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+10-K
+1
+asci123102_10k.htm
+ANNUAL REPORT FORM 10-K 12/31/02
+DECEMBER 31, 2002 Form 10-K 
+================================================================================
+UNITED STATES
+SECURITIES AND EXCHANGE COMMISSION
+Washington, D.C. 20549
+FORM 10-K
+[ x ] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
+Act of 1934
+For the fiscal year ended December 31, 2002
+or
+[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
+Exchange Act of 1934.
+Commission file number 001-31539
+ST. MARY LAND & EXPLORATION COMPANY
+(Exact name of registrant as specified in its charter)
+Delaware 41-0518430
+(State or other jurisdiction (I.R.S. Employer Identification No.)
+of incorporation or organization)
+1776 Lincoln Street, Suite 700, Denver, Colorado 80203
+------------------------------------------------------
+(Address of principal executive offices) (Zip Code)
+(303) 861-8140
+(Registrant's telephone number, including area code)
+Securities registered pursuant to Section 12(b)of the Act:
+Title of each class Name of each exchange
+on which registered
+Common Stock, $.01 par value New York Stock Exchange
+---------------------------- -----------------------
+Securities registered pursuant to Section 12(g)of the Act:
+None
+Indicate by check mark whether the registrant (1) has filed all reports required
+to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
+the preceding 12 months (or for such shorter period that the registrant was
+required to file such reports), and (2) has been subject to such filing
+requirements for the past 90 days. Yes [ x ] No [ ]
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
+of Regulation S-K is not contained herein, and will not be contained, to the
+best of registrant's knowledge, in definitive proxy or information statements
+incorporated by reference in Part III of this Form 10-K or any amendment to this
+Form 10-K. [ ]
+Indicate by check mark whether the registrant is an accelerated filer (as
+defined in Rule 12-6-2 of the Act). Yes [ x ] No [ ]
+The aggregate market value of 27,152,051 shares of voting stock held by
+non-affiliates of the registrant, based upon the closing sale price of the
+common stock on June 28, 2002, the last business day of the registrant's most
+recently completed second fiscal quarter, of $24.06 per share as reported on the
+Nasdaq National Market System, on which St. Mary's common stock was traded at
+the time, was $653,278,347. Shares of common stock held by each director and
+executive officer and by each person who owns 10% or more of the outstanding
+common stock or who is otherwise believed by the Company to be in a control
+position have been excluded. This determination of affiliate status is not
+necessarily a conclusive determination for other purposes.
+As of March 3, 2003, the registrant had 31,433,900 shares of common
+stock outstanding.
+DOCUMENTS INCORPORATED BY REFERENCE
+The information required by Items 10, 11, 12 and 13 of Part III is incorporated
+by reference from portions of the registrant's definitive proxy statement
+relating to its 2003 annual meeting of stockholders to be filed within 120 days
+from December 31, 2002.
+================================================================================
+TABLE OF CONTENTS
+-----------------
+ITEM PAGE
+---- ----
+PART I
+ITEM 1. BUSINESS.............................................................1
+Background.......................................................1
+Business Strategy................................................2
+Significant Developments Since December 31, 2001.................3
+Major Customers..................................................4
+Employees and Office Space.......................................5
+Title to Properties..............................................5
+Competition......................................................5
+Government Regulations...........................................5
+Risk Factors....................................................10
+Cautionary Statement about Forward-Looking Statements...........20
+Available Information...........................................21
+Glossary........................................................21
+ITEM 2. PROPERTIES..........................................................23
+Operations......................................................23
+Acquisitions....................................................28
+Reserves........................................................28
+Production......................................................29
+Productive Wells................................................30
+Drilling Activity...............................................30
+Acreage.........................................................31
+ITEM 3. LEGAL PROCEEDINGS...................................................32
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................32
+ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT................................33
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
+RELATED STOCKHOLDER MATTERS.........................................34
+ITEM 6. SELECTED FINANCIAL DATA.............................................36
+i
+TABLE OF CONTENTS
+-----------------
+(Continued)
+ITEM PAGE
+---- ----
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
+CONDITION AND RESULTS OF OPERATIONS.................................38
+Overview........................................................38
+Critical Accounting Policies and Estimates......................38
+Results of Operations...........................................41
+Liquidity and Capital Resources.................................46
+Accounting Matters..............................................53
+Effects of Inflation and Changing Prices........................54
+Environmental...................................................55
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
+MARKET RISK.........................................................55
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.........................56
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
+ACCOUNTING AND FINANCIAL DISCLOSURE.................................56
+PART III
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..................56
+ITEM 11. EXECUTIVE COMPENSATION..............................................57
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
+AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS......................57
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS......................57
+ITEM 14. CONTROLS AND PROCEDURES.............................................57
+PART IV
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
+REPORTS ON FORM 8-K.................................................58
+ii
+PART I
+When we use the terms "St. Mary," "we," "us" or "our," we are referring to St.
+Mary Land & Exploration Company and its subsidiaries, unless the context
+otherwise requires. We have included technical terms important to an
+understanding of our business under "Glossary". Throughout this document we make
+statements that are classified as "forward-looking". Please refer to the
+"Cautionary Statement about Forward-Looking Statements" section of this document
+for an explanation of these types of assertions.
+ITEM 1. BUSINESS
+Background
+St. Mary Land & Exploration Company is an independent energy
+company engaged in the exploration, development, acquisition and production of
+natural gas and crude oil. St. Mary was founded in 1908 and incorporated in
+Delaware in 1915. Our operations are focused in the following five core
+operating areas in the United States:
+o the Mid-Continent region in Oklahoma and northern Texas;
+o the ArkLaTex region that spans northern Louisiana and portions
+of Arkansas, Mississippi and eastern Texas;
+o the onshore Gulf Coast and offshore Gulf of Mexico;
+o the Rocky Mountain region consisting of the Williston Basin in
+eastern Montana and western North Dakota and the Powder River,
+Green River and Wind River Basins in Wyoming; and
+o the Permian Basin in eastern New Mexico and western Texas.
+As of December 31, 2002, we had estimated proved reserves of
+approximately 36.1 MMBbls of oil and 274.2 Bcf of natural gas, or a total of
+490.9 BCFE, 88% of which were proved developed and 56% of which were natural
+gas, with a PV-10 value of $824.8 million. For the year ended December 31, 2002,
+we produced 55.1 BCFE representing average daily production of 150.8 MMCFE per
+day.
+We focus our resources in selected domestic basins where we believe
+that our expertise in geology, geophysics and drilling and completion techniques
+provides us with competitive advantages. We have assembled a balanced program of
+low-to-medium-risk development and exploitation projects to provide the
+foundation for steady growth. In addition, we have a portfolio of
+higher-potential exploration projects and non-conventional gas plays in the
+Rocky Mountain region that we believe could significantly increase our reserves
+and production. We measure and rank our investment decisions based on their
+risk-adjusted impact on per share net asset value. In the past, we have sold
+selected assets when we believed attractive prices were available, and we will
+continue to evaluate such opportunities in the future.
+We seek to develop our existing property base and acquire acreage with
+additional potential in our core areas. From January 1, 2000, through December
+31, 2002, we participated in the drilling or recompletion of 623 gross wells
+with an average success rate of 82%. During that same period we added estimated
+1
+proved reserves of 347 BCFE at an average finding cost of $1.44 per MCFE. Our
+average annual production replacement was 214% during this three-year period,
+and our production has grown at an average rate of 21% per year over the same
+time period.
+As of December 31, 2002, we had an acreage position of 1,145,507 gross
+(542,736 net) acres of which 504,873 gross (325,290 net) acres were undeveloped.
+For 2003 we have budgeted capital expenditures of $135 million for ongoing
+development, exploitation and exploration programs in our core operating areas
+and $90 million for acquisitions of oil and gas properties.
+Our principal offices are located at 1776 Lincoln Street, Suite 700,
+Denver, Colorado 80203, and our telephone number is (303) 861-8140.
+Business Strategy
+Our objective is to build stockholder value through consistent economic
+growth in reserves and production that increase net asset value per share, cash
+flow per share and earnings per share. The principal elements of our strategy
+are as follows:
+o Maintain Focused Geographic Operations. We focus on
+exploration, development and acquisition activities in five
+core operating areas where we have built a balanced portfolio
+of proved reserves, development drilling opportunities and
+higher-potential exploration and non-conventional gas
+prospects. We believe that our leasehold position is a
+strategic asset. Our senior technical managers, each
+possessing over 20 years of experience, head up regional
+technical offices supported by centralized administration in
+our Denver office. We believe that our long-standing presence,
+our established networks of local industry relationships and
+our acreage holdings in our core operating areas provide us
+with a competitive advantage. In addition, we believe that we
+can continue to expand our operations without the need to
+proportionately increase the number of employees.
+o Continue Exploitation and Development of Existing Properties.
+We use our comprehensive base of geological, geophysical,
+engineering and production experience in each of our core
+operating areas to source prospects for our ongoing
+low-to-medium-risk development and exploitation programs. We
+conduct detailed geologic studies and use an array of
+technologies and tools including 2-D and 3-D seismic imaging,
+hydraulic fracturing and reservoir stimulation techniques, and
+specialized logging tools to enhance the potential of our
+existing properties. In 2002 we participated in the drilling
+or recompletion of 168 gross wells with a 79% success rate.
+o Pursue Higher-Risk Higher-Potential Exploration Projects. We
+have allocated approximately 7% of our 2003 drilling and
+exploration capital expenditures budget to higher-potential
+exploration and unconventional gas projects. Our strategy is
+to test several of these prospects each year that in total
+have the potential to significantly increase our reserves. We
+seek to invest in a diversified mix of projects and generally
+limit our capital exposure by participating with other
+experienced industry partners. We plan to test projects in the
+Mid-Continent region and Rocky Mountain area during 2003.
+o Make Selective Acquisitions. We seek to make selective niche
+acquisitions of oil and gas properties that complement our
+existing operations, offer economies of scale and provide
+2
+further development, exploitation and exploration
+opportunities based on proprietary geologic concepts. We
+believe that the focus on smaller, negotiated transactions
+where we have specialized geologic knowledge or operating
+experience has enabled us to acquire attractively priced and
+under-exploited properties. In addition, we will pursue
+corporate acquisitions that we believe will be accretive.
+Examples of this type of acquisition include our 1999 Nance
+Petroleum Corporation and King Ranch Energy, Inc.
+acquisitions, both of which were acquired with our common
+stock. We have budgeted $90.0 million for acquisitions in
+2003, of which $74.0 million closed in January 2003, including
+the acquisition of properties from Flying J Oil & Gas Inc.
+and Big West Oil & Gas Inc. in exchange for the issuance
+of 3,380,818 restricted shares of St. Mary common stock.
+o Control Operations. We believe it is important to control
+geologic and operational decisions as well as the timing of
+those decisions. At December 31, 2002, we operated 31% of our
+properties on a volume basis and 66% on a PV-10 value basis.
+We are the operator of properties representing approximately
+81% of our 2003 capital budget.
+o Maintain Financial Flexibility. Conservative use of financial
+leverage has long been a critical element of our strategy. We
+believe that maintaining a strong balance sheet is a
+significant competitive advantage that enables us to pursue
+acquisition and other opportunities, especially in weaker
+price environments. It also provides us with the financial
+resources to weather periods of volatile commodity prices or
+escalating costs.
+Significant Developments Since December 31, 2001
+o 2002 Acquisitions of Oil and Gas Properties. In December 2002
+St. Mary completed a $69.5 million acquisition of properties
+in the Williston Basin from Burlington Resources Oil & Gas
+Company LP. The properties are located in Montana and North
+Dakota and produce approximately 3,100 barrels of oil and
+3,300 Mcf of gas per day. Smaller acquisitions during 2002
+included the $7.5 million Mid-Continent acquisition from
+Merchant Resources LP, the $4.9 million acquisition in the
+Huxley Field located in east Texas and $5.8 million in various
+other properties. We used cash from our March 2002 senior
+convertible note placement and borrowings under our bank
+credit facility to fund these acquisitions.
+o 2003 Acquisition of Oil and Gas Properties. In January 2003
+St. Mary issued 3,380,818 shares of its restricted common
+stock valued at $71.6 million to acquire Rocky Mountain
+properties from Flying J Oil & Gas Inc. and Big West Oil
+& Gas Inc. This acquisition included properties located in
+the Williston, Powder River and Green River Basins with 66.9
+BCFE of proved reserves and production of approximately 2,100
+barrels of oil and 8,200 Mcf of gas per day. We also received
+a net amount of $2.8 million in cash for normal purchase price
+adjustments. In addition, St. Mary made a non-recourse loan to
+Flying J and Big West of $71.6 million at LIBOR plus 2% for up
+to a 39-month period. The loan is secured by a pledge of the
+shares of St. Mary stock issued to Flying J and Big West. The
+loan was funded through borrowings under our bank credit
+facility.
+3
+o Increase in 2002 Year-End Reserves. Proved reserves increased
+28% from December 31, 2001 to 490.9 BCFE as of December 31,
+2002. We added 101.6 BCFE through acquisitions for cash and
+40.3 BCFE from drilling activities. There were net upward
+revisions of previous reserves totaling 26.4 BCFE. This upward
+revision was the result of a 33.9 BCFE increase from price
+revisions, which was partially offset by 7.5 BCFE in negative
+performance revisions.
+o New York Stock Exchange Listing. On November 20, 2002 St. Mary
+Land & Exploration Company's common stock began trading on
+the New York Stock Exchange. The Company believes the NYSE
+will improve visibility with investors and the auction market
+structure will help reduce intra-day volatility and increase
+the liquidity in St. Mary's stock. Prior to November 20, 2002
+St. Mary's common stock was traded on the Nasdaq National
+Market System.
+o Senior Convertible Notes. In March 2002 we issued in a private
+placement a total of $100.0 million of our 5.75% senior
+convertible notes due 2022 with a1/2% contingent interest
+provision. We received net proceeds of $96.7 million after
+deducting the initial purchasers' discount and offering
+expenses paid by us. The notes are general unsecured
+obligations and rank on a parity in right of payment with all
+our existing and future senior indebtedness and other general
+unsecured obligations. They are senior in right of payment to
+all our future subordinated indebtedness. The notes are
+convertible into our common stock at a conversion price of
+$26.00 per share, subject to adjustment. We can redeem the
+notes with cash in whole or in part at a repurchase price of
+100% of the principal amount plus accrued and unpaid interest
+beginning on March 20, 2007. The note holders have the option
+of requiring us to repurchase the notes for cash at 100% of
+the principal amount plus accrued and unpaid interest
+(including contingent interest) upon (1) a change in control
+of St. Mary or (2) on March 20, 2007, March 15, 2012 and March
+15, 2017. On March 20, 2007, we may pay the repurchase price
+with cash, shares of our common stock or any combination of
+cash and our common stock. We are not restricted from paying
+dividends, incurring debt, or issuing or repurchasing our
+securities under the indenture for the notes. There are no
+financial covenants in the indenture. We used a portion of the
+net proceeds from the notes to repay our credit facility
+balance and used the remaining net proceeds to fund a portion
+of our 2002 capital expenditures.
+o Revolving Credit Agreement. In January 2003 we entered into a
+new long-term revolving credit agreement with nine banks. The
+maximum loan amount is $300 million with a calculated
+borrowing base of $250 million. We have reduced the commitment
+amount to $150 million to meet our projected needs. The
+maturity date is January 27, 2006. Interest is accrued based
+on the borrowing base utilization and is currently LIBOR plus
+1.25%.
+Major Customers
+During 2002 there were no sales to individual customers that accounted
+for more than 10% of our total oil and gas production revenue. During 2001 sales
+to Transok Gas Company accounted for 12.0% and sales to BP Amoco accounted for
+11.3% of our total oil and gas production revenue. During 2000 sales to BP Amoco
+accounted for 22.3% of our total oil and gas production revenue.
+4
+Employees and Office Space
+As of December 31, 2002, St. Mary had 185 full-time employees. None of
+our employees are subject to a collective bargaining agreement. We consider our
+relations with our employees to be good. We lease approximately 42,660 square
+feet of office space in Denver, Colorado for our executive and administrative
+offices, of which 9,479 square feet is subleased. We also lease approximately
+14,990 square feet of office space in Tulsa, Oklahoma; approximately 11,740
+square feet in Shreveport, Louisiana; approximately 7,500 square feet in
+Lafayette, Louisiana; and approximately 15,830 square feet in Billings, Montana.
+Title to Properties
+Substantially all of our working interests are held pursuant to leases
+from third parties. A title opinion is usually obtained prior to the
+commencement of drilling operations on properties. We have obtained title
+opinions or conducted a thorough title review on substantially all of our
+producing properties and believe that we have satisfactory title to such
+properties in accordance with standards generally accepted in the oil and gas
+industry. Our properties are subject to a mortgage under our credit facility,
+customary royalty interests, liens for current taxes, and other burdens that we
+believe do not materially interfere with the use of or affect the value of such
+properties. We perform only a minimal title investigation before acquiring
+undeveloped properties.
+Competition
+The oil and gas industry is intensely competitive. Competition is
+particularly intense in the acquisition of prospective oil and natural gas
+properties and oil and gas reserves. Our competitive position depends on our
+geological, geophysical and engineering expertise, our financial resources, and
+our ability to select, acquire and develop proved reserves. We believe that the
+locations of our leasehold acreage, our exploration, drilling and production
+capabilities and the experience of our management and that of our industry
+partners generally enable us to compete effectively in our core operating areas.
+However, we compete with a substantial number of major and independent oil and
+gas companies that have larger technical staffs and greater financial and
+operational resources than we do. Many of these companies not only engage in the
+acquisition, exploration, development and production of oil and natural gas
+reserves, but also have refining operations, market refined products and
+generate electricity. We also compete with other oil and natural gas companies
+in attempting to secure drilling rigs and other equipment necessary for drilling
+and completion of wells. Drilling equipment may be in short supply from time to
+time.
+Government Regulations
+Our business is subject to various federal, state and local laws and
+governmental regulations that may be changed from time to time in response to
+economic or political conditions. Matters subject to regulation include
+discharge permits for drilling operations, drilling bonds, reports concerning
+operations, the spacing of wells, unitization and pooling of properties,
+taxation and environmental protection. From time to time, regulatory agencies
+have imposed price controls and limitations on production by restricting the
+rate of flow of oil and gas wells below actual production capacity in order to
+conserve supplies of oil and gas.
+St. Mary's operations could result in liability for personal injuries,
+property damage, oil spills, discharge of hazardous materials, remediation and
+clean-up costs and other environmental damages. We could be liable for
+environmental damages caused by previous property owners. As a result,
+substantial liabilities to third parties or governmental entities may be
+5
+incurred, and the payment of such liabilities could have a material adverse
+effect on our financial condition and results of operations. We maintain
+insurance coverage for our operations, including limited coverage for sudden
+environmental damages, but we do not believe that insurance coverage for
+environmental damage that occurs over time is available at a reasonable cost.
+Moreover, we do not believe that insurance coverage for the full potential
+liability that could be caused by sudden environmental damages is available at a
+reasonable cost. Accordingly, we may be subject to liability or may lose
+substantial portions of our properties in the event of certain environmental
+damages. St. Mary could incur substantial costs to comply with environmental
+laws and regulations.
+Energy Regulations. With respect to federal energy regulation, the
+transportation and sale for resale of natural gas in interstate commerce have
+historically been regulated pursuant to several laws enacted by Congress and
+regulations promulgated under these laws by the Federal Energy Regulatory
+Commission and its predecessor. In the past the federal government has regulated
+the prices at which gas could be sold. Congress removed all price and non-price
+controls affecting wellhead sales of natural gas effective January 1, 1993.
+However, Congress could reenact price controls in the future.
+Our sales of natural gas are affected by the availability, terms and
+cost of transportation. The price and terms of access to pipeline transportation
+are subject to extensive federal and state regulation. From 1985 to the present,
+several major regulatory changes have been implemented by Congress and the FERC
+that affect the economics of natural gas production, transportation and sales.
+In addition, the FERC is continually proposing and implementing new rules and
+regulations affecting those segments of the natural gas industry that remain
+subject to the FERC's jurisdiction, most notably interstate natural gas
+transmission companies. These initiatives may also affect the intrastate
+transportation of gas under certain circumstances. The stated purpose of many of
+these regulatory changes is to promote competition among the various sectors of
+the natural gas industry, and these initiatives generally reflect more
+light-handed regulation.
+The ultimate impact of the complex rules and regulations issued by the
+FERC since 1985 cannot be predicted. In addition, many aspects of these
+regulatory developments have not become final but are still pending judicial and
+final FERC decisions. We cannot predict what further action the FERC will take
+on these matters. Some of the FERC's more recent proposals may, however,
+adversely affect the availability and reliability of interruptible
+transportation service on interstate pipelines. Additional proposals and
+proceedings that might affect the natural gas industry are pending before
+Congress and the courts. The natural gas industry historically has been very
+heavily regulated; therefore, there is no assurance that the less stringent
+regulatory approach recently pursued by the FERC and Congress will continue. We
+do not believe that we will be affected by any action taken that differs
+materially from other natural gas producers and marketers with whom we compete.
+Our sales of crude oil, condensate and natural gas liquids are
+currently not regulated and are made at market prices. However, in a number of
+instances the ability to transport and sell such products are dependent on
+pipelines whose rates, terms and conditions of service are subject to FERC
+jurisdiction under the Interstate Commerce Act. Certain regulations implemented
+by the FERC in recent years could result in an increase in the cost of
+transportation service on certain petroleum product pipelines. We do not believe
+that these regulations affect us any differently than other producers of these
+products.
+Certain operations we conduct are on federal oil and gas leases that
+the Minerals Management Service administers. The MMS issues such leases through
+6
+competitive bidding. These leases contain relatively standardized terms and
+require compliance with detailed MMS regulations and, for offshore leases,
+orders pursuant to the Outer Continental Shelf Lands Act, which are subject to
+change by the MMS. For offshore operations, lessees must obtain MMS approval for
+exploration plans and development and production plans prior to the commencement
+of such operations. In addition to permits required from other agencies such as
+the Coast Guard, the Army Corps of Engineers and the Environmental Protection
+Agency, lessees must obtain a permit from the MMS prior to the commencement of
+drilling. Lessees must also comply with detailed MMS regulations governing,
+among other things:
+o engineering and construction specifications for offshore
+production facilities;
+o safety procedures;
+o flaring of production;
+o plugging and abandonment of Outer Continental Shelf or OCS
+wells;
+o calculation of royalty payments and the valuation of
+production for this purpose; and
+o removal of facilities.
+To cover the various obligations of lessees on the OCS, the MMS
+generally requires that lessees post substantial bonds or other acceptable
+assurances that such obligations will be met. The cost of such bonds or other
+surety can be substantial, and we cannot assure that we can continue to obtain
+bonds or other surety in all cases. Under certain circumstances the MMS may
+require our operations on federal leases to be suspended or terminated.
+Many of the states in which we conduct our oil and gas drilling and
+production activities regulate such activities by requiring, among other things,
+drilling permits and bonds and reports concerning operations. The laws of these
+states also govern a number of environmental and conservation matters, including
+the handling and disposing of waste material, plugging and abandonment of wells,
+restoration requirements, unitization and pooling of natural gas and oil
+properties and establishment of maximum rates of production from natural gas and
+oil wells. Some states prorate production to the market demand for oil and
+natural gas.
+Environmental Regulations. Our operations are subject to numerous laws
+and regulations governing the discharge of materials into the environment or
+otherwise relating to environmental protection. These laws and regulations may
+require the acquisition of a permit before drilling commences, restrict the
+types, quantities and concentration of various substances that can be released
+into the environment in connection with drilling and production activities,
+limit or prohibit drilling activities on certain lands lying within wilderness,
+wetlands and other protected areas, and impose substantial liabilities for any
+pollution resulting from our operations.
+Public interest in the protection of the environment has increased
+dramatically in recent years. Onshore and offshore drilling in some areas has
+been opposed by environmental groups and, in some areas, has been restricted.
+Legislation has also been proposed in Congress from time to time that would
+reclassify certain oil and gas exploration and production wastes as "hazardous
+wastes," which would make the reclassified wastes subject to much more stringent
+handling, disposal and clean-up requirements. To the extent laws are enacted or
+other governmental actions are taken that prohibit or restrict offshore drilling
+7
+or impose environmental protection requirements that result in increased costs
+to the natural gas and oil industry (both onshore and offshore), our business
+and prospects could be adversely affected. We believe that we are in substantial
+compliance with current applicable environmental laws and regulations and that
+continued compliance with existing requirements would not have a material
+adverse impact on us.
+Violation of environmental laws and regulations can lead to the
+imposition of administrative, civil or criminal penalties; remedial obligations;
+and in some instances injunctive relief. In addition, violations of
+environmental laws or the discharge of hazardous materials or oil could result
+in liability for personal injuries, property damage, remediation and cleanup
+costs, and other environmental damages. As a result, substantial liabilities to
+third parties or governmental entities may be incurred, and the payment of such
+liabilities could have a material adverse effect on our financial condition and
+results of operations.
+The Oil Pollution Act and regulations thereunder impose a variety of
+regulations on "responsible parties" related to the prevention of oil spills and
+liability for damages resulting from such spills in United States waters. A
+"responsible party" includes the owner or operator of an onshore facility,
+pipeline or vessel, or the lessee or permittee of the area in which an offshore
+facility is located. The OPA assigns liability to each responsible party for oil
+cleanup costs and a variety of public and private damages. While liability
+limits apply in some circumstances, a party cannot take advantage of liability
+limits if the spill was caused by gross negligence or willful misconduct or
+resulted from violation of a federal safety, construction or operating
+regulation. Likewise, if the party fails to report a spill or to cooperate fully
+in the cleanup, liability limits do not apply. Even if applicable, the liability
+limits for offshore facilities require the responsible party to pay all removal
+costs, plus up to $75 million in other damages. Few defenses exist to the
+liability imposed by the OPA.
+The OPA imposes ongoing requirements on a responsible party, including
+the preparation of oil spill response plans and proof of financial
+responsibility to cover environmental cleanup and restoration costs that could
+be incurred in connection with an oil spill. As amended by the Coast Guard
+Authorization Act of 1996, the OPA requires responsible parties for covered
+offshore facilities that have a worst case oil spill of more than 1,000 barrels
+to demonstrate financial responsibility in amounts ranging from at least $10
+million in specified state waters to at least $35 million in federal outer
+continental shelf waters, with higher amounts of up to $150 million if a formal
+risk assessment indicates that a higher amount should be required based on
+specific risks posed by the operations or if the worst case oil spill discharge
+volume possible at the facility may exceed the applicable threshold volumes
+specified under the final rule of the MMS implementing these financial
+responsibility requirements as enacted in August 1998. We do not anticipate that
+we will experience any difficulty in continuing to satisfy the MMS requirements
+for demonstrating financial responsibility under the OPA.
+The Federal Water Pollution Control Act, also known as the Clean Water
+Act, imposes restrictions and strict controls regarding the discharge of
+produced waters and other oil and gas wastes into navigable waters. Permits must
+be obtained to discharge pollutants into waters and to conduct construction
+activities in waters and wetlands. The FWPCA and similar state laws provide for
+civil, criminal and administrative penalties for any unauthorized discharges of
+pollutants and unauthorized discharges of reportable quantities of oil and other
+hazardous substances. Many state discharge regulations and the general permits
+from the Federal National Pollutant Discharge Elimination System prohibit the
+discharge of produced water and sand, drilling fluids, drill cuttings and
+certain other substances related to the oil and gas industry into coastal
+waters. Although the costs to comply with zero discharge mandates under federal
+or state law may be significant, the entire industry is expected to experience
+similar costs, and we believe that these costs will not have a material adverse
+8
+impact on our results of operations or financial position. The United States
+Environmental Protection Agency has adopted regulations requiring certain oil
+and gas exploration and production facilities to obtain permits for storm water
+discharges. Costs may be associated with the treatment of wastewater or
+developing and implementing storm water pollution prevention plans.
+The Comprehensive Environmental Response, Compensation, and Liability
+Act, also known as the "Superfund" law, imposes liability, without regard to
+fault or the legality of the original conduct, on certain classes of persons
+that are considered to be responsible for the release of a "hazardous substance"
+into the environment. These persons, including the owner or operator of the
+disposal site or sites where the release occurred and companies that transported
+or disposed or arranged for the transport or disposal of the hazardous
+substances under CERCLA, may be subject to joint and several liability for the
+costs of cleaning up the hazardous substances that have been released into the
+environment and for damages to natural resources. It is not uncommon for
+neighboring landowners and other third parties to file claims for personal
+injury and property damage allegedly caused by the hazardous substances released
+into the environment.
+We generate both hazardous and nonhazardous solid wastes which are
+subject to requirements of the Federal Resource Conservation and Recovery Act
+and comparable state statutes. From time to time, the EPA has considered making
+changes in nonhazardous waste standards that would result in stricter disposal
+requirements for these wastes. Furthermore, it is possible that some wastes that
+we generate that are currently classified as nonhazardous may be in the future
+be designated as "hazardous wastes," resulting in the wastes being subject to
+more rigorous and costly disposal requirements. Changes in applicable
+regulations may result in an increase in our capital expenditures or operating
+expenses.
+We currently own or lease, and have in the past owned or leased,
+onshore properties that for many years have been utilized for or associated with
+the exploration and production of oil and gas. Although we have utilized
+operating and disposal practices that were standard in the industry at the time,
+hydrocarbons or other wastes may have been disposed of or released on or under
+the properties owned or leased by us or on or under other locations where such
+wastes have been taken for disposal. These properties and the wastes disposed
+thereon may be subject to CERCLA, RCRA and analogous state laws. Under such
+laws, we could be required to remove or remediate previously disposed wastes
+(including waste disposed of or released by prior owners or operators) or
+property contamination (including groundwater contamination by prior owners or
+operators), or to perform remedial plugging or closure operations to prevent
+future contamination.
+Our operations are also subject to the Federal Clean Air Act and
+comparable state statutes. Amendments to the Clean Air Act adopted in 1990
+contain provisions that may result in the imposition of increasingly stringent
+pollution control requirements with respect to air emissions from the operations
+of stationary and mobile source equipment. Such air pollution control
+requirements may include specific equipment or technologies, permits with
+emissions and operational limitations, pre-approval of new or modified projects
+or facilities producing air emissions, and similar measures. Failure to comply
+with applicable air statutes or regulations may lead to the assessment of
+administrative, civil or criminal penalties, and/or result in the limitation or
+cessation of construction or operation of certain air emission sources.
+9
+Risk Factors
+Risks Related to Our Business
+In addition to the other information set forth elsewhere in this Form
+10-K, the following factors should be carefully considered when evaluating St.
+Mary.
+Oil and natural gas prices are volatile, and an extended decline in prices would
+hurt our profitability and financial condition.
+Our revenues, operating results, profitability, future rate of growth
+and the carrying value of our oil and gas properties depend heavily on
+prevailing market prices for oil and gas. We expect the markets for oil and gas
+to continue to be volatile. Any substantial or extended decline in the price of
+oil or gas would have a material adverse effect on our financial condition and
+results of operations. It could reduce our cash flow and borrowing capacity, as
+well as the value and the amount of our oil and gas reserves. Lower prices may
+also reduce the amount of oil and gas that we can economically produce.
+Historically, the markets for oil and gas have been volatile, and they
+are likely to continue to be volatile. Wide fluctuations in oil and gas prices
+may result from relatively minor changes in the supply of and demand for oil and
+gas, market uncertainty and other factors that are beyond our control,
+including:
+o worldwide and domestic supplies of oil and natural gas;
+o the ability of the members of the Organization of Petroleum
+Exporting Countries to agree to and maintain oil price and
+production controls;
+o political instability or armed conflict in oil or gas
+producing regions;
+o the price and level of foreign imports;
+o worldwide economic conditions;
+o marketability of production;
+o the level of consumer demand;
+o the price, availability and acceptance of alternative fuels;
+o the availability of pipeline capacity;
+o weather conditions; and
+o actions of federal, state, local and foreign authorities.
+These external factors and the volatile nature of the energy markets
+make it difficult to estimate future prices of oil and natural gas. Declines in
+oil and gas prices would reduce our revenue and could also reduce the amount of
+oil and gas that we can produce economically and, as a result, could have a
+material adverse effect on our financial condition, results of operations and
+reserves. Further, oil and gas prices do not necessarily move in tandem. Because
+10
+approximately 56% of our proved reserves were natural gas reserves as of
+December 31, 2002, our financial results are slightly more affected by changes
+in natural gas prices.
+A material portion of our production, revenues and cash flows are derived from
+one field.
+Production from the Judge Digby Field accounted for approximately 10%
+of our total oil and gas production volumes during 2002. If the level of
+production from this field substantially declines other than through normal
+depletion over the expected reserve life, it could have a material adverse
+impact on our overall production levels and our revenues.
+Our future success depends on our ability to replace reserves that we produce.
+Our future success depends on our ability to find, develop and acquire
+oil and gas reserves that are economically recoverable. As of December 31, 2002
+our proved reserves would last approximately 8.9 years if produced constantly at
+the 2002 rate of production. In order to maintain current production rates we
+must locate and develop or acquire new oil and gas reserves to replace those
+being depleted by production. We may do this even during periods of low oil and
+gas prices. Without successful exploration or acquisition activities, our
+reserves, production and revenues will decline rapidly. In addition,
+approximately 12% of our total estimated proved reserves at December 31, 2002,
+were undeveloped. By their nature, undeveloped reserves are less certain.
+Recovery of such reserves will require significant capital expenditures and
+successful drilling operations. We cannot assure you that we will be able to
+find and develop or acquire additional reserves at an acceptable cost.
+Our producing property acquisitions carry significant risks.
+Our recent growth is due in part to, and our growth strategy relies in
+part on, acquisitions of producing properties and exploration and production
+companies. Successful acquisitions require an assessment of a number of factors
+beyond our control. These factors include recoverable reserves, future oil and
+gas prices, operating costs and potential environmental and other liabilities.
+These assessments are inexact and their accuracy is inherently uncertain. In
+connection with these assessments, we perform a review of the subject properties
+that we believe is generally consistent with industry practices. However, such a
+review will not reveal all existing or potential problems. In addition, our
+review may not permit us to become sufficiently familiar with the properties to
+fully assess their deficiencies and capabilities. We do not inspect every well.
+Even when we do inspect a well, we may not always discover structural,
+subsurface or environmental problems that may exist or arise.
+In connection with our acquisitions, we may not be entitled to
+contractual indemnification for preclosing liabilities, including environmental
+liabilities. Normally, we acquire interests in properties on an "as is" basis
+with limited remedies for breaches of representations and warranties. In
+addition, competition for producing oil and gas properties is intense and many
+of our competitors have financial and other resources substantially greater than
+those available to us. Therefore, we cannot assure you that we will be able to
+acquire oil and gas properties that contain economically recoverable reserves or
+that we will acquire such properties at acceptable prices.
+Additionally, significant acquisitions can change the nature of our
+operations and business depending upon the character of the acquired properties,
+which may have substantially different operating and geological characteristics
+or be in different geographic locations than our existing properties. While it
+11
+is our current intention to continue to concentrate on acquiring properties with
+development, exploitation and exploration potential located in our five core
+operating areas, we cannot assure you that in the future we will not decide to
+pursue acquisitions of properties located in other geographic regions. To the
+extent that such acquired properties are substantially different than our
+existing properties, our ability to efficiently realize the expected economic
+benefits of such transactions may be limited.
+We may not be able to successfully integrate future property or corporate
+acquisitions.
+We seek to make selective niche acquisitions of oil and gas properties,
+and we will pursue corporate acquisitions that we believe will be accretive.
+However, integrating acquired properties and businesses involves a number of
+special risks. These risks include the possibility that management may be
+distracted from normal business concerns by the need to integrate operations and
+systems and in retaining and assimilating additional employees. Any of these or
+other similar risks could lead to potentially adverse short-term or long-term
+effects on our operating results. We cannot assure you that we will be able to
+obtain adequate funds for future property or corporate acquisitions,
+successfully integrate our future property or corporate acquisitions or that we
+will realize any of the anticipated benefits of the acquisitions.
+Substantial capital is required to replace and grow reserves.
+We make, and will continue to make, substantial expenditures to find,
+acquire, develop and produce oil and natural gas reserves. Our capital
+expenditures for oil and gas properties were $193.0 million for 2002 and $182.9
+million during 2001. We have budgeted total capital expenditures of $225.0
+million in 2003. With the cash provided by operating activities and borrowings
+under our credit facility, we believe we will have sufficient cash to fund
+budgeted capital expenditures in 2003. If additional development or attractive
+acquisition opportunities arise, we may consider other forms of financing,
+including the public offering or private placement of equity or debt securities.
+However, if oil and gas prices decrease or we encounter operating difficulties
+that result in our cash flow from operations being less than expected, we may
+have to reduce the capital we can spend in future years unless we raise
+additional funds through debt or equity financing. We cannot assure you that
+debt or equity financing, cash generated by operations or borrowing capacity
+will be available to us on acceptable terms to meet these requirements.
+Future cash flows and the availability of financing will be subject to
+a number of variables, such as:
+o our success in locating and producing new reserves;
+o the level of production from existing wells;
+o prices of oil and natural gas;
+o lease operating expense, including workovers and taxes; and
+o administrative expense.
+Issuing equity securities to satisfy our financing requirements could
+cause substantial dilution to existing stockholders. Debt financing could lead
+to:
+12
+o a substantial portion of our operating cash flow being
+dedicated to the payment of principal and interest;
+o us being more vulnerable to competitive pressures and economic
+downturns; and
+o restrictions on our operations.
+If our revenues were to decrease due to lower oil and natural gas
+prices, decreased production or other reasons, and if we could not obtain
+capital through our credit facility or otherwise, our ability to execute our
+development plans, replace our reserves or maintain production levels could be
+greatly limited.
+We may not obtain a bank credit facility borrowing base redetermination that
+adequately meets our anticipated financing needs.
+We closed a new long-term revolving credit facility in January 2003
+with a 9-bank group led by Wachovia Bank. Under the facility, the maximum loan
+amount is $300.0 million. The amount actually available from time to time
+depends on a borrowing base that the lenders periodically redetermine based on
+the value of our oil and gas properties and other assets. The stated total
+borrowing base is $215.0 million and will be increased to $250.0 million after
+sufficient mortgage collateral has been provided to the banks. Since we pay
+commitment fees based on the unused portion of the borrowing base, we have
+reduced the commitment that we have accepted under the borrowing base to $150.0
+million to correspond with our projected funding requirements.
+Our next borrowing base redetermination date is scheduled to occur on
+or about April 15, 2003. We cannot assure you that the banks will agree to a
+borrowing base redetermination that is adequate for our anticipated financing
+needs.
+If oil and gas prices decrease or exploration efforts are unsuccessful, we may
+be required to take additional writedowns.
+There is a risk that we will be required to write down the carrying
+value of our oil and gas properties. This could occur when oil and gas prices
+are low or if we have substantial downward adjustments to our estimated proved
+reserves, increases in our estimates of development costs or deterioration in
+our exploration results.
+We follow the successful efforts accounting method. All property
+acquisition costs and costs of exploratory and development wells are capitalized
+when incurred, pending the determination of whether proved reserves have been
+discovered. If proved reserves are not discovered with an exploratory well, the
+costs of drilling the well are expensed. All geological and geophysical costs on
+exploratory prospects are expensed as incurred. The capitalized costs of our oil
+and gas properties, on a field-by-field basis, may not exceed the estimated
+future net cash flows of that field. If capitalized costs exceed future net
+revenues we write down the costs of each such field to our estimate of fair
+market value. Unproved properties are evaluated at the lower of cost or fair
+market value. This type of charge will not affect our cash flow from operating
+activities, but it will reduce the book value of our stockholders' equity. We
+review the carrying value of our properties quarterly, based on prices in effect
+as of the end of each quarter or as of the time of reporting our results. Once
+incurred, a writedown of oil and gas properties is not reversible at a later
+13
+date even if oil or gas prices increase. St. Mary incurred impairment and
+abandonment charges on proved and unproved properties of $2.4 million, $4.7
+million and $6.3 million in 2002, 2001 and 2000, respectively.
+Information concerning our reserves and future net revenue estimates is
+uncertain.
+There are numerous uncertainties inherent in estimating quantities of
+proved oil and natural gas reserves and their values, including many factors
+beyond our control. Estimates of proved undeveloped reserves, which comprise a
+significant portion of our reserves, are by their nature uncertain. The reserve
+data included in this Annual Report on Form 10-K is estimated. Although we
+believe these estimates are reasonable, actual production, revenues and reserve
+expenditures will likely vary from estimates, and these variances may be
+material.
+Estimates of oil and natural gas reserves, by necessity, are
+projections based on geologic and engineering data, and there are uncertainties
+inherent in the interpretation of such data as well as the projection of future
+rates of production and the timing of development expenditures. Reserve
+engineering is a subjective process of estimating underground accumulations of
+oil and natural gas that are difficult to measure. The accuracy of any reserve
+estimate is a function of the quality of available data, engineering and
+geological interpretation and judgment. Estimates of economically recoverable
+oil and natural gas reserves and future net cash flows necessarily depend upon a
+number of variable factors and assumptions, such as historical production from
+the area compared with production from other producing areas, the assumed
+effects of regulations by governmental agencies and assumptions governing future
+oil and natural gas prices, future operating costs, severance and excise taxes,
+development costs and workover and remedial costs, all of which may in fact vary
+considerably from actual results. For these reasons, estimates of the
+economically recoverable quantities of oil and natural gas attributable to any
+particular group of properties, classifications of such reserves based on risk
+of recovery, and estimates of the future net cash flows may vary substantially.
+Any significant variance in the assumptions could materially affect the
+estimated quantity and value of the reserves. Actual production, revenues and
+expenditures with respect to our reserves will likely vary from estimates, and
+such variances may be material. See "Business and Properties--Reserves."
+In addition, you should not construe PV-10 value as the current market
+value of the estimated oil and natural gas reserves attributable to our
+properties. We have based the PV-10 value on prices and costs as of the date of
+the estimate, in accordance with applicable regulations, whereas actual future
+prices and costs may be materially higher or lower. For example, values of our
+reserves at December 31, 2002 were estimated starting with a calculated weighted
+average sales price of $31.20 per barrel of oil (NYMEX) and $4.74 per MMBtu of
+gas (Gulf Coast spot price), then adjusted for transportation, quality and basis
+differentials. During 2002 our monthly average realized gas prices were as high
+as $3.99 per Mcf and as low as $2.24 per Mcf. For the same period our monthly
+average realized oil prices were as high as $27.66 per Bbl and as low as $17.72
+per Bbl. Many factors will affect actual future net cash flows, including:
+o the amount and timing of actual production;
+o supply and demand for oil and natural gas;
+o curtailments or increases in consumption by natural gas
+purchasers; and
+o changes in governmental regulations or taxation.
+14
+The timing of the production of oil and natural gas properties and of
+the related expenses affect the timing of actual future net cash flows from
+proved reserves and, thus, their actual present value. In addition, the 10%
+discount factor, which we are required to use to calculate PV-10 value for
+reporting purposes, is not necessarily the most appropriate discount factor
+given actual interest rates and risks to which our business or the oil and
+natural gas industry in general are subject. As a result, our actual future net
+cash flows could be materially different from the estimates included in this
+Annual Report on Form 10-K.
+Our industry is highly competitive.
+Major oil companies, independent producers, and institutional and
+individual investors are actively seeking oil and gas properties throughout the
+world, along with the equipment, labor and materials required to operate
+properties. Many of our competitors have financial and technological resources
+vastly exceeding those available to us. Many oil and gas properties are sold in
+a competitive bidding process in which we may lack technological information or
+expertise available to other bidders. We cannot be sure that we will be
+successful in acquiring and developing profitable properties in the face of this
+competition.
+Exploration and development drilling may not result in commercially productive
+reserves.
+Oil and gas drilling and production activities are subject to numerous
+risks, including the risk that no commercially productive oil or natural gas
+will be found. The cost of drilling and completing wells is often uncertain, and
+oil and gas drilling and production activities may be shortened, delayed or
+canceled as a result of a variety of factors, many of which are beyond our
+control. These factors include:
+o unexpected drilling conditions;
+o pressure or irregularities in formations;
+o equipment failures or accidents;
+o adverse weather conditions;
+o shortages in experienced labor;
+o compliance with governmental requirements; and
+o shortages or delays in the availability of drilling rigs and
+the delivery of equipment.
+The prevailing prices of oil and gas also affect the cost of and the
+demand for drilling rigs, production equipment and related services.
+We cannot assure you that the wells we drill will be productive or that
+we will recover all or any portion of our investment in such wells. The seismic
+data and other technologies we use do not allow us to know conclusively prior to
+drilling a well that oil or gas is present or may be produced economically. The
+cost of drilling, completing and operating a well is often uncertain, and cost
+factors can adversely affect the economics of a project. Drilling activities can
+result in dry wells or wells that are productive but do not produce sufficient
+net revenues after operating and other costs to cover initial drilling costs.
+15
+Our future drilling activities may not be successful, nor can we be
+sure that our overall drilling success rate or our drilling success rate for
+activity within a particular area will not decline. Unsuccessful drilling
+activities could have a material adverse effect on our results of operations and
+financial condition. Also, we may not be able to obtain any options or lease
+rights in potential drilling locations that we identify. Although we have
+identified numerous potential drilling locations, we cannot be sure that we will
+ever drill them or that we will produce oil or natural gas from them or any
+other potential drilling locations.
+Our business is subject to operating hazards that could result in substantial
+losses.
+Oil and gas operations are subject to many risks, including well
+blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
+well fluids, fires, formations with abnormal pressures, pipeline ruptures or
+spills, pollution, releases of toxic gas and other environmental hazards and
+risks. If any of these hazards occurs, we could sustain substantial losses as a
+result of:
+o injury or loss of life;
+o severe damage to or destruction of property, natural resources
+and equipment;
+o pollution or other environmental damage;
+o clean-up responsibilities;
+o regulatory investigations and penalties; and/or
+o suspension of operations.
+In addition, we may be liable for environmental damage caused by
+previous owners of property we own or lease. As a result, we may face
+substantial liabilities to third parties or governmental entities, which could
+reduce or eliminate funds available for exploration, development or acquisitions
+or cause us to incur losses. An event that is not fully covered by insurance
+could have a material adverse effect on our financial condition and results of
+operations.
+We maintain insurance against some, but not all, of these potential
+risks and losses. We may elect not to obtain insurance if we believe that the
+cost of available insurance is excessive relative to the risks presented. In
+addition, pollution and environmental risks generally are not fully insurable.
+If a significant accident or other event occurs and is not fully covered by
+insurance, it could adversely affect us.
+Other independent oil and gas companies' limited access to capital may change
+our exploration and development plans.
+Many independent oil and gas companies have limited access to the
+capital necessary to finance their activities. As a result, some of the other
+working interest owners of our wells may be unwilling or unable to pay their
+share of the costs of projects as they become due. These problems could cause us
+to change, suspend or terminate our drilling and development plans with respect
+to the affected project.
+16
+Hedging transactions may limit our potential gains and involve other risks.
+To manage our exposure to price risks in the marketing of our oil and
+natural gas, we enter into commodity price risk management arrangements from
+time to time with respect to a portion of our current or future production.
+While intended to reduce the effects of volatile oil and natural gas prices,
+these transactions may limit our potential gains if oil or natural gas prices
+were to rise substantially over the price established by the hedge. In addition,
+such transactions may expose us to the risk of financial loss in certain
+circumstances, including instances in which:
+o our production is less than expected;
+o the counterparties to our futures contracts fail to perform
+under the contracts; or
+o a sudden, unexpected event materially impacts oil or natural
+gas prices.
+The terms of our hedging agreements may also require that we furnish
+cash collateral, letters of credit or other forms of performance assurance in
+the event that mark-to-market calculations result in settlement obligations by
+us to the counterparties, which would encumber our liquidity and capital
+resources.
+Our industry is heavily regulated.
+Federal, state and local authorities extensively regulate the oil and
+gas industry. Legislation and regulations affecting the industry are under
+constant review for amendment or expansion, raising the possibility of changes
+that may affect, among other things, the pricing or marketing of oil and gas
+production. Noncompliance with statutes and regulations may lead to substantial
+penalties, and the overall regulatory burden on the industry increases the cost
+of doing business and, in turn, decreases profitability. State and local
+authorities regulate various aspects of oil and gas drilling and production
+activities, including the drilling of wells (through permit and bonding
+requirements), the spacing of wells, the unitization or pooling of oil and gas
+properties, environmental matters, safety standards, the sharing of markets,
+production limitations, plugging and abandonment, and restoration. Federal
+authorities regulate many of these same activities for our drilling and
+production operations in federal offshore waters. To cover the various
+obligations of leaseholders in federal waters, federal authorities generally
+require that leaseholders have substantial net worth or post bonds or other
+acceptable assurances that such obligations will be met. The cost of these bonds
+or other surety can be substantial, and we cannot assure you that we will be
+able to obtain bonds or other surety in all cases. Under some circumstances,
+federal authorities may require any of our operations on federal leases be
+suspended or terminated. Any such suspension or termination could materially
+adversely affect our financial condition and results of operations.
+We must comply with complex environmental regulations.
+Our operations are subject to complex and constantly changing
+environmental laws and regulations adopted by federal, state and local
+governmental authorities where we are engaged in exploration or production
+operations. New laws or regulations, or changes to current requirements, could
+have a material adverse effect on our business. We will continue to be subject
+to uncertainty associated with new regulatory interpretations and inconsistent
+interpretations between state and federal agencies. We could face significant
+liabilities to the government and third parties for discharges of oil, natural
+gas or other pollutants into the air, soil or water, and we could have to spend
+substantial amounts on investigations, litigation and remediation. We cannot be
+sure that existing environmental laws or regulations, as currently interpreted
+17
+or enforced, or as they may be interpreted, enforced or altered in the future,
+will not materially adversely affect our results of operations and financial
+condition. As a result, we may face material indemnity claims with respect to
+properties we own or have owned.
+Our business depends on transportation facilities owned by others.
+The marketability of our oil and gas production depends in part on the
+availability, proximity and capacity of pipeline systems owned by third parties.
+The unavailability of or lack of available capacity on these systems and
+facilities could result in the shut-in of producing wells or the delay or
+discontinuance of development plans for properties. Although we have some
+contractual control over the transportation of our product, material changes in
+these business relationships could materially affect our operations. Federal and
+state regulation of oil and gas production and transportation, tax and energy
+policies, changes in supply and demand, pipeline pressures, damage to or
+destruction of pipelines and general economic conditions could adversely affect
+our ability to produce, gather and transport oil and natural gas.
+We depend on key personnel.
+Our success will continue to depend on the continued services of our
+executive officers and a limited number of other senior management and technical
+personnel with extensive experience and expertise in evaluating and analyzing
+producing oil and gas properties and drilling prospects, maximizing production
+from oil and gas properties and marketing oil and gas production. Loss of the
+services of any of these people could have a material adverse effect on our
+operations. We currently do not have employment agreements with our executive
+officers other than Mark Hellerstein, our Chief Executive Officer. We do not
+carry any key person life insurance policies.
+Ownership of working interests, royalty interests and other interests by some of
+our officers and directors may create conflicts of interest.
+As a result of their prior employment with another company with which
+St. Mary engaged in a number of transactions, Ronald D. Boone, the Executive
+Vice President and Chief Operating Officer and a director of St. Mary, and two
+other vice presidents of St. Mary own royalty interests in many of St. Mary's
+properties, which were earned as part of the prior employer's employee benefit
+programs. One vice president also owns certain working interests through
+participation in acquisitions made by his former employer. Those persons have no
+royalty participation in any new St. Mary properties.
+Mr. Boone also owns 25% of Princeton Resources LLC, which owns the oil
+and gas working interests that he acquired as a result of his prior employment.
+Although Mr. Boone does not manage this entity, he may participate in any
+investment decisions made by them.
+As a result of these transactions and relationships, conflicts of
+interest may exist between these persons and us. Although these persons owe
+fiduciary duties to our stockholders and to us, we cannot assure you that
+conflicts of interest will always be resolved in our favor.
+Risks Related to Our Common Stock
+Our certificate of incorporation and bylaws have provisions that discourage
+corporate takeovers and could prevent shareholders from realizing a premium on
+their investment.
+18
+Our certificate of incorporation and bylaws contain provisions that may
+have the effect of delaying or preventing a change of control. These provisions,
+among other things, provide for noncumulative voting in the election of the
+board of directors and impose procedural requirements on stockholders who wish
+to make nominations for the election of directors or propose other actions at
+stockholders' meetings. These provisions, alone or in combination with each
+other and with the rights plan described below, may discourage transactions
+involving actual or potential changes of control, including transactions that
+otherwise could involve payment of a premium over prevailing market prices to
+shareholders for their common stock
+On July 15, 1999, our board of directors adopted a stockholder rights
+plan. The plan is designed to enhance the board's ability to prevent an acquirer
+from depriving stockholders of the long-term value of their investment and to
+protect stockholders against attempts to acquire us by means of unfair or
+abusive takeover tactics. If the board of directors decides in accordance with
+its fiduciary obligations that the terms of a potential acquisition do not
+reflect the long-term value of St. Mary, under the plan the board of directors
+could allow the holder of each outstanding share of our common stock other than
+those held by the potential acquirer to purchase one additional share of our
+common stock with a market value of twice the exercise price. This prospective
+dilution to a potential acquirer would make the acquisition impracticable unless
+the terms were improved to the satisfaction of the board of directors. However,
+the existence of the plan may impede a takeover not supported by our board,
+including a takeover that may be desired by a majority of our stockholders or
+involving a premium over the prevailing stock price.
+Our shares that are eligible for future sale may have an adverse effect on the
+price of our common stock.
+At February 28, 2003, we had 31,433,900 shares of common stock
+outstanding. Of the shares outstanding, approximately 27,405,059 shares were
+freely tradable without substantial restriction or the requirement of future
+registration under the Securities Act. Also as of that date, options to purchase
+3,025,007 shares of our common stock were outstanding, of which 1,911,398 were
+exercisable. These options are exercisable at prices ranging from $9.25 to
+$33.3125 per share. Sales of substantial amounts of common stock, or a
+perception that such sales could occur, and the existence of options or warrants
+to purchase shares of commons stock at prices that may be below the then -
+current market price of the common stock could adversely affect the market price
+of the common stock and could impair our ability to raise capital through the
+sale of our equity securities.
+Our Former Chairman of the Board and his extended family may be able to control
+us.
+Thomas E. Congdon, a director and our former Chairman of the Board, and
+members of his extended family owned approximately 16% of the outstanding shares
+of our common stock as of February 28, 2003. While no formal arrangements exist,
+these extended family members may be inclined to act in concert with Mr. Congdon
+on matters related to control of St. Mary, including for example the election of
+directors or response to an unsolicited bid to acquire St. Mary. Accordingly,
+Mr. Congdon and his family may be able to control or influence matters presented
+to our stockholders.
+We may not always pay dividends on our common stock.
+Although we have paid cash dividends to stockholders every year since
+1940 and we expect that our practice of paying dividends will continue, the
+payment of future dividends remains in the discretion of the board of directors
+19
+and will continue to depend on our earnings, capital requirements, financial
+condition and other factors. In addition, the payment of dividends is subject to
+covenants in our bank credit facility, including the requirement that we
+maintain certain levels of stockholder's equity. The board of directors may
+determine in the future to reduce the current annual dividend rate of $0.10 per
+share or discontinue the payment of dividends altogether.
+Cautionary Statement about Forward-Looking Statements
+This Annual Report on Form 10-K includes certain statements that may be
+deemed to be "forward-looking statements" within the meaning of Section 27A of
+the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
+1934. All statements, other than statements of historical facts, included in
+this Form 10-K that address activities, events or developments that St. Mary's
+management expects, believes or anticipates will or may occur in the future are
+forward looking statements. Examples of forward-looking statements may include
+discussion of such matters as:
+o The amount and nature of future capital, development and
+exploration expenditures;
+o The drilling of wells;
+o Reserve estimates and the estimates of both future net
+revenues and the present value of future net revenues that are
+included in their calculation;
+o Future oil and gas production estimates;
+o Repayment of debt;
+o Business strategies;
+o Expansion and growth of operations; and
+o Other similar matters such as those discussed in Management's
+Discussion and Analysis of Financial Condition and Results of
+Operations.
+These statements are based on certain assumptions and analyses made by us in
+light of our experience and our perception of historical trends, current
+conditions, expected future developments and other factors we believe are
+appropriate in the circumstances. Such statements are subject to a number of
+assumptions, risks and uncertainties, including such factors as the volatility
+and level of oil and natural gas prices, uncertainties in cash flow, expected
+acquisition benefits, production rates and reserve replacement, reserve
+estimates, drilling and operating risks, competition, litigation, environmental
+matters, the potential impact of government regulations, and other matters
+discussed under the caption "Risk Factors", many of which are beyond our
+control. Readers are cautioned that forward-looking statements are not
+guarantees of future performance and that actual results or developments may
+differ materially from those expressed or implied in the forward-looking
+statements.
+20
+Available Information
+Our Internet website address is www.stmaryland.com. We make available
+free of charge through our website's financial information section our annual
+reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
+8-K, and amendments to those reports filed with or furnished to the SEC under
+applicable securities laws as soon as reasonably practical after we
+electronically file such material with, or furnish it to, the SEC. Our web site
+information is not incorporated by reference into this Annual Report on Form
+10-K.
+Glossary
+The terms defined in this section are used throughout this Annual
+Report on Form 10-K.
+2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a
+two-dimensional cross-section of the subsurface.
+3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a
+three-dimensional picture of the subsurface.
+Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
+reference to oil or other liquid hydrocarbons.
+Bcf. Billion cubic feet, used herein in reference to natural gas.
+BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using
+the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+Behind pipe reserves. Estimated net proved reserves in a formation in which
+production casing has already been set in the wellbore but has not been
+perforated and production tested.
+BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio
+of six Mcf of gas (including gas liquids) to one Bbl of oil.
+Development well. A well drilled within the proved area of an oil or gas
+reservoir to the depth of a stratigraphic horizon known to be productive in an
+attempt to recover proved undeveloped reserves.
+Dry hole. A well found to be incapable of producing either oil or gas in
+sufficient quantities to justify completion as an oil or gas well.
+Estimated net proved reserves. The estimated quantities of oil, gas and gas
+liquids which geological and engineering data demonstrate with reasonable
+certainty to be recoverable in future years from known reservoirs under existing
+economic and operating conditions.
+Exploratory well. A well drilled to find and produce oil or gas in an unproved
+area, to find a new reservoir in a field previously found to be productive of
+oil or gas in another reservoir, or to extend a known reservoir.
+Fee land. The most extensive interest that can be owned in land, including
+surface and mineral (including oil and gas) rights.
+21
+Finding cost. Expressed in dollars per BOE or MCFE. Finding costs are calculated
+by dividing the amount of total capital expenditures for oil and gas activities
+by the amount of estimated net proved reserves added during the same period
+(including the effect on proved reserves of reserve revisions).
+Gross acres. An acre in which a working interest is owned.
+Gross well. A well in which a working interest is owned.
+Hydraulic fracturing. A procedure to stimulate production by forcing a mixture
+of fluid and proppant (usually sand) into the formation under high pressure.
+This creates artificial fractures in the reservoir rock, which increases
+permeability and porosity.
+MBbl. One thousand barrels of oil or other liquid hydrocarbons.
+MMBbl. One million barrels of oil or other liquid hydrocarbons.
+MBOE. One thousand barrels of oil equivalent.
+MMBOE. One million barrels of oil equivalent.
+Mcf. One thousand cubic feet.
+MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined
+using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+MMcf. One million cubic feet.
+MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined
+using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+MMBtu. One million British Thermal Units. A British Thermal Unit is the heat
+required to raise the temperature of a one-pound mass of water one degree
+Fahrenheit.
+Net acres or net wells. The sum of the fractional working interests owned in
+gross acres or gross wells.
+Net asset value per share. The result of the fair market value of total assets
+less total liabilities, divided by the total number of outstanding shares of
+common stock.
+PV-10 value. The present value of estimated future gross revenue to be generated
+from the production of estimated net proved reserves, net of estimated
+production and future development costs, using prices and costs in effect as of
+the date indicated (unless such prices or costs are subject to change pursuant
+to contractual provisions), without giving effect to non-property related
+expenses such as general and administrative expenses, debt service and future
+income tax expenses or to depreciation, depletion and amortization, discounted
+using an annual discount rate of 10%.
+Productive well. A well that is producing oil or gas or that is capable of
+production.
+Proved developed reserves. Reserves that can be expected to be recovered through
+existing wells with existing equipment and operating methods.
+22
+Proved undeveloped reserves. Reserves that are expected to be recovered from new
+wells on undrilled acreage, or from existing wells where a relatively major
+expenditure is required for recompletion.
+Recompletion. The completion for production of an existing wellbore in another
+formation from that in which the well has previously been completed.
+Reserve life. Expressed in years, represents the estimated net proved reserves
+at a specified date divided by forecasted production for the preceding 12-month
+period.
+Royalty. The interest paid to the owner of mineral rights expressed as a
+percentage of gross income from oil and gas produced and sold unencumbered by
+expenses.
+Royalty interest. An interest in an oil and gas property entitling the owner to
+shares of oil and gas production free of costs of exploration, development and
+production. Royalty interests are approximate and are subject to adjustment.
+Undeveloped acreage. Lease acreage on which wells have not been drilled or
+completed to a point that would permit the production of commercial quantities
+of oil and gas, regardless of whether such acreage contains estimated net proved
+reserves.
+Working interest. The operating interest that gives the owner the right to
+drill, produce and conduct operating activities on the property and to share in
+the production.
+ITEM 2. PROPERTIES
+Operations
+St. Mary's exploration, development and acquisition activities are
+focused in five core operating areas: the Mid-Continent region; onshore Gulf
+Coast and offshore Gulf of Mexico; the ArkLaTex region; the Rocky Mountain
+region in Montana, North Dakota and Wyoming; and the Permian Basin in west Texas
+and New Mexico. Information concerning each of our major areas of operations,
+based on our estimated proved reserves as of December 31, 2002, is shown below.
+Estimated Proved Reserves
+----------------------------------------
+MMCFE PV-10 Value
+Oil Gas ------------------ ------------------------
+(MBbls) (MMcf) Amount Percent (In thousands) Percent
+------- ------- ------------------ ------------------------
+Mid-Continent Region........... 1,315 140,840 148,731 30.3% $ 278,685 33.8%
+ArkLaTex Region................ 1,350 47,464 55,566 11.3% 91,458 11.1%
+Gulf Coast and Gulf of Mexico.. 400 37,505 39,906 8.1% 103,128 12.5%
+Rocky Mountain Region.......... 27,422 35,568 200,096 40.8% 284,482 34.5%
+Permian Basin.................. 5,632 12,795 46,588 9.5% 67,055 8.1%
+------- ------- ------- ------- -------------- -------
+Total.......................... 36,119 274,172 490,887 100.0% $ 824,808 100.0%
+======= ======= ======= ======= ============== =======
+Mid-Continent Region. Since 1973 St. Mary has been active in the
+Mid-Continent region, where operations are managed by our 32-person Tulsa,
+Oklahoma office. We have ongoing exploration and development programs in the
+Anadarko and Arkoma Basins of Oklahoma and Texas. The Mid-Continent region
+accounted for 30% of our estimated proved reserves as of December 31, 2002, or
+23
+148.7 BCFE, 84% of which were proved developed and 95% of which were natural
+gas. We participated in drilling 50 gross wells in this region in 2002,
+including 26 wells operated by us, 88% of which were completed as producers.
+St. Mary's development and exploration budget in the Mid-Continent
+region for 2003 totals $45.0 million. We plan to operate 36 drilling wells in
+the Mid-Continent region during 2003 and to utilize three to four drilling rigs
+throughout the year. Our 2003 budget also reflects participation in an
+additional 10 to 30 wells to be operated by other entities.
+Anadarko Basin. Our long history of operations and proprietary geologic
+knowledge enables us to sustain economic development and exploration programs
+despite periods of adverse industry conditions. We are applying state of the art
+technology in hydraulic fracturing and innovative well completion techniques to
+accelerate production and associated cash flow from the region's tight gas
+reservoirs. We also continue to benefit from the continuing consolidation of
+operators in the basin as we pursue attractive opportunities to acquire
+properties.
+Approximately 55% of the drilling activities for 2003 will be focused
+on low-to-medium-risk development in the Cromwell, Granite Wash, Osborne, Red
+Fork and Spiro formations. In addition, approximately 45% of our 2003
+Mid-Continent capital budget is allocated to deeper, higher-potential wells in
+the Morrow and Atoka formations at the NE Mayfield Field in Oklahoma and in
+various other fields within the Morrow and Springer formations at depths up to
+22,000 feet.
+Carrier Prospect. Within its inventory of higher-risk higher-potential
+exploration prospects, St. Mary holds an aggregate 42% working interest in 5,700
+acres in Leon County, Texas. Our Carrier Prospect acreage relates to a platform
+reef prospect located near the industry's prolific Cotton Valley pinnacle reef
+discovery and targets potentially larger platform reefs that we believe
+developed in the deeper waters of the basin during the Jurassic period. We plan
+to seek industry participation for an initial test well in 2003.
+Arkoma Basin. In February 2002 we expanded our Arkoma Basin holdings
+with the acquisition of oil and gas properties and an 89-mile gas gathering
+system from Merchant Resources #1 L.P. of Houston, Texas for $7.5 million. The
+properties include undrilled locations and are expected to complement our
+existing properties in the area. In 2002, we spud 11 wells in this area with an
+82% success rate. The primary producing formations in this area include the
+Booch, Hartshorne, Wapanucka and the Cromwell. Our average working interest for
+these wells is 91%, and we anticipate drilling at least ten gross wells in this
+area in 2002. Initial production rates from the wells have varied from
+approximately 500 Mcf per day to 1,250 Mcf per day. Since the Merchant
+acquisition we have increased production in this area from two MMcf per day to
+nearly eight MMcf per day.
+Gulf Coast and Gulf of Mexico Region. St. Mary's presence in south
+Louisiana dates to the early 1900's when our founders acquired a franchise
+property in St. Mary Parish on the shoreline of the Gulf of Mexico. These 24,900
+acres of fee lands yielded $2.9 million of gross oil and gas royalty revenue in
+2002. Our onshore Gulf Coast and Gulf of Mexico presence increased significantly
+in 1999 with the acquisition of King Ranch Energy. This acquisition included
+260,000 gross undeveloped acres (81,000 net acres) and a large 3-D seismic
+database. The Gulf Coast and Gulf of Mexico region accounted for 8% of our
+estimated proved reserves as of December 31, 2002, or 39.9 BCFE, 95% of which
+were proved developed and 94% of which were natural gas.
+24
+St. Mary's diverse activities in the onshore Gulf Coast and Gulf of
+Mexico are managed by our 13-person regional office in Lafayette, Louisiana and
+include ongoing development and exploitation programs in multiple basins onshore
+south Louisiana as well as several offshore shallow-water Gulf of Mexico blocks.
+Advanced 3-D seismic imaging and interpretation techniques and extensive
+subsurface geological interpretations are revitalizing exploration and
+development activities in the Miocene trend along the Gulf Coast. Our
+exploration and development budget in the Gulf Coast and Gulf of Mexico region
+for 2003 is $17.0 million.
+The Judge Digby Field is the largest field acquired in the King Ranch
+Energy acquisition and is located outside Baton Rouge, Louisiana in Point Coupee
+Parish. We have interests ranging from 10% to 20% in eleven wells that are
+producing a total of 180 MMcf per day on a gross basis as of February 2003. This
+ultra deep field produces from multiple Tuscaloosa reservoirs between 19,000 and
+24,000 feet. The wells are characterized by high producing rates such as the
+Parlange #11 completed in 2000 at an initial rate of 92,000 Mcf per day. We
+believe this well had the highest initial production rate for a well ever
+completed onshore Louisiana. New drilling in this field is continuing with the
+completion of the J. Wuertele #3 in August 2002 with producing rates up to
+60,000 Mcf per day. The Majors #4 was drilled to 22,962 feet and completed in
+December 2002 in the C-3 and C-4 Tuscaloosa sands producing at initial rates up
+to 36,000 Mcf per day. Two new wells and two sidetrack wells are planned for
+2003 along with several recompletions in this multi-pay geologically complex
+field.
+In December 2002 we acquired additional interests in the High Island
+Field where we drilled the successful Miami Corp T-1 well in 2001. This well is
+currently producing 8,500 Mcf per day and we plan to drill an offset well in
+2003.
+Fee Lands. St. Mary owns 24,900 acres of fee lands and associated
+mineral rights in St. Mary Parish located approximately 85 miles southwest of
+New Orleans, Louisiana. Since the initial discovery on our fee lands in 1938,
+our cumulative oil and gas revenues, primarily landowner's royalties, from the
+Bayou Sale, Horseshoe Bayou and Belle Isle fields have exceeded $235 million. We
+currently lease 9,945 acres and have granted a seismic option to Seismic
+Exchange, Inc. on the remaining 14,969 acres. The survey is underway and will
+cover the entire fee properties. SEI estimates the acquisition of the data to be
+completed by mid-October. Under the terms of the agreement, we are entitled to
+receive a copy of the processed data and have been granted the right to utilize
+the data for our purpose or for purposes of showing the data to current lessees
+and prospective lessees. Upon completion of the processing of the survey data,
+we are hopeful this will encourage development drilling by our lessees,
+facilitate the origination of new prospects and stimulate exploration interest
+in deeper, untested horizons. Our principal operators on the fee properties are
+BP Amoco, Cabot and Amerada Hess
+ArkLaTex Region. St. Mary's operations in the ArkLaTex region are
+managed by our 18-person office in Shreveport, Louisiana. The ArkLaTex region
+accounted for 11% of our estimated proved reserves as of December 31, 2002, or
+55.6 BCFE, 75% of which were proved developed and 85% of which were natural gas.
+In 1992, we acquired oil and gas properties and rights to over 6,000 square
+miles of proprietary 2-D seismic data in the region. Much of the Shreveport
+office's successful exploration and development programs have derived from niche
+acquisitions completed since 1992 totaling $23.2 million. These acquisitions
+have provided access to strategic holdings of undeveloped acreage and
+proprietary packages of geologic and seismic data, resulting in an active
+program of additional development and exploration.
+Our holdings in the ArkLaTex region are comprised of interests in
+approximately 701 producing gross wells, including 117 wells operated by us;
+interests in leases totaling approximately 77,158 gross acres; and mineral
+25
+servitudes totaling approximately 14,600 gross acres. Activities in the ArkLaTex
+region during 2002 focused on the search for new opportunities and potential
+analog fields as well as final development of several important field
+discoveries made by our geoscientists since 1994. We completed two acquisitions
+totaling $4.9 million for primarily undeveloped properties in the Huxley Field,
+part of the James Lime Horizontal Trend. Our initial well, the USA N No. 2-H was
+completed in early 2003 at a rate of 3,800 Mcf per day. We have six additional
+wells planned in the Huxley Field in 2003.
+In 2003 we will continue to focus on the search for new opportunities
+and potential analog fields in which to apply our proprietary geologic models
+and production techniques. We anticipate participating in 35 gross wells in the
+ArkLaTex region and are the operator of properties representing approximately
+85% of our 2003 ArkLaTex region capital expenditures budget.
+Rocky Mountain Region. Nance Petroleum Corporation, a wholly owned
+subsidiary of St. Mary, has conducted operations in the Williston Basin in
+eastern Montana and western North Dakota on our behalf since 1991, initially
+under a joint venture arrangement and subsequently as a wholly owned subsidiary.
+This area has expanded into the Green River Basin with properties acquired from
+Choctaw and Flying J and the Powder River Basin with our coal-bed methane pilot
+project and additional properties acquired from Flying J in 2003. The Rocky
+Mountain region accounted for 41% of our estimated proved reserves as of
+December 31, 2002, or 200.1 BCFE, 96% of which were proved developed and 82% of
+which were oil.
+Our office in Billings, Montana includes a 35-person staff. A
+significant portion of the exploration and development in the Rocky Mountain
+Region is based on the interpretation of 3-D seismic data. We have successfully
+used 3-D seismic imaging to delineate structure and porosity development in the
+Red River formation. Since 1991 we have successfully completed 34 out of 38
+gross wells drilled and operated. Our prospect inventory continues to expand as
+results from current activity lead to additional areas to conduct 3-D seismic
+surveys. Ten additional 3-D surveys are planned for 2003.
+St. Mary spent $17 million on exploration and development in the
+Williston Basin in 2002. In December 2002 we completed a $69.5 million
+acquisition of Williston Basin properties from Burlington Resources. These
+properties currently produce approximately 3,100 barrels of oil and 3,300 Mcf of
+gas per day. Our 2003 Rocky Mountain Region exploration and development capital
+budget is $33.0 million. We plan to drill seventeen operated wells with working
+interests ranging from 48% to 100%. We are the operator of properties
+representing approximately 86% of our Rocky Mountain Region capital budget in
+2003.
+In January 2003 St. Mary issued 3,380,818 shares of its restricted
+common stock valued at $71.6 million to acquire Rocky Mountain properties from
+Flying J Oil & Gas Inc. and Big West Oil & Gas Inc. This acquisition
+included properties located in the Williston, Powder River and Green River
+Basins with 66.9 BCFE of proved reserves and production of approximately 2,100
+barrels of oil and 8,200 Mcf of gas per day. We also received a net amount of
+$2.8 million in cash for normal purchase price adjustments. In addition, St.
+Mary made a non-recourse loan to Flying J and Big West of $71.6 million at LIBOR
+plus 2% for up to a 39-month period, which is secured by a pledge of the shares
+of St. Mary stock issued to Flying J and Big West. The loan was funded through
+borrowings under our bank credit facility.
+Permian Basin Region. The Permian Basin area covers a significant
+portion of eastern New Mexico and western Texas and is one of the major
+producing basins in the United States. The basin includes hundreds of oil fields
+26
+undergoing secondary and enhanced oil recovery projects. 3-D seismic imaging of
+existing fields and advanced secondary recovery programs are substantially
+increasing oil recoveries in the Permian Basin. Our holdings in the Permian
+Basin resulted from a series of niche property acquisitions since 1995, which
+total $22.1 million. We believe that our Permian Basin operations provide us
+with a solid base of long-lived oil reserves, promising longer-term exploration
+and development prospects and the potential for secondary recovery projects. The
+Permian Basin region accounted for 9.5% of our estimated proved reserves as of
+December 31, 2002, or 46.6 BCFE, of which 73% were proved developed and 73% were
+oil.
+St. Mary participated in drilling 15 gross wells in 2002 with an 80%
+success rate. The East Shugart Delaware Unit waterflood project was initiated in
+2000 with a 5-well pilot project. Production flattened out in 2002 and the
+initial response from the water injection is anticipated in 2003. We are hopeful
+the East Shugart waterflood will be an analog to our successful Parkway Delaware
+Unit waterflood that increased production from 325 Bbl per day in 1996 when the
+property was acquired to 1,200 Bbl per day in 2002.
+Our Permian Basin capital budget for 2002 is $12.0 million. In addition
+to drilling four injection wells in the East Shugart Delaware waterflood, two
+wells are planned at our Samboca prospect, six in-fill wells are planned at Ft.
+Chadbourne and three wells in the Parkway and HJSA fields.
+Other Areas. We have acquired leases covering 145,000 gross acres in
+which we own an average 90% working interest in the Hanging Woman Basin of
+Montana and Wyoming for prospective coalbed methane development. We have drilled
+an 18-well pilot program and are evaluating its results. We are also currently
+investigating permitting and environmental issues related to these prospects. We
+will be unable to determine the future potential of these prospects until we
+have completed the evaluation of our pilot program and have resolved all such
+permitting and environmental issues. An environmental public interest group has
+filed a lawsuit against the federal Bureau of Land Management seeking to cancel
+certain federal leases related to coalbed methane development in Montana, which
+could affect 48,000 of our 145,000 gross leased acres. We will monitor this
+lawsuit as part of our investigation of environmental issues related to these
+prospects. See "Legal Proceedings" for a discussion of this lawsuit.
+On April 26, 2002, the Interior Board of Land Appeals of the U.S.
+Department of the Interior issued an order that reversed a decision by the
+Bureau of Land Management dismissing a protest by the Wyoming Outdoor Council
+and Powder River Basin Resource Council of the offer for sale in February 2000
+of three oil and gas leases in the Powder River Basin in Wyoming. The Board held
+that the BLM determination to allow the offer for sale of the three particular
+leases did not comply with environmental laws since the environmental analysis
+used by the BLM in making that determination did not contain a discussion of the
+unique potential impacts associated with coalbed methane extraction and
+development or consider reasonable alternatives relevant to a pre-leasing
+environmental analysis. On October 15, 2002, the Board refused to reconsider
+this lease holding. The order addressed only three particular leases covering
+approximately 2,600 acres that are not included in our Hanging Woman Basin
+project. However, we cannot assure you that other leases, including issued
+leases that we hold in the Hanging Woman Basin, will not be challenged on a
+similar basis.
+Coalbed methane production is similar to our traditional natural gas
+production as to the physical producing facilities and the product produced.
+However, the subsurface mechanisms that allow the gas to move to the wellbore
+and the producing characteristics of coalbed methane wells are very different
+from traditional natural gas production. Unlike conventional gas wells, which
+27
+require a porous and permeable reservoir, hydrocarbon migration and a natural
+structural and/or stratigraphic trap, the coalbed methane gas is trapped in the
+molecular structure of the coal itself until released by pressure changes
+resulting from the removal of in situ water. Frequently, coalbeds are partly or
+completely saturated with water. As the water is removed, internal pressures on
+the coal are decreased, allowing the gas to desorb from the coal and flow to the
+wellbore. Unlike traditional gas wells, new coalbed methane wells often produce
+water for several months and then, as the water production decreases, natural
+gas production increases as the coal seams de-water.
+Coalbed methane gas production in the Hanging Woman Basin requires
+state permits for the use of well-site pits and evaporation ponds for the
+disposal of produced water. However, groundwater produced from the coal seams
+can generally be discharged into arroyos, surface waters, well-site pits and
+evaporation ponds without a permit if it does not exceed surface discharge
+permit levels, and if it meets state and federal primary drinking water
+standards. All of these disposal options require an extensive third-party water
+sampling and laboratory analysis program to ensure compliance with state permit
+standards. Where water of lesser quality is involved or the wells produce water
+in excess of the applicable volumetric permit limits, additional disposal wells
+would have to be drilled to re-inject the produced water back into deep
+underground rock formations.
+Duchesne Deep. In 2002 we acquired over 12,000 acres in the Uinta Basin
+of Utah to drill a basin centered gas test in the Mesaverde formation at depths
+up to 16,000 feet. Using current technology and our experience drilling and
+completing tight gas sand formations, our objective is to economically produce
+gas from the tight Mesaverde sand. The first well was spud in September 2002 and
+reached total depth in early 2003. The well will undergo extensive testing and
+if successful, $4.8 million is budgeted in 2003 for additional acreage and to
+drill two additional wells.
+Acquisitions
+In December 2002 we completed a $69.5 million acquisition of Williston
+Basin properties from Burlington Resources Oil and Gas Company LP. Other
+acquisitions in 2002 totaled $18.2 million including the $7.5 million
+acquisition of Arkoma Basin, Oklahoma properties from Merchant Resources LP and
+the $4.9 Huxley Field acquisition in east Texas. In November 2001, we completed
+a $40.5 million acquisition from Choctaw II Oil & Gas, Ltd. of oil and gas
+properties located in our Williston Basin core area and the Green River Basin in
+Wyoming. During the last five years we have completed over $232 million of
+acquisitions. For 2003 we have budgeted $90.0 million for property acquisitions.
+However, we have the financial capacity to commit substantially greater
+resources to purchases should additional opportunities be identified. In January
+2003 we closed a $68.8 million acquisition of Rocky Mountain properties from
+Flying J Oil & Gas Inc. and Big West Oil & Gas Inc., after purchase price
+adjustments. This acquisition included 66.9 BCFE of proved reserves located in
+the Williston, Powder River and Green River Basins. In January 2003 we also
+closed a $5.2 million acquisition of interests in our Ft. Chadbourne field in
+west Texas.
+Reserves
+The following table presents summary information with respect to the
+estimates of our proved oil and gas reserves for each of the years in the
+three-year period ended December 31, 2002, as prepared by both Ryder Scott
+Company, independent petroleum engineers, and us. For the periods presented,
+Ryder Scott Company evaluated properties representing approximately 80% of our
+28
+total PV-10 value while we evaluated the remainder. The PV-10 values shown in
+the following table are not intended to represent the current market value of
+the estimated proved oil and gas reserves owned by St. Mary. Neither prices nor
+costs have been escalated, but prices include the effects of hedging contracts.
+You should read the following table along with the sections entitled "Risk
+Factors - Risks Related to Our Business - Information concerning our reserves
+and future net revenue estimates is uncertain".
+As of December 31,
+--------------------------------
+2002 2001 2000
+---- ---- ----
+Proved Reserves Data:
+Oil (MBbls) 36,119 23,669 20,950
+Gas (MMcf) 274,172 241,231 225,975
+MMCFE 490,887 383,247 351,673
+PV-10 value (in thousands) (1) $ 824,808 $ 363,795 $ 1,153,663
+Proved Developed Reserves 88% 86% 87%
+Production Replacement 306% 166% 168%
+Reserve Life (years) (2) 8.9 7.1 6.7
+------------------
+(1) PV-10 value as of December 31, 2002, was calculated using prices in
+effect at December 31, 2002, of $31.20 per barrel of oil (NYMEX) and
+$4.74 per MMBtu of gas (Gulf Coast spot price). Both of these prices
+were then adjusted for transportation, quality and basis differentials.
+These prices were 57% and 79% higher, respectively, than prices used to
+calculate PV-10 value as of December 31, 2001. The PV-10 value includes
+a deficit totaling $23,398,000 attributable to price hedging contracts.
+(2) Reserve life represents the estimated proved reserves at the dates
+indicated divided by actual production for the preceding 12-month
+period.
+Production
+The following table summarizes the average volumes of oil and gas
+produced from properties in which St. Mary held an interest during the periods
+indicated:
+Years Ended December 31,
+------------------------------
+2002 2001 2000
+---- ---- ----
+Operating Data:
+Net production:
+Oil (MBbls)................................ 2,815 2,434 2,398
+Gas (MMcf)................................. 38,164 39,491 38,346
+MMCFE...................................... 55,055 54,093 52,731
+Average net daily production:
+Oil (Bbls)................................. 7,713 6,667 6,551
+Gas (Mcf).................................. 104,558 108,195 104,769
+MCFE....................................... 150,836 148,199 144,075
+Average sales price (1):
+Oil (per Bbl).............................. $ 25.34 $ 23.29 $ 23.53
+Gas (per Mcf).............................. $ 3.00 $ 3.73 $ 3.44
+Additional per MCFE data:
+Lease operating expense.................... $ 0.66 $ 0.75 $ 0.48
+Transportation costs....................... $ 0.06 $ 0.04 $ 0.04
+Production taxes........................... $ 0.20 $ 0.23 $ 0.21
+General and administrative................. $ 0.26 $ 0.22 $ 0.21
+Depreciation, depletion and amortization... $ 0.99 $ 0.95 $ 0.76
+-----------------
+(1) Includes the effects of St. Mary's hedging activities. See "Management's
+Discussion and Analysis of Financial Condition and Results of Operations."
+29
+Productive Wells
+As of December 31, 2002, we had interests in 1,256 gross (558 net)
+productive oil wells and 1,457 gross (334 net) productive gas wells. Productive
+wells are either producing wells or wells capable of commercial production
+although currently shut in. One or more completions in the same wellbore are
+counted as one well. A well is categorized under state reporting regulations as
+an oil well or a gas well based upon the ratio of gas to oil produced when it
+first commenced production, and such designation may not be indicative of
+current production.
+Drilling Activity
+The following table sets forth the wells drilled and recompleted in
+which St. Mary participated during each of the three years indicated:
+Years Ended December 31,
+---------------------------------------------------
+2002 2001 2000
+--------------- --------------- ---------------
+Gross Net Gross Net Gross Net
+----- --- ----- --- ----- ---
+Development:
+Oil..................... 26 11.52 48 14.49 40 17.37
+Gas..................... 103 38.89 154 33.28 107 24.94
+Non-productive.......... 27 14.42 31 7.13 31 9.38
+--- ----- --- ----- --- -----
+156 64.83 233 54.90 178 51.69
+--- ----- --- ----- --- -----
+Exploratory:
+Oil..................... 3 1.22 3 1.55 6 4.17
+Gas..................... 1 .10 9 1.84 11 3.63
+Non-productive.......... 8 2.64 7 2.56 8 4.32
+--- ----- --- ----- --- -----
+12 3.96 19 5.95 25 12.12
+--- ----- --- ----- --- -----
+Farmout or non-consent... 8 - 9 - 8 -
+--- ----- --- ----- --- -----
+Total (1) ............... 176 68.79 261 60.85 211 63.81
+=== ===== === ===== === =====
+---------------------------
+(1) Does not include 14, 12 and 12 gross wells completed on St.
+Mary's fee lands during 2002, 2001 and 2000, respectively, in
+which we have only a royalty interest.
+All of our drilling activities are conducted on a contract basis with
+independent drilling contractors. We do not own any drilling equipment.
+30
+Acreage
+The following table sets forth the gross and net acres of developed and
+undeveloped oil and gas leases, fee properties, mineral servitudes and lease
+options held by St. Mary as of December 31, 2002. Undeveloped acreage includes
+leasehold interests that may already have been classified as containing proved
+undeveloped reserves.
+Developed Acres (1) Undeveloped Acres (2) Total
+------------------- --------------------- -------------------
+Gross Net Gross Net Gross Net
+----- --- ----- --- ----- ---
+Arkansas............................ 2,256 399 166 28 2,422 427
+Louisiana.......................... 90,574 33,075 25,709 10,381 116,283 43,456
+Montana............................ 57,732 28,630 174,923 139,410 232,655 168,040
+New Mexico......................... 7,160 2,151 1,320 920 8,480 3,071
+North Dakota....................... 93,362 36,780 95,999 61,064 189,361 97,844
+Oklahoma........................... 231,147 60,633 43,661 20,163 274,808 80,796
+Texas.............................. 138,304 49,155 92,941 35,735 231,245 84,890
+Wyoming............................ 17,598 6,277 56,689 48,942 74,287 55,219
+Other (3) ......................... 2,501 346 13,465 8,647 15,966 8,993
+------- ------- ------- ------- --------- -------
+640,634 217,446 504,873 325,290 1,145,507 542,736
+------- ------- ------- ------- --------- -------
+Louisiana Fee Properties............ 10,337 10,337 14,577 14,577 24,914 24,914
+Louisiana Mineral Servitudes........ 9,785 5,346 4,768 4,255 14,553 9,601
+------- ------- ------- ------- --------- -------
+20,122 15,683 19,345 18,832 39,467 34,515
+------- ------- ------- ------- --------- -------
+Total ........................... 660,756 233,129 524,218 344,122 1,184,974 577,251
+======= ======= ======= ======= ========= =======
+-----------
+(1) Developed acreage is acreage assigned to producing wells for the
+spacing unit of the producing formation. Developed acreage in certain
+of St. Mary's properties that include multiple formations with
+different well spacing requirements may be considered undeveloped for
+certain formations, but have only been included as developed acreage in
+the presentation above.
+(2) Undeveloped acreage is lease acreage on which wells have not been
+drilled or completed to a point that would permit the production of
+commercial quantities of oil and gas regardless of whether such acreage
+contains estimated proved reserves.
+(3) Includes interests in Alabama, Colorado, Kansas, Mississippi, South
+Dakota, Utah and Washington. St. Mary also holds an overriding royalty
+interest in an additional 43,108 gross acres in Utah.
+31
+ITEM 3. LEGAL PROCEEDINGS
+From time to time, we may be involved in litigation relating to claims
+arising out of our operations in the normal course of business. As of this date,
+no legal proceedings are pending against us that individually or collectively
+could have a material adverse effect upon our financial condition or results of
+operations.
+On March 27, 2002, Nance Petroleum Corporation, a wholly owned
+subsidiary, was named along with several other leaseholders and interested
+parties as an additional co-defendant in a lawsuit that was originally filed in
+the U.S. District Court for the District of Montana on June 12, 2001. The
+plaintiff, the Northern Plains Resource Council, Inc. ("NPRC"), an environmental
+public interest group, sued the U.S. Bureau of Land Management, the U.S.
+Secretary of the Interior, the Montana BLM State Director and Fidelity
+Exploration & Production Company. The lawsuit, which was reported in our 2001
+Form 10-K and our 2002 Form 10-Qs, seeks the cancellation of all federal leases
+related to coalbed methane development in Montana issued by the BLM since
+January 1, 1997. This cancellation is sought primarily on the grounds of an
+alleged failure of the BLM to comply with federal environmental laws. NPRC
+alleges that the environmental impacts of coalbed methane development were not
+properly analyzed before the challenged leases were issued. The Montana portion
+of our Hanging Woman Basin coalbed methane project contains approximately 71,000
+total net acres. The lawsuit potentially affects the approximately 47,000 net
+acres that are subject to federal leases. Based on information presently
+available, we believe that the BLM complied with the applicable environmental
+laws. Nevertheless, there is no assurance as to the outcome of the lawsuit, and
+therefore, there is no assurance that it will not adversely affect our coalbed
+methane project. Even if the federal leases in Montana become unavailable, we
+anticipate continuing with the Hanging Woman Basin project in Wyoming, and
+obtaining additional non-federal leases in Montana. See "Properties - Other
+Areas" for a discussion of other recent coalbed methane legal developments.
+As previously reported in our 2002 Quarterly Reports on Form 10-Q, GNK
+Acquisition Corp., a recently acquired wholly owned subsidiary, was served in a
+lawsuit on May 1, 2002, that had been filed earlier in 2002 in the District
+Court in Shelby County, Texas. This suit was filed by Samson Lone Star Limited
+Partnership against GNK Acquisition Corp. and GNK, Inc., the previous owner of
+GNK Acquisition Corp. This suit was settled and dismissed in February 2003 with
+no material effect on our financial position or results of operations.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
+There were no matters submitted to a vote of security holders during
+the fourth quarter of 2002.
+32
+ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
+The following table sets forth the names, ages and positions held by
+St. Mary's executive officers as of January 31, 2003.
+Name Age Position
+---- --- --------
+Mark A. Hellerstein 50 Chairman of the Board, President
+and Chief Executive Officer
+Ronald D. Boone 55 Executive Vice President and Chief
+Operating Officer
+Robert L. Nance 66 Senior Vice President, and President
+of Nance Petroleum Corporation, a
+wholly-owned subsidiary of St. Mary
+since 1999
+Robert T. Hanley 56 Vice President - Business Development
+Richard C. Norris 47 Vice President - Finance, Secretary
+and Treasurer
+Milam Randolph Pharo 50 Vice President - Land and Legal
+Garry A. Wilkening 52 Vice President - Administration and
+Controller
+Douglas W. York 41 Vice President - Acquisitions and
+Engineering
+Each of the executive officers has held the above positions for the
+past five years, with the exception of the following:
+Mark A. Hellerstein was appointed Chairman of the Board in September
+2002.
+Robert L. Nance has served as Senior Vice President of St. Mary since
+2001.
+Robert T. Hanley has served as Vice President - Business Development
+since 2000. Mr. Hanley was Chief Financial Officer of Nance Petroleum
+Corporation from 1999 to 2000 and Chief Financial Officer of Panterra Petroleum,
+a partnership between St. Mary and Nance Petroleum Corporation, from 1992 to
+1999.
+Richard C. Norris has served as Vice President - Finance and Secretary
+since 1999. Mr. Norris was appointed Treasurer in 1991, and from 1991 to 1999 he
+was also Vice President - Accounting and Administration. Mr. Norris joined St.
+Mary in 1982 as Corporate Controller.
+Milam Randolph Pharo has served as Vice President - Land and Legal
+since 1998. Mr. Pharo joined St. Mary in 1996 as Vice President - Land and was
+previously in private practice as an attorney specializing in oil and gas
+matters since 1977.
+Garry A. Wilkening has served as Vice President - Administration since
+1999. Mr. Wilkening joined St. Mary in 1993 as Corporate Controller.
+The executive officers of the Company serve at the pleasure of the
+board of directors and do not have fixed terms. Executive officers generally are
+elected at the regular meeting of the board immediately following the annual
+stockholders meeting. Any officer or agent elected or appointed by the board may
+33
+be removed by the board whenever in its judgement the best interests of the
+Company will be served thereby without prejudice, subject however, to
+contractual rights, if any, of the person so removed. Messrs. Hellerstein, Boone
+and Nance are members of the board of directors.
+There are no family relationships, first cousin or closer, between any
+executive officer and director. There are no arrangements or understandings
+between any officer and any other person pursuant to which that officer was
+elected.
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
+Market Information. St. Mary's common stock is currently traded on the
+New York Stock Exchange under the symbol SM after transferring from the Nasdaq
+on November 20, 2002. The range of high and low sales prices for the quarterly
+periods in 2002 and 2001, as reported by the New York Stock Exchange after
+November 19, 2002, and the Nasdaq National Market System before November 20,
+2002, is set forth below:
+Quarter Ended High Low
+------------ ---- ---
+December 31, 2002 $27.35 $23.16
+September 30, 2002 24.71 19.00
+June 30, 2002 25.05 21.00
+March 31, 2002 23.25 18.75
+December 31, 2001 $22.20 $14.65
+September 30, 2001 21.81 14.58
+June 30, 2001 25.24 19.25
+March 31, 2001 35.00 20.63
+Holders. As of February 28, 2003, the number of record holders of St.
+Mary's common stock was 173. Management believes, after inquiry, that the number
+of beneficial owners of our common stock is in excess of 3,700.
+Dividends. St. Mary has paid cash dividends to stockholders every year
+since 1940. Annual dividends of $0.10 per share were paid in each of the years
+1998 through 2002. We expect that our practice of paying dividends on our common
+stock will continue, although the payment of future dividends on our common
+stock will continue to depend on our earnings, capital requirements, financial
+condition and other factors. In addition, the payment of dividends is subject to
+covenants in our bank credit facility, including the requirement that we
+maintain certain levels of stockholders' equity. Dividends are currently paid on
+a semi-annual basis. Dividends paid totaled $2,787,000 in 2002 and $2,795,000 in
+2001.
+Restricted Shares. On January 29, 2003, St. Mary issued 3,380,818
+restricted shares of our common stock in connection with the acquisition of oil
+and gas properties from Flying J Oil & Gas Inc. and Big West Oil & Gas
+Inc. The shares are subject to contractual restrictions on transfer for a period
+of two years and St. Mary will be required to file a registration statement for
+the resale of the shares and have it declared effective upon the expiration of
+the two-year period.
+34
+Equity Compensation Plans. St. Mary has a stock option plan, an
+incentive stock option plan and an employee stock purchase plan under which
+options and shares of St. Mary common stock are authorized for grant or issuance
+as compensation to eligible employees, consultants and members of the board of
+directors. Each of these plans has been approved by our stockholders. See Note 7
+of the Notes to Consolidated Financial Statements included in this report for
+further information about the material terms of these plans. The following table
+is a summary of the shares of common stock authorized for issuance under our
+equity compensation plans as of December 31, 2002:
+( a ) ( b ) ( c )
+Number of securities
+Number of securities remaining available for
+to be issued upon Weighted-average future issuance under
+exercise of exercise price of equity compensation plans
+outstanding options, outstanding options, (excluding securities
+Plan Category warrants and rights warrants and rights reflected in column (a))
+---------------------------------- -------------------- -------------------- -------------------------
+Equity compensation plans approved
+by security holders 3,061,566 $21.34 1,118,588(1)
+Equity compensation plans not
+approved by security holders - - -
+-------------------- -------------------- -------------------------
+Total 3,061,566 $21.34 1,118,588
+==================== ==================== =========================
+--------------
+(1) Includes 870,073 shares which are authorized for issuance
+under our employee stock purchase plan.
+35
+ITEM 6. SELECTED FINANCIAL DATA
+The following table sets forth selected consolidated financial data for St. Mary
+as of the dates and for the periods indicated. The financial data for each of
+the five years presented were derived from the consolidated financial statements
+of St. Mary. The following data should be read in conjunction with "Management's
+Discussion and Analysis of Financial Condition and Results of Operations," which
+includes a discussion of factors materially affecting the comparability of the
+information presented, and in conjunction with St. Mary's consolidated financial
+statements included elsewhere in this report.
+Years Ended December 31,
+------------------------------------------------------
+2002 2001 2000 1999 1998
+---------- ---------- ---------- ---------- ----------
+(In thousands, except per share data)
+Income Statement Data:
+Operating revenues:
+Oil and gas production $ 185,670 $ 203,973 $ 188,407 $ 73,387 $ 71,413
+Gas marketing revenue 8,399 420 - - -
+Gain (loss) on sale of proved
+properties (2,633) 367 3,404 (55) 7,685
+Derivative gain 3,188 - - - -
+Other 1,770 2,709 3,855 1,582 411
+---------- ---------- ---------- ---------- ----------
+Total operating revenues 196,394 207,469 195,666 74,914 79,509
+---------- ---------- ---------- ---------- ----------
+Operating expenses:
+Oil and gas production 50,839 55,000 38,461 19,574 17,770
+Depletion, depreciation &
+amortization 54,432 51,346 40,129 22,574 24,912
+Exploration 19,501 19,518 9,633 11,593 11,705
+Impairment of proved properties - 820 4,449 3,982 17,483
+Abandonment and impairment of
+unproved properties 2,446 3,865 1,841 6,616 4,457
+General and administrative 14,299 11,762 11,166 9,172 7,097
+Gas marketing expense 7,982 420 - - -
+Derivative loss - 1573 - - -
+Other 1,206 1,253 1,437 1,802 9,304
+---------- ---------- ---------- ---------- ----------
+Total operating expenses 150,705 145,557 107,116 75,313 92,728
+---------- ---------- ---------- ---------- ----------
+Income (loss) from operations 45,689 61,912 88,550 (399) (13,219)
+Non-operating (expense) income (3,110) 376 737 75 (1,027)
+Income tax (expense) benefit (15,019) (21,829) (33,667) 406 5,415
+---------- ---------- ---------- ---------- ----------
+Income (loss) from continuing operations 27,560 40,459 55,620 82 (8,831)
+Gain on sale of discontinued operations,
+net of income taxes - - - - 34
+---------- ---------- ---------- ---------- ----------
+Net income (loss) $ 27,560 $ 40,459 $ 55,620 $ 82 $ (8,797)
+========== ========== ========== ========== ==========
+Basic net income (loss) per common share $ 0.99 $ 1.45 $ 2.00 $ - $ (0.40)
+========== ========== ========== ========== ==========
+Diluted net income (loss) per common share $ 0.97 $ 1.42 $ 1.97 $ - $ (0.40)
+========== ========== ========== ========== ==========
+Cash dividends per share $ 0.10 $ 0.10 $ 0.10 $ 0.10 $ 0.10
+Basic weighted average common shares
+outstanding 27,856 27,973 27,781 22,198 21,874
+Diluted weighted average common shares
+outstanding 28,391 28,555 28,271 22,329 21,874
+36
+Years Ended December 31,
+------------------------
+2002 2001 2000 1999 1998
+---- ---- ---- ---- ----
+(In thousands, except per share data)
+Balance Sheet Data (end of period):
+Working capital $ 2,050 $ 34,000 $ 40,639 $ 13,440 $ 9,785
+Net property and equipment 471,939 358,930 252,411 180,664 143,825
+Total assets 537,139 436,989 321,895 230,438 184,497
+Long-term obligations 113,601 64,000 22,000 13,000 19,398
+Total stockholders' equity 299,513 286,117 250,136 188,772 134,742
+Other Data:
+Discretionary cash flow (1) $ 118,762 $ 141,278 $ 132,947 $ 43,984 $ 44,332
+Net Cash provided by (used in):
+Operating activities 141,709 127,492 92,267 40,755 45,386
+Investing activities (180,931) (159,075) (112,868) (22,243) (36,982)
+Financing activities 46,260 29,080 13,025 (12,138) (7,695)
+Capital and exploration expenditures, cash
+and noncash 192,988 182,863 125,184 91,184 57,855
+------------
+(1) Discretionary cash flow is calculated as net income plus depreciation
+and amortization expense, exploration expense, deferred tax expense and
+unrealized derivative loss minus deferred tax benefit and unrealized
+derivative gain. Discretionary cash flow is presented since it is a
+financial measure widely used for St. Mary's industry, and management
+believes that it provides useful additional information for analysis of
+St. Mary's ability to satisfy capital expenditure expectations and debt
+service and working capital requirements. Discretionary cash flow
+should not be considered in isolation or as a substitute for net
+income, income from operations, cash flow provided by operating
+activities or other income or cash flow data prepared in accordance
+with generally accepted accounting principles or as a measure of a
+company's profitability or liquidity. As discretionary cash flow
+excludes some, but not all, items that affect net income and may vary
+among companies, the discretionary cash flow presented above may not be
+comparable to similarly titled measures of other companies. The
+following table provides a reconciliation of discretionary cash flow to
+net cash provided by operating activities for the periods presented.
+Following is a reconciliation of discretionary cash flow to cash
+provided by operations:
+Years Ended December 31,
+------------------------------------------------------
+2002 2001 2000 1999 1998
+---------- ---------- ---------- ---------- ----------
+Discretionary cash flow $ 118,762 $ 141,278 $ 132,947 $ 43,984 $ 44,332
+Writedown of investments - - - - 8,502
+Loss (gain) on sales 1,797 (367) (5,560) 55 (7,685)
+Non-exploratory dry hole
+exploration expense (11,824) (10,490) (8,844) (6,602) (6,813)
+Minority interest & other 40 (1,327) 1,260 29 1,039
+Changes in working capital 32,934 (1,602) (27,536) 3,289 6,011
+---------- ---------- ---------- ---------- ----------
+Cash Flow from Operations $ 141,709 $ 127,492 $ 92,267 $ 40,755 $ 45,386
+========== ========== ========== ========== ==========
+37
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
+FINANCIAL CONDITION AND RESULTS OF OPERATION
+Overview
+During the year ended December 31, 2002, the financial markets were
+characterized by instability. At the same time some stability returned to the
+oil and gas industry. The NYMEX gas price averaged $3.25 per MMBtu and oil
+prices averaged $26.06 per barrel. Rig costs and operating costs decreased
+slightly with after-hedge price realizations down 11%, cash costs plus DD&A flat
+on an MCFE basis, production relatively flat and a $2.6 million pre-tax loss on
+property sales compared to a $367,000 pre-tax gain in 2001, net income decreased
+$14.2 million to $26.7 million. We replaced 305% of our 2002 production at a
+finding cost of $1.15 per MCFE. This success was led by excellent drilling
+results at the NE Mayfield field in Oklahoma. In December 2002 we acquired the
+Williston Basin properties of Burlington Resources Oil & Gas Company LP for
+$69.5 million in cash. In March 2002 we completed a private placement of $100.0
+million of senior convertible notes.
+The industry enters 2003 with less than average gas in storage, cold
+weather in the eastern half of the United States, a continuing petroleum
+industry strike in Venezuela and the possibility of escalating conflict in the
+Middle East. Rig and other service costs have remained moderate, and the rig
+count has not increased to the extent predicted. Our financial condition is
+excellent, and we have an outstanding inventory of prospects to be drilled. We
+caution that higher gas prices may cause rig rates and operating costs to
+increase in future months. Subject to uncertainties specified in our cautionary
+statement about forward-looking statements, we project that results of
+operations for 2003 should reflect higher revenues and higher net income.
+Critical Accounting Policies and Estimates
+Our discussion of financial condition and results of operation is based
+upon the information reported in our consolidated financial statements. The
+preparation of these consolidated financial statements requires us to make
+assumptions and estimates that affect the reported amounts of assets,
+liabilities, revenues and expenses as well as the disclosure of contingent
+assets and liabilities at the date of our financial statements. We base our
+decisions on historical experience and various other sources that are believed
+to be reasonable under the circumstances. Actual results may differ from the
+estimates we calculated due to changing business conditions or unexpected
+circumstances. Policies we believe are critical to understanding our business
+operations and results of operations are detailed below. For additional
+information on our significant accounting policies you should see Note 1 -
+Summary of Significant Accounting Policies and Note 11 - Disclosures About Oil
+and Gas Producing Activities in our accompanying consolidated financial
+statements.
+Revenue recognition - We are engaged in the exploration, development,
+acquisition and production of natural gas and crude oil. Our revenue
+recognition policy is significant because revenue is a key component of
+our results of operations and our forward-looking statements contained
+in Liquidity and Capital Resources. We derive our revenue primarily
+from the sale of produced natural gas and crude oil. Revenue is
+recorded in the month our production is delivered to the purchaser, but
+payment is generally received between 30 and 90 days after the date of
+production. At the end of each month we make estimates of the amount of
+production delivered to the purchaser and the price we will receive. We
+use our knowledge of our properties, their historical performance, the
+anticipated effect of weather conditions during the month of
+production, NYMEX and local spot market prices and other factors as the
+38
+basis for these estimates. Variances between our estimates and the
+actual amounts received are recorded in the month payment is received.
+Crude oil and Natural Gas Hedging - Generally, our crude oil and
+natural gas hedging contracts will qualify for cash flow hedge
+accounting under Statement of Financial Accounting Standards No. 133,
+"Accounting for Derivative Instruments and Hedging Activities." This
+policy is significant because it affects the timing of revenue
+recognition in our statements of operations and is discussed
+prominently in our forward looking statements contained in Liquidity
+and Capital Resources. Under this accounting pronouncement a majority
+of the gain or loss from a contract qualifying as a cash flow hedge is
+recorded in the month the contract settles with the counterparty. We
+include this gain or loss in oil and gas production revenues. If our
+natural gas and crude oil hedge contracts did not qualify for hedge
+accounting treatment or we chose not to use this hedge accounting
+methodology, our periodic statements of operations could include
+significant changes in the estimate of non-cash derivative gain or loss
+due to swings in the value of these contracts. Consequently we would
+report a different amount for oil and gas production revenues in our
+statement of operations. These fluctuations could be especially
+significant in a volatile pricing environment such as we have
+encountered over the last three years.
+Oil and gas reserve quantities - Estimated reserve quantities and the
+related estimates of future net cash flows affect our periodic
+calculations of depletion, depreciation and impairment for our proved
+oil and gas properties. Proved oil and gas reserves are the estimated
+quantities of crude oil, natural gas and natural gas liquids which
+geological and engineering data demonstrate with reasonable certainty
+to be recoverable in future periods from known reservoirs under
+existing economic and operating conditions. Future cash inflows and
+future production and development costs are determined by applying
+benchmark prices and costs, including transportation, quality and basis
+differentials, in effect at the end of each period to the estimated
+quantities of oil and gas remaining to be produced at the end of that
+period. Expected cash flows are reduced to present value using a
+discount rate that depends upon the purpose for which the reserve
+estimates will be used. Reserve estimates are inherently imprecise, and
+estimates of new discoveries are more imprecise than those of proved
+producing oil and gas properties. We expect that periodic reserve
+estimates will change in the future as additional information becomes
+available or as oil and gas prices and operating and capital costs
+change. Changes in depletion, depreciation or impairment calculations
+caused by changes in reserve quantities or net cash flows are recorded
+in the period that the reserve estimates changed.
+Valuation of long-lived and intangible assets - Our property and
+equipment is recorded at cost. An impairment allowance is provided on
+unproved property when we determine that the property will not be
+developed. We evaluate the realizability of our proved producing and
+other long-lived assets whenever events or changes in circumstances
+indicate that an impairment may have occurred. Our impairment test
+compares the expected undiscounted future net revenues from a property,
+using escalated pricing with the related net capitalized costs of the
+property at the end of each period. When the net capitalized costs
+exceed the undiscounted future net revenue of a property, the cost of
+the property is written down to our estimate of fair value, which is
+determined by applying a 15% discount rate to future net revenues.
+Other companies have their own criteria for acceptable internal rates
+of return, which may differ from our criteria. Additionally, our
+criteria for an acceptable internal rate of return are subject to
+change over time. Different pricing assumptions or discount rates could
+result in a different calculated impairment.
+39
+Income taxes - We provide for deferred income taxes on the difference
+between the tax basis of an asset or liability and its carrying amount
+in our financial statements in accordance with Statement of Financial
+Accounting Standards No. 109, "Accounting for Income Taxes." This
+difference will result in taxable income or deductions in future years
+when the reported amount of the asset or liability is recovered or
+settled, respectively. Considerable judgment is required in determining
+when these events may occur and whether recovery of an asset is more
+likely than not. Additionally, our federal and state income tax returns
+are generally not filed before the consolidated financial statements
+are prepared, therefore we estimate the tax basis of our assets and
+liabilities at the end of each period as well as the effects of tax
+rate changes, tax credits and net operating loss carryforwards.
+Adjustments related to differences between the estimates we used and
+actual amounts we reported are recorded in the period in which we file
+our income tax returns. These adjustments and changes in our estimates
+of asset recovery could have a material impact on our results of
+operations.
+The remaining portion of Management's Discussion and Analysis contains
+additional discussion of management and accounting policies that are relevant to
+specific disclosures.
+40
+Results of Operations
+The following table sets forth selected operating data for the periods
+indicated:
+Years Ended December 31,
+--------------------------------
+2002 2001 2000
+---- ---- ----
+(In thousands, except per volume data)
+Oil and gas production revenues:
+Gas production................................... $ 114,334 $ 147,292 $ 131,979
+Oil production................................... 71,336 56,681 56,428
+---------- ---------- ----------
+Total......................................... $ 185,670 $ 203,973 $ 188,407
+========== ========== ==========
+Net production:
+Gas (MMcf)....................................... 38,164 39,491 38,346
+Oil (MBbls)...................................... 2,815 2,434 2,398
+MMCFE............................................ 55,055 54,093 52,731
+Average sales price (1):
+Gas (per Mcf).................................... $ 3.00 $ 3.73 $ 3.44
+Oil (per Bbl).................................... $ 25.34 $ 23.29 $ 23.53
+Oil and gas production costs:
+Lease operating expenses......................... $36,472 $ 40,505 $ 25,567
+Transportation costs............................. 3,184 2,321 1,817
+Production taxes................................. 11,183 12,174 11,077
+---------- ---------- ----------
+Total......................................... $ 50,839 $ 55,000 $ 38,461
+========== ========== ==========
+Additional per MCFE data:
+Sales price (see Discussion under
+Accounting Matters)............................ $ 3.37 $ 3.77 $ 3.57
+Lease operating expenses......................... (0.66) (0.75) (0.48)
+Transportation costs............................. (0.06) (0.04) (0.04)
+Production taxes................................. (0.20) (0.23) (0.21)
+---------- ---------- ----------
+Operating margin.............................. $ 2.45 $ 2.75 $ 2.84
+========== ========== ==========
+Depletion, depreciation and amortization......... $ 0.99 $ 0.95 $ 0.76
+Impairment of proved properties.................. $ 0.00 $ 0.02 $ 0.08
+General and administrative....................... $ 0.26 $ 0.22 $ 0.21
+---------------------
+(1) Includes the effects of the Company's hedging activities.
+41
+2002 to 2001 Comparison
+Oil and Gas Production Revenues. Oil and gas production revenues
+decreased $18.3 million, or 9% to $185.7 million in 2002 compared to $204.0
+million in 2001. The following table presents the components of increases or
+(decreases) between 2002 and 2001:
+Production Price Price
+% Change $ Change % Change
+------------------------------------
+o Natural Gas (3%) ($0.73)/Mcf (20%)
+o Oil 16% $2.05/Bbl 9%
+Projections of pricing for oil and gas lead us to believe that our
+average realized price for both natural gas and oil will increase in 2003. We
+also expect our acquisitions in late 2002 and early 2003 to cause a significant
+increase in oil production in 2003. Average net daily production increased to a
+new annual record of 150.8 MMCFE in 2002 compared to 148.2 MMCFE in 2001. Our
+November 2001 acquisition from Choctaw II Oil & Gas, Ltd. added $13.7
+million of revenue and average daily production of 11.2 MMCFE in 2002. Wells
+completed in 2002 and our acquisitions added average net daily production of
+19.7 MMCFE. These increases offset declines in average daily production from
+older properties that include an average 5.8 MMCFE/day decline from the Judge
+Digby field.
+St. Mary hedged approximately 53.9% or 1,518 MBbls of its oil
+production for 2002 and realized a $1.9 million increase in oil revenue
+attributable to hedging compared to a $1.9 million decrease in 2001. Without
+these contracts we would have received an average price of $24.67 per Bbl in
+2002 compared to $24.08 per Bbl in 2001. We also hedged 44.9% of our 2002 gas
+production or 18.9 million MMBtu and realized a $4.1 million decrease in gas
+revenue attributable to hedging compared to a $19.2 million decrease in gas
+revenues in 2001. Without these contracts we would have received an average
+price of $3.10 per Mcf for 2002 compared to $4.22 per Mcf in 2001. With the
+contracts we currently have in place and the December 31, 2002, projections of
+pricing for natural gas and crude oil in 2003, we project that we will record
+decreases in both oil and gas revenues attributable to hedging in 2003.
+Gain (loss) on sale of proved properties. In December we closed the
+sale of our Flour Bluff field in Texas and recognized a $2.6 million loss.
+Marketed Gas Revenue and Expense. For the year ended December 31, 2002,
+we received $8.4 million from the sale of marketed natural gas produced by third
+parties. Costs associated with these revenues totaled $8.0 million and resulted
+in gross margin to us of $417,000. Due to pipeline imbalances, cost inflation,
+and fluctuations in natural gas prices we may not always have a positive gross
+margin from gas marketing activities.
+Oil and Gas Production Expenses. Oil and gas production expenses
+consist of lease operating expenses, production taxes and transportation
+expenses. Total production expenses decreased $4.2 million, or 8% in 2002 to
+$50.8 million compared with $55.0 million in 2001. In the second quarter of 2002
+our Gulf Coast region experienced a $2.7 million decrease in LOE that was
+comprised of a decrease in workover expense and an adjustment due to the
+issuance of a revised Authorization for Expenditure by the operator at Judge
+Digby. This AFE indicated that workover LOE we previously expensed under the
+original AFE should have been capitalized and recorded as property, plant and
+equipment. Our total workover expense decreased $5.1 million from 2001 to 2002.
+Other decreases in LOE attributable to our efforts to reduce LOE in total and on
+a per MCFE basis were offset by $7.3 million of LOE incurred on properties
+42
+acquired since November 2001, wells completed in 2002 and the $863,000 increase
+in transportation costs. The $991,000 decrease in production taxes reflects the
+decrease in revenue discussed above.
+Total production costs per MCFE decreased 10% to $0.92 for 2002
+compared with $1.02 in 2001. This decrease is comprised of the following:
+o A $0.03 per MCFE decrease in production taxes due to lower per
+MCFE prices.
+o A $0.09 per MCFE decrease in LOE, net of general inflation
+increases, due to our efforts to decrease LOE in total and on
+a per MCFE basis.
+o A $0.10 per MCFE decrease in LOE attributable to the decrease
+in total workover expense in excess of general cost inflation
+increases.
+o A $0.03 per MCFE increase in LOE and transportation costs
+attributable to property acquisitions and 2002 well additions
+outside of the Williston Basin.
+o A $0.09 per MCFE increase in LOE and transportation costs
+attributable to increased activity in the higher cost
+Williston Basin.
+Although we continue to monitor these costs, we believe that the trend
+of decreases in LOE on an absolute basis and on a per MCFE basis will not
+continue into the future. New workover activity is always a possibility in our
+Gulf Coast region, and it is likely that our acquisitions of producing
+properties in the higher-cost, oil-based Williston Basin will cause a general
+increase in LOE and will lead to additional workover activities as we attempt to
+enhance the performance and lengthen the lives of those properties.
+Depreciation, Depletion, Amortization and Impairment. DD&A
+increased $3.1 million or 6% to $54.4 million in 2002 compared with $51.3
+million in 2001. This increase reflects both the increase in production between
+the respective periods for 2002 and 2001 and acquisitions and drilling results
+from both years that caused DD&A per MCFE to increase by 4% to $0.99 in 2002
+compared with $0.95 in 2001.
+Abandonment and impairment of unproved properties decreased $1.4
+million or 37% to $2.4 million in 2002 compared to $3.9 million in 2001. This
+decrease is due to a decrease in abandonment of expired leases in 2002. It is
+not likely that this trend will continue into the future due to our increased
+investment in unproved properties from our acquisitions in late 2002 and early
+2003.
+Exploration. Exploration expense for 2002 remained constant at $19.5
+million. Percentages of total exploration expense are as follows:
+2002 2001
+---- ----
+o Geological and geophysical expenses 13% 19%
+o Exploratory dry holes 39% 47%
+o Overhead and other expenses 48% 34%
+In 2003 we have budgeted for geological and geophysical expenses and
+expect to incur overhead and other expenses in the pursuit of exploration.
+However, oil and gas exploration is imprecise, and success can be affected by
+numerous factors. Not every likely geological structure contains oil or natural
+gas. Even when oil or natural gas is discovered there are no guarantees that
+sufficient quantities can be produced to justify the completion of an
+exploratory well.
+43
+General and Administrative. General and administrative expenses
+increased $2.5 million or 22% to $14.3 million in 2002 compared to $11.8 million
+in 2001. On a per MCFE basis these costs increased 18% to $0.26 in 2002 from
+$0.22 in 2001. We experienced an increase in non-compensation general expenses
+of $1.0 million due primarily to increased personnel and general cost inflation.
+This amount plus a $3.7 million increase in compensation expense associated with
+increased personnel and our incentive plans were partially offset by a $2.2
+million increase in COPAS overhead reimbursement from operations and costs
+allocated to exploration expense. As we continue to grow in size and number of
+personnel we expect that general and administrative expenses will also grow.
+However, we anticipate that these expenses will decrease on a per MCFE basis in
+2003.
+Interest Expense. Interest expense increased to $3.9 million in 2002.
+This amount reflects accrued interest on our senior convertible notes. The
+amount we accrued and paid in 2002 was affected by a fixed-rate to floating-rate
+interest rate swap we entered into in March 2002 and closed at a net gain in
+December 2002. Without this swap, interest expense for the period ending
+December 31, 2002, would have been $4.6 million. We anticipate that interest
+expense in 2003 will be significantly higher than the 2002 amount due to
+termination of the interest rate swap and increased borrowing from our credit
+facility.
+Income Taxes. Income tax expense totaled $15.0 million in 2002
+resulting in an effective tax rate of 35.3% compared to $21.8 million in 2001 at
+an effective tax rate of 35.0%. The effective rate change from 2001 reflects
+increased accrued state income taxes from marginal rate adjustments offset by
+adjustments to valuation allowances against state net operating loss carryovers.
+We adjusted the valuation allowance after we considered a number of factors,
+including our prior utilization of net operating losses and carryovers, tax
+planning strategies for utilizing both federal and state net operating loss and
+capital loss carryovers and projections of future taxable income. We also took
+into account the reversal of prior temporary timing differences and the effect
+that recent acquisitions will have on anticipated expenditures for intangible
+drilling costs. Based on the weight of positive and negative evidence regarding
+the recoverability of our net deferred tax assets, we concluded that only a
+partial valuation allowance was required. Future effective tax rates could be
+adversely affected if our taxable income increases to the point of being taxed
+at the highest federal marginal rate, increased revenues in states with higher
+statutory rates, unfavorable changes in tax laws and regulations, and by changes
+in our opinion of our ability to absorb our deferred tax assets due to changes
+in economic conditions.
+Net Income. Net income decreased to $27.6 million for 2002 compared to
+$40.5 million for 2001. A 20% decrease in gas prices and a 3% decrease in gas
+production partially offset by a 16% increase in oil production and a 9%
+increase in oil price resulted in an $18.3 million decrease in oil and gas
+production revenue between the two periods. Other large items causing a decrease
+in net income were a $3.0 million decrease in gain from property sales, a $3.1
+million increase in DD&A, a $2.5 million increase in G&A and a $3.5
+million increase in interest expense. The decreases were partially offset by a
+$4.8 million increase in derivative gains, a $4.2 million decrease in production
+costs, and a $1.4 million decrease in unproved property impairment. The net
+result of the changes caused a $6.8 million decrease in income tax expense.
+2001 to 2000 Comparison
+Oil and Gas Production Revenues. Oil and gas production revenues
+increased $15.6 million, or 8% to a record $204.0 million in 2001 compared to
+$188.4 million in 2000. Revenue from gas production increased $15.3 million or
+12%. This increase was a result of a gas production volume increase of 3% and an
+8% increase in the average realized gas price to $3.73 per Mcf in 2001. Revenue
+44
+from oil production increased $253,000. This increase resulted from an oil
+production volume increase of 1% offset by a 1% decrease in the average realized
+oil price to $23.29 per Bbl in 2001. Our share of revenue from wells completed
+in 2001 added $27.5 million of revenue and our December 2000 acquisition of JN
+Exploration properties added $11.5 million of revenue and average daily
+production of 7.4 MMCFE in 2001. Average net daily production increased to a new
+annual record of 148.2 MMCFE in 2001 compared to 144.1 MMCFE in 2000. Wells
+completed in 2001 offset 22.3 MMCFE of decline in average daily production from
+older properties.
+St. Mary hedged approximately 34.6% or 841 MBbls of its oil production
+for 2001 and realized a $1.9 million decrease in oil revenue attributable to
+hedging compared to a $13.2 million decrease in 2000. Without these contracts we
+would have received an average price of $24.08 per Bbl in 2001 compared to
+$29.01 per Bbl in 2000. We also hedged 40.6% of our 2001 gas production or 17.6
+million MMBtu and realized a $19.2 million decrease in gas revenue attributable
+to hedging compared to a $20.5 million decrease in gas revenues in 2000. Without
+these contracts we would have received an average price of $4.22 per Mcf for
+2001 compared to $3.97 per Mcf in 2000.
+Oil and Gas Production Expenses. Total production expenses increased
+$16.5 million, or 43% in 2001 to $55.0 million compared with $38.5 million in
+2000. During 2001 we experienced a $4.9 million increase in workover expense,
+most of which related to activity in the Williston Basin and the Gulf Coast
+Region. Williston Basin acquisitions in the last half of 2000 and in 2001 added
+$1.7 million of LOE. Recurring LOE from our JN Exploration acquisition
+properties represented $1.1 million of the increase and wells completed in 2001
+added another $1.1 million. We experienced higher recurring LOE from wells
+completed in the Williston Basin, the Permian Basin and the Gulf Coast/Gulf of
+Mexico as a result of increased competition for limited availability of services
+and general cost inflation. Higher production taxes and transportation expenses
+resulting from higher oil and gas revenues account for $1.6 million of the
+increase. Total production costs per MCFE increased 40% to $1.02 for 2001
+compared with $0.73 in 2000. An $0.18 per MCFE increase was due to the increase
+in workover expense, plus LOE from acquisitions and wells completed in 2001.
+Another $0.02 per MCFE increase was due to increased production taxes and
+transportation expenses. The remaining increase is due to general cost
+inflation.
+Depreciation, Depletion, Amortization and Impairment. DD&A
+increased $11.2 million or 28% to $51.3 million in 2001 compared with $40.1
+million in 2000. DD&A expense per MCFE increased 25% to $0.95 in 2001
+compared to $0.76 in 2000. This increase reflects acquisitions and drilling
+results in 2000 and 2001 that added costs at a higher per unit rate. The
+DD&A per MCFE rate was further affected by downward adjustments to reserves
+due to pricing differences between December 31, 2001 and December 31, 2000.
+St. Mary recorded an $820,000 impairment of proved oil and gas
+properties in 2001 compared with $4.4 million in 2000. Impairments in 2001
+include a declining performance adjustment of $520,000 from the Thornton South
+prospect in Texas and various marginal well impairments.
+Abandonment and impairment of unproved properties increased $2.0
+million or 110% to $3.9 million in 2001 compared to $1.8 million in 2000. This
+increase is due to an increase in abandonment of expired leases in 2001 and the
+impairment of leasehold costs related to several exploratory dry holes.
+45
+Exploration. Exploration expense for 2001 increased $9.9 million or
+103% to $19.5 million compared with $9.6 million in 2000. Percentages of total
+exploration expense are as follows:
+2001 2000
+---- ----
+o Geological and geophysical expenses 19% 24%
+o Exploratory dry holes 47% 21%
+o Overhead and other expenses 34% 55%
+General and Administrative. General and administrative expenses
+increased $596,000 or 5% to $11.8 million in 2001 compared to $11.2 million in
+2000. Increases in compensation expense associated with increased personnel, our
+incentive plans and general cost inflation were offset by a $4.3 million
+increase in COPAS overhead reimbursements from operations and costs allocated to
+exploration expense
+Income Taxes. Income tax expense totaled $21.8 million in 2001
+resulting in an effective tax rate of 35.0% compared to $33.7 million in 2000
+with an effective tax rate of 37.7%. The effective rate change from 2000
+reflects decreased accrued state income taxes from marginal rate adjustments and
+a decrease in deferred federal income tax due to a 1% rate decrease from the
+highest federal marginal rate.
+Net Income. Net income decreased to $40.5 million for 2001 compared to
+$55.6 million for 2000. An 8% increase in gas prices and a 3% increase in
+production volumes resulted in a $15.6 million increase in oil and gas
+production revenue. Increases in oil and gas production costs and DD&A of
+$27.8 million, a $5.2 million decrease from gains on sale of proved property and
+KMOC stock and a $9.9 million increase in exploration expense offset the
+increase in revenue and an $11.8 million decrease in income tax expense.
+Liquidity and Capital Resources
+Our primary sources of liquidity are the cash provided by operating
+activities, debt financing, sales of non-strategic properties and access to the
+capital markets. All of these sources can be impacted by significant
+fluctuations in oil and gas prices. An unexpected decrease in prices would
+reduce expected cash flow from operating activities, might reduce the borrowing
+base on our credit facility, could reduce the value of our non-strategic
+properties and historically has limited our industry's access to the capital
+markets.
+We use cash for the acquisition, exploration and development of oil and
+gas properties and for the payment of debt obligations, trade payables and
+stockholder dividends. Exploration and development programs are generally
+financed from internally generated cash flow, debt financing and cash and cash
+equivalents on hand. In the event of an unexpected decrease in oil and gas
+prices, cash uses such as the acquisition of oil and gas properties and the
+payment of stockholder dividends are discretionary and can be reduced or
+eliminated. At any given point in time, we may be obligated to pay for
+commitments to explore for or develop oil and gas properties or incur trade
+payables. However, future obligations can be reduced or eliminated when
+necessary. We are currently only required to make interest payments on our debt
+obligations. An unexpected increase in oil and gas prices provides flexibility
+to modify our uses of cash flow.
+We continually review our capital expenditure budget to reflect changes
+in current and projected cash flow, acquisition opportunities, debt requirements
+and other factors.
+46
+Cash Flow. St. Mary's net cash provided by operating activities
+increased $14.2 million or 11% to $141.7 million in 2002 compared to $127.5
+million in 2001. The increase reflects a change between years of $29.3 million
+in other current assets relating to the collection of receivables, payment of
+prepaid items and collection of refundable income taxes. We also had a change
+between years of $5.2 million from increased accounts payable. These items
+increasing cash flow from operations were offset by a decrease in net income of
+$13.1 million and a $7.1 million decrease in the effect of non-cash items
+between the periods. We anticipate significantly increased cash flow from
+operations in 2003 as a result of expected higher oil and gas prices in 2003 and
+increased production attributable to our property acquisitions in late 2002 and
+early 2003.
+St. Mary's net cash provided by operating activities increased $35.2
+million or 40% to $127.5 million in 2001 compared to $92.3 million in 2000. The
+increase reflects a change between years of $22.5 million from the collection of
+receivables and a change between years of $15.4 million from increased accounts
+payable.
+Net cash used in investing activities increased $21.8 million in 2002
+to $180.9 million compared to $159.1 million in 2001. Total 2002 capital
+expenditures for cash, including acquisitions of oil and gas properties,
+increased $14.2 million or 8% to $184.7 million in 2002 compared to $170.5
+million in 2001 due to an increase in acquisition activity in 2002 offset by our
+planned decrease in cash expended on drilling activities.
+Net cash used in investing activities increased $46.2 million in 2001
+to $159.1 million compared to $112.9 million in 2000. Total 2001 capital
+expenditures for cash, including acquisitions of oil and gas properties,
+increased $53.2 million or 45% to $170.5 million in 2001 compared to $117.3
+million in 2000 due to an increase in drilling activity in 2001 offset by a
+decrease in cash expended for oil and gas property purchases.
+Net cash provided by financing activities increased $17.2 million to
+$46.3 million in 2002 compared to $29.1 million in 2001. This increase reflects
+our March 2002 private placement of $100.0 million of 5.75% senior convertible
+notes due 2022. A portion of the net proceeds of $96.7 million was used to repay
+the balance due on our credit facility at that time. By year end we had borrowed
+$14.0 million on our credit facility, and subsequent to year end we borrowed an
+additional $56.0 million to finance acquisitions that closed in early 2003. We
+did not repurchase any of our common stock during 2002.
+Net cash provided by financing activities increased $16.1 million to
+$29.1 million in 2001 compared to $13.0 million in 2000. The increase is due to
+a net $42.0 million increase in long-term debt during 2001 compared to a $9.0
+million increase in 2000 offset by a $4.4 million decrease in proceeds received
+from the sale of common stock related to our stock option programs. We also
+repurchased $12.9 million of our common stock during 2001. We used our credit
+facility to fund the acquisition of properties from Choctaw and finance current
+operations.
+St. Mary had $11.2 million in cash and cash equivalents and had working
+capital of $2.1 million as of December 31, 2002 compared to $4.1 million in cash
+and cash equivalents and working capital of $34.2 million as of December 31,
+2001.
+Pension Benefits. Substantially all of our employees who meet age and
+service requirements participate in a non-contributory pension plan. At December
+31, 2002, we have recorded a $1.2 million pre-tax loss in accumulated other
+comprehensive income related to this plan. We believe this obligation will be
+funded from future cash flow from operating activities. For purposes of
+calculating our obligation under the plan, we have used an expected return on
+47
+plan assets of 8%. We think this rate of return is appropriate over the
+long-term given the 60% equity and 40% debt securities mix of investment for
+plan assets and the historical rate of return provided by equity and debt
+securities since the 1920s. Our actual rate of return for 2002 was a negative
+10.0% and was a negative 0.7% for 2001. The difference in investment income
+using our projected rate of return compared to our actual rates of return for
+the past two years was not material and will not have a material effect on
+statements of operation or cash flow from operating activities in future years.
+For the 2002 plan year, a 0.75% decrease in the discount rate combined
+with a 0.25% decrease in the rate of future compensation increases caused a
+$195,000 increase in the projected benefit obligation of the plan. We do not
+believe this change was material and project that it will not have a material
+effect on the results of operations or on cash flow from operating activities in
+future periods.
+We also have a supplemental non-contributory pension plan that covers
+certain management employees. There are no plan assets for this plan. For the
+2002 plan year, a 0.75% decrease in the discount rate combined with a 0.25%
+decrease in the rate of future compensation increases caused a $91,000 increase
+in the projected benefit obligation for this plan. This plan's accumulated
+benefit obligation was $853,000 at December 31, 2002, and was $685,000 at
+December 31, 2001. We believe this obligation will be funded from future cash
+flow from operating activities.
+Senior Convertible Notes. In March 2002 we issued in a private
+placement a total of $100.0 million of our 5.75% senior convertible notes due
+2022 with a 0.5% contingent interest provision. The contingent interest
+provision did not apply to our first interest payment on September 15, 2002, but
+it will apply to the payment due on March 15, 2003. Interest payments on the
+notes will be made on March 15 and September 15 in subsequent years. We received
+net proceeds of $96.7 million after deducting the initial purchasers' discount
+and offering expenses paid by us. The notes are general unsecured obligations
+and rank on a parity in right of payment with all our existing and future senior
+indebtedness and other general unsecured obligations, and are senior in right of
+payment with all our future subordinated indebtedness. The notes are convertible
+into our common stock at a conversion price of $26.00 per share, subject to
+adjustment. We can redeem the notes with cash in whole or in part at a
+repurchase price of 100% of the principal amount plus accrued and unpaid
+interest beginning on March 20, 2007. The note holders have the option of
+requiring us to repurchase the notes for cash at 100% of the principal amount
+plus accrued and unpaid interest upon (1) a change in control of St. Mary or (2)
+on March 20, 2007, March 15, 2012 and March 15, 2017. If the note holders
+require repurchase on March 20, 2007, we may pay the repurchase price with cash,
+shares of our common stock valued at a discount to the market price at the time
+of repurchase or any combination of cash and our discounted common stock. We are
+not restricted from paying dividends, incurring debt, or issuing or repurchasing
+our securities under the indenture for the notes. There are no financial
+covenants in the indenture. We used a portion of the net proceeds from the notes
+to repay our credit facility balance and used the remaining net proceeds to fund
+a portion of our 2002 capital expenditures. On March 25, 2002, we entered into a
+five-year fixed-rate to floating-rate interest rate swap on $50.0 million of the
+notes. The floating rate was determined as LIBOR plus 0.36%. We elected to
+terminate this swap on December 3, 2002, and received proceeds of $4.0 million.
+Credit Facility. At December 31, 2002, we had an unsecured long-term
+revolving credit facility with a bank group consisting of Bank of America,
+Comerica Bank-Texas and Wells Fargo Bank West. Under this facility, the maximum
+loan amount was $200.0 million. The amount actually available depended upon a
+borrowing base that the lenders periodically redetermined based on the value of
+48
+our oil and gas properties and other assets. As of December 31, 2002, the stated
+total possible borrowing base was $160.0 million. However, since we pay
+commitment fees based on the unused portion of the borrowing base we limited the
+borrowing base that we accepted to correspond with our actual funding
+requirements. The accepted borrowing base was $40.0 million at December 31,
+2002. The facility had a maturity date of December 31, 2006, and included a
+revolving period that matured on June 30, 2003, at which time all outstanding
+borrowings would convert to a term loan payable in quarterly installments
+through the facility maturity date. We were required to comply with certain
+covenants including maintenance of stockholders' equity at a specified level, as
+well as restrictions on additional indebtedness, sales of oil and gas
+properties, activities outside our ordinary course of business and certain
+merger transactions. Borrowings under the facility were secured by a pledge of
+collateral in favor of the banks and guarantees by subsidiaries. Such collateral
+consisted of security interests in the oil and gas properties of St. Mary and
+its subsidiaries.
+As of December 31, 2002 and 2001, $14.0 million and $64.0 million,
+respectively, was outstanding under this credit agreement. These outstanding
+balances accrued interest at rates determined by St. Mary's debt to total
+capitalization ratio at our option of either:
+Debt to Capitalization Ratio <30% =>30%<40% =>40%<50% >50%
+---------------------------------------------------------------------------------------
+Option (1)
+LIBOR plus 1.000% 1.250% 1.375% 1.625%
+Option (2) - The higher of:
+Federal funds rate plus 0.50% 0.50% 0.50% 0.50%
+Prime rate plus - - - 0.25%
+At December 31, 2002 our debt to capitalization ratio as defined under
+the credit agreement was 27.5%.
+On January 29, 2003, St. Mary entered into a new $300.0 million credit
+facility with Wachovia Bank as Administrative Agent and eight other
+participating banks. This new credit facility replaced our previous $200.0
+million credit facility. The initial calculated borrowing base included
+properties we acquired from Flying J Oil & Gas Inc. and Big West Oil &
+Gas Inc. The borrowing base is currently at $215.0 million and will increase to
+$250.0 million when we provide the remaining collateral. St. Mary has accepted
+an initial commitment of $150.0 million under this facility. The credit
+agreement has a maturity date of January 27, 2006. We are required to comply
+with certain covenants that include a current ratio of 1.0 to 1.0, maintenance
+of ERISA compliance, and restrictions on additional indebtedness, sales of oil
+and gas properties, activities outside our ordinary course of business and
+certain merger transactions. Interest is accrued based on the borrowing base
+utilization percentage as LIBOR or the Alternate Base Rate (Prime), plus the
+following:
+Borrowing Base
+Utilization Percentage <50% =>50%<75% =>75%<90% =>90% - - -
+----------------------------------------------------------------------------------------
+Eurodollar Loans 1.250% 1.500% 1.750% 2.000%
+ABR Loans 0.000% 0.250% 0.500% 0.750%
+Commitment Fee Rate 0.300% 0.375% 0.375% 0.500%
+49
+On the date we entered into this credit facility our loan balance
+accrued interest at LIBOR plus 1.25%.
+Schedule of Contractual Obligations. The following table summarizes our
+future estimated principal payments and minimum lease payments for the periods
+specified (in millions):
+Long-Term Operating Total Cash
+Debt Leases Obligation
+------------------------------------
+Less than 1 year $ - $ 1.6 $ 1.6
+1-3 years - 2.5 2.5
+4-5 years 14.0 1.9 15.9
+After 5 years 100.0 3.7 103.7
+------------------------------------
+Total $ 114.0 $ 9.7 $ 123.7
+====================================
+In the next three years, we have two leases of office space for our
+regional offices that will expire. A third lease for office space will expire in
+year 4. Estimated costs to replace these leases are not included in the table
+above. For purposes of the table we assume that the holders of our senior
+convertible notes will not exercise the conversion feature.
+Common Stock. At the annual stockholders meeting on May 23, 2001 the
+stockholders of St. Mary voted to increase the amount of authorized common
+shares to 100,000,000.
+In August 1998 our board of directors authorized a stock repurchase
+program whereby we may purchase from time-to-time, in open market transactions
+or negotiated sales, up to two million of our common shares. Through March 12,
+2003 we had repurchased a total of 1,009,900 shares of St. Mary common stock
+under the program for $16.2 million at a weighted average price of $15.86 per
+share, net of put option sale premiums received. We anticipate that additional
+purchases of shares may occur as market conditions warrant. Any future purchases
+will be funded with internal cash flow and borrowings under our credit facility.
+On January 29, 2003, we issued a total of 3,380,818 restricted shares
+of our common stock valued at $71.6 million to Flying J Oil & Gas Inc. and
+Big West Oil & Gas Inc. for the acquisition of oil and gas properties, and
+we made a non-recourse loan to Flying J and Big West in the amount of $71.6
+million at LIBOR plus 2% for up to a 39-month period. The loan is secured by a
+pledge of the 3,380,818 shares and during the 39-month loan period Flying J and
+Big West can elect to sell these shares to St. Mary for $71.6 million plus
+accrued interest on the loan for up to the first 30 months, and we can elect to
+repurchase the shares for $97.4 million with the proceeds applied to repayment
+of the loan. The shares are subject to contractual restrictions on transfer for
+a period of two years. Flying J and Big West cannot increase their ownership
+percentage in St. Mary for a period of 30 months.
+Capital and Exploration Expenditures. Expenditures for exploration and
+development of oil and gas properties and acquisitions are the primary use of
+our capital resources. The following table sets forth certain information
+regarding the costs incurred by us in our oil and gas activities during the
+periods indicated.
+50
+Capital and Exploration Expenditures
+------------------------------------
+For the Years Ended
+December 31,
+------------
+2002 2001 2000
+---- ---- ----
+(In thousands)
+Development $ 74,376 $ 98,617 $ 48,996
+Exploration 22,778 24,506 17,012
+Acquisitions:
+Proved 87,706 41,188 53,482
+Unproved 8,128 18,552 5,694
+-------- -------- ---------
+Total $192,988 $182,863 $ 125,184
+======== ======== =========
+We continuously evaluate opportunities in the marketplace for oil and
+gas properties and, accordingly, may be a buyer or a seller of properties at
+various times. We will continue to emphasize smaller niche acquisitions
+utilizing our technical expertise, financial flexibility and structuring
+experience. In addition, we are also actively seeking larger acquisitions of
+assets or companies that would afford opportunities to expand our existing core
+areas, to acquire additional geoscientists and/or engineers, or gain a
+significant acreage and production foothold in a new basin.
+St. Mary's total costs incurred for capital and exploration activities
+in 2002 increased $10.1 million or 6% compared to 2001. We spent $112.8 million
+in 2002 for unproved property acquisitions and domestic exploration and
+development compared to $141.7 million for the comparable period in 2001. This
+decrease was a result of planned decreases in the drilling activity budget and a
+$2.9 million decrease in unproved property acquisition activity. Well testing
+continues on our two coalbed methane pilot programs located in the Hanging Woman
+Basin. All pilot wells in the Antelope Draw field are currently shut-in while we
+evaluate the data from dewatering. Prior to shut-in, production from the
+Anderson coal averaged 250 Mcf/day. We are continuing to produce and test wells
+at the Nest Prong field project. During the year, one of our partners exercised
+their right to participate in a leasehold acquisition bringing our total to
+145,000 gross acres in the project. We are subject to an environmental public
+interest group lawsuit on 48,000 of these acres. See "Legal Proceedings" for a
+discussion of this lawsuit.
+In November 2001 we purchased oil and gas properties from Choctaw II
+Oil & Gas, Ltd. for $40.5 million in cash. We used a portion of our credit
+facility for this acquisition. The properties are primarily located in the
+Williston Basin of Montana and North Dakota and in the Green River Basin of
+Wyoming.
+In December 2002 we purchased oil and gas properties from Burlington
+Resources Oil & Gas Company LP for $69.5 million in cash. The properties are
+located in the Williston Basin of Montana and North Dakota with extensive
+overlap of ownership interest. Most of the properties will be operated by our
+Nance subsidiary and are very concentrated in a manageable well count with high
+ownership percentages in high quality long-lived properties. We financed this
+acquisition using cash on hand and a portion of our bank credit facility. At the
+time of acquisition, these properties were producing an estimated 3,100 Bbls of
+oil per day and 3,300 Mcf of natural gas per day.
+51
+Capital Expenditure Budget. We anticipate spending approximately $225
+million for capital and exploration expenditures in 2003 with $90 million
+allocated for acquisitions of producing properties. Anticipated ongoing
+exploration and development expenditures for each of our core areas is as
+follows (in millions):
+o Mid-Continent region $ 45
+o Williston Basin and Rockies region $ 33
+o ArkLaTex region $ 19
+o Gulf Coast and Gulf of Mexico region $ 17
+o Permian Basin $ 12
+o Other $ 9
+-----
+Total $135
+=====
+We believe that the amount not funded from our internally generated
+cash flow in 2003 can be funded from our existing cash and our bank credit
+facility. The amount and allocation of future capital and exploration
+expenditures will depend upon a number of factors including the number and size
+of available acquisition opportunities and our ability to assimilate these
+acquisitions. Also, the impact of oil and gas prices on investment
+opportunities, the availability of capital and borrowing capability and the
+success of our development and exploratory activity could lead to funding
+requirements for further development. If additional development or attractive
+acquisition opportunities arise, we may consider other forms of financing,
+including the public offering or private placement of equity or debt securities.
+In January 2003 we utilized our common stock, cash on hand and a
+portion of our new credit facility to acquire $74.0 million of oil and gas
+properties. On January 29, 2003, we closed a $71.6 million acquisition with
+restricted shares of our common stock that included 66.9 BCFE or proved reserves
+for $68.8 million of oil and gas properties and $2.8 million of cash for net
+purchase price adjustments from Flying J Oil & Gas Inc. and Big West Oil
+& Gas Inc. See the Common Stock section above for additional details. Half
+of the value of the properties acquired is located in the Williston Basin. The
+remaining value is split between the Powder River, Wind River and Green River
+Basins of Wyoming and represents a significant increase of our presence in these
+areas.
+We seek to protect our rate of return on acquisitions of producing
+properties by hedging cash flow when the economic criteria from our evaluation
+and pricing model indicate it would be appropriate. Management's strategy is to
+hedge cash flows from investments currently requiring a gas price in excess of
+$3.25 per Mcf and an oil price in excess of $22.50 per Bbl in order to meet
+minimum rate-of-return criteria. Management reviews these hedging parameters on
+a quarterly basis. We anticipate this strategy will result in the hedging of
+future cash flows from acquisitions. We generally limit our aggregate hedge
+position to no more than 50% of total production but will hedge larger
+percentages of total production in certain circumstances. We seek to minimize
+basis risk and index the majority of oil hedges to NYMEX prices and the majority
+of gas hedges to various regional index prices associated with pipelines in
+proximity to our areas of gas production. Our cash flow hedging instruments
+generally qualify for cash flow hedge accounting under SFAS No. 133. Our policy
+requires that we diversify our hedge positions with various counterparties and
+requires that such counterparties have clear indications of current financial
+strength. Including hedges entered into since December 31, 2002 we have the
+following contracts in place:
+52
+Swaps
+-----
+Average Quantity Average Fixed
+Product Volumes/month Type Contract Price Duration
+---------------------------------------------------------------------------------------------
+Natural Gas 1,599,000 MMBtu $4.35 01/03 - 12/03
+Natural Gas 844,000 MMBtu $4.04 01/04 - 12/04
+Oil 206,200 Bbls $25.94 01/03 - 12/03
+Oil 144,500 Bbls $23.71 01/04 - 12/04
+Collars
+Average Floor Ceiling
+Product Volumes/month Price Price Duration
+---------------------------------------------------------------------------------------------
+Natural Gas 152,000 MMbtu $2.50 $5.96 02/03 - 12/03
+On February 4, 2002, we entered into an agreement to monetize our
+unrealized hedge gain receivable due from Enron for $1.1 million. This amount
+was included in other comprehensive income at December 31, 2001, and was
+recorded as a hedge gain in the first quarter of 2002. Hedge gains and losses
+are reported in oil and gas production revenues in our consolidated statements
+of operations. Amortization of $1.7 million of other comprehensive income
+related to our commodity positions with Enron is also recorded in hedge gain. We
+will record amortization of the remaining $49,000 of other comprehensive income
+in hedge loss in 2003 for these contracts. Derivative gain in the consolidated
+statements of operations includes $31,000 of net loss from oil and gas hedge
+ineffectiveness.
+Other Derivatives. Our senior convertible notes contain a provision for
+payment of contingent interest if certain conditions are met. Under SFAS No. 133
+this provision is considered an embedded equity-related derivative that is not
+clearly and closely related to the fair value of an equity interest and
+therefore must be separated and accounted for as a derivative instrument. The
+value of the derivative at issuance was $474,000. This amount was recorded as a
+decrease to the convertible notes payable in the consolidated balance sheets. Of
+this amount, $75,000 was amortized through interest expense in 2002. Derivative
+gain in the consolidated statements of operations includes $341,000 of net loss
+from mark-to-market adjustments for this derivative.
+Our fixed-rate to floating-rate interest rate swap on $50.0
+million of senior convertible notes did not qualify for fair value hedge
+treatment under SFAS No. 133. We entered into this contract in March 2002 and
+closed it out in December 2002. Derivative gain in the consolidated statements
+of operations includes $3.6 million of net gain from the termination of this
+contract.
+Accounting Matters
+In December 2002 the Financial Accounting Standards Board issued SFAS
+No. 148, "Accounting for Stock-Based Compensation -- Transition and Disclosure:
+an amendment of FASB Statement No. 123." This statement amends SFAS No. 123,
+"Accounting for Stock-Based Compensation", to provide alternative methods of
+transition for a voluntary change to the fair value based method of accounting
+for stock-based employee compensation. In addition, this statement amends the
+disclosure requirements of SFAS No. 123 to require prominent disclosures in both
+annual and interim financial statements about the method of accounting for
+53
+stock-based employee compensation and the effect of the method used on reported
+results. The statement is effective for financial statements for fiscal years
+ending after December 15, 2002. We will continue to account for stock-based
+compensation using the methods detailed in Accounting Principles Board Opinion
+No.25, "Accounting for Stock Issued to Employees."
+In June 2002 the FASB issued SFAS No. 146, "Accounting for Costs
+Associated with Exit or Disposal Activities." This statement addresses financial
+accounting and reporting for costs associated with exit or disposal activities
+and requires recognition of a liability for a cost associated with an exit or
+disposal activity when the liability is incurred, as opposed to when the entity
+commits to an exit plan. SFAS No. 146 is to be applied prospectively to exit or
+disposal activities initiated after December 31, 2002. We do not have any
+pending or planned exit or disposal activities and do not expect a material
+effect on our financial position or results of operations from the adoption of
+this statement.
+In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB
+Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
+Corrections." SFAS No. 145 requires that gains and losses from extinguishment of
+debt be evaluated under the provisions of Accounting Principles Board Opinion
+No. 30 and be classified as ordinary items unless they are unusual or infrequent
+or meet the specific criteria for treatment as an extraordinary item. This
+statement is effective for fiscal years beginning after May 15, 2002. We do not
+anticipate that the adoption of this statement will have a material effect on
+our financial position or results of operations.
+In July 2001 the FASB issued SFAS No. 143, "Accounting for
+Asset Retirement Obligations." This statement requires companies to recognize
+the fair value of an asset retirement liability in the financial statements by
+capitalizing that cost as part of the cost of the related long-lived asset. The
+asset retirement liability should then be allocated to expense by using a
+systematic and rational method. The statement is effective January 1, 2003. We
+have not determined the impact of adoption of this statement.
+Effects of Inflation and Changing Prices
+Within the United States in 2002 and 2001 general cost inflation had an
+effect on St. Mary as reflected in increased drilling costs and lease operating
+costs. We cannot predict the future extent of any such effect.
+St. Mary's results of operations and cash flows are affected by
+material changes in oil and gas prices. Oil and gas prices are strongly impacted
+by North American influences on natural gas and global influences on oil in
+relation to supply and demand for petroleum products. Oil and gas prices are
+further impacted by the quality of the oil and gas to be sold and the location
+of our producing properties in relation to markets for our products. Oil and gas
+price increases or decreases have a corresponding effect on our revenues from
+oil and gas sales. Oil and gas prices also affect the prices charged for
+drilling and related services. As oil and gas prices increase, revenues increase
+and there is usually a corresponding increase in our costs of drilling and
+related services. Also as oil and gas prices increase, the cost of acquiring
+producing properties increases, which could limit the number and accessibility
+of quality properties on the market.
+Material changes in oil and gas prices affect the current and future
+value of our estimated proved reserves and our borrowing capability, which is
+largely based on the value of such proved reserves. More stable natural gas and
+oil prices characterized most of 2002. Rig costs and operating costs decreased
+slightly. At the end of the year, in spite of a weakened economy, less than
+54
+normal gas in storage, cold weather, a continuing petroleum industry strike in
+Venezuela and the possibility of escalating conflict in the Middle East are
+causing both oil and natural gas prices to increase. However, higher oil and gas
+prices have not caused rig utilization to increase to the extent many expected.
+In the near-term we do not expect competition for these limited resources to
+increase, but continued high prices will encourage development activity and
+could result in increases in the cost of both materials and personnel and
+corresponding effects on the cost to explore for, drill for and produce oil and
+gas. We continue to have good relationships with our vendors due to our
+reputation for timely payment of invoices, a positive by-product of our strong
+balance sheet.
+Environmental
+St. Mary's compliance with applicable environmental regulations has not
+resulted in any significant capital expenditures or materially adverse effects
+to our liquidity or results of operations. We believe we are in substantial
+compliance with environmental regulations and foresee that no material
+expenditures will be incurred in the future. However, we are unable to predict
+the impact that future compliance with regulations may have on future capital
+expenditures, liquidity and results of operations.
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
+We hold derivative contracts and financial instruments that have cash
+flow and net income exposure to changes in commodity prices or interest rates.
+Financial and commodity-based derivative contracts are used to limit the risks
+inherent in some crude oil and natural gas price changes that have an effect on
+us.
+Our board of directors has adopted a policy regarding the use of
+derivative instruments. This policy requires every derivative used by St. Mary
+to relate to underlying offsetting positions, anticipated transactions or firm
+commitments. It prohibits the use of speculative, highly complex or leveraged
+derivatives. Under the policy, the Chief Executive Officer and Vice President of
+Finance must review and approve all risk management programs that use
+derivatives. The board of directors and the audit committee periodically review
+these programs.
+Commodity Price Risk. We use various hedging arrangements to manage our
+exposure to price risk from natural gas and crude oil production. These hedging
+arrangements have the effect of locking in for specified periods, at
+predetermined prices or ranges of prices, the prices we will receive for the
+volumes to which the hedge relates. Consequently, while these hedging
+arrangements are structured to reduce our exposure to decreases in prices
+associated with the hedged commodity, they also limit the benefit we might
+otherwise receive from any price increases associated with the hedged commodity.
+The derivative gain or loss effectively offsets the loss or gain on the
+underlying commodity exposures that have been hedged. The fair value of the
+swaps are estimated based on quoted market prices of comparable contracts and
+approximate the net gains or losses that would have been realized if the
+contracts had been closed out at year-end. The fair values of the futures are
+based on quoted market prices obtained from the New York Mercantile Exchange
+adjusted fpr basis differentials.
+For contracts in place on December 31, 2002, a hypothetical $0.10
+change in the future NYMEX strip prices applied to a notional amount of 12.4
+million MMBtu covered by natural gas swaps would cause a change in the gain or
+(loss) from these contracts of $853,000 in 2003 and $321,000 in 2004. A
+hypothetical $1.00 change in future NYMEX oil prices applied to a notional
+amount of 2.5 MMBbls covered by crude oil swaps would cause a change in the gain
+55
+or (loss) from these contracts of $1.7 million in 2003 and $654,000 in 2004.
+These hypothetical changes were discounted to present value using a 7.5%
+discount rate since the latest expected maturity date of some of the swaps and
+futures contracts is greater than one year from the reporting date.
+Interest Rate Risk. Market risk is estimated as the potential change in
+fair value resulting from an immediate hypothetical one-percentage point
+parallel shift in the yield curve. The sensitivity analysis presents the
+hypothetical change in fair value of those financial instruments we held at
+December 31, 2002, that are sensitive to changes in interest rates. For
+fixed-rate debt, interest rate changes affect the fair market value but do not
+impact results of operations or cash flows. Conversely for floating-rate debt,
+interest rate changes generally do not affect the fair market value but do
+impact future results of operations and cash flows, assuming other factors are
+held constant. The carrying amount of our floating rate debt approximates its
+fair value. At December 31, 2002, we had floating-rate debt of $14.0 million and
+had $100.0 million of fixed-rate debt. Assuming constant debt levels, the cash
+flow impact for the next year resulting from a one-percentage point change in
+interest rates would be approximately $140,000 before taxes. The results of
+operations impact might be less than this amount as a direct effect of the
+capitalization of interest to wells drilled in the next year. In prior years
+when our debt amount was at a reduced level we capitalized a large portion of
+our interest expense. Since we cannot predict the exact amount that would be
+capitalized, we cannot predict the exact effect that a one-percentage point
+shift would have on the results of operations.
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
+The Consolidated Financial Statements that constitute Item 8 follow the
+text of this report. An index to the Consolidated Financial Statements and
+Schedules appears in Item 14(a) of this report.
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
+ACCOUNTING AND FINANCIAL DISCLOSURE
+As previously reported in our current reports on Form 8-K filed with
+the SEC on May 30, 2002 and June 5, 2002, on May 23, 2002 we dismissed Arthur
+Andersen LLP as our independent accountants and on June 3, 2002 we engaged
+Deloitte & Touche LLP as our new independent accountants. The St. Mary audit
+committee and board of directors approved this change in accountants.
+PART III
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
+The information required by this Item concerning St. Mar's directors is
+incorporated by reference to the information provided under the captions
+"Election of Directors" and "Nominees for Election of Directors" in St. Mary's
+definitive proxy statement for the 2003 annual meeting of stockholders to be
+filed within 120 days from December 31, 2002. The information required by this
+Item concerning St. Mary's executive officers is incorporated by reference to
+the information provided in Part I-Item 4A-Executive Officers of the Registrant,
+included in this Form 10-K.
+The information required by this Item concerning compliance with
+Section 16(a) of the Securities Exchange Act of 1934 is incorporated by
+reference to the information provided under the caption "Section 16(a)
+Beneficial Ownership Reporting Compliance" in St. Mary's definitive proxy
+56
+statement for the 2003 annual meeting of stockholders to be filed within 120
+days from December 31, 2002.
+ITEM 11. EXECUTIVE COMPENSATION
+The information required by this Item is incorporated by reference to
+the information provided under the captions, "Director Compensation," "Executive
+Compensation," "Report of the Compensation Committee on Executive Compensation,"
+"Retirement Plans," "Performance Graph," and "Employee Agreements and
+Termination of Employment and Change-in-Control Arrangements" in St. Mary's
+definitive proxy statement for the 2003 annual meeting of stockholders to be
+filed within 120 days from December 31, 2002.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
+MANAGEMENT AND RELATED STOCKHOLDER MATTERS
+The information required by this Item concerning security ownership of
+certain beneficial owners and management is incorporated by reference to the
+information provided under the caption "Security Ownership of Certain Beneficial
+Owners and Management" in St. Mary's definitive proxy statement for the 2003
+annual meeting of stockholders to be filed within 120 days from December 31,
+2002.
+The information required by this Item concerning securities authorized
+for issuance under equity compensation plans is incorporated by reference to the
+information provided under the caption "Equity Compensation Plans" in Part II -
+Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters,
+included in this form 10-K.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+The information required by this Item is incorporated by reference to
+the information provided under the caption "Certain Relationships and Related
+Transactions" in St. Mary's definitive proxy statement for the 2003 annual
+meeting of stockholders to be filed within 120 days from December 31, 2002.
+ITEM 14. CONTROLS AND PROCEDURES
+We maintain a system of disclosure controls and procedures that are
+designed for the purposes of ensuring that information required to be disclosed
+in our SEC reports is recorded, processed, summarized and reported within the
+time periods specified in the SEC's rules and forms, and that such information
+is accumulated and communicated to our management, including the Chief Executive
+Officer and the Vice-President - Finance, as appropriate to allow timely
+decisions regarding required disclosure.
+Within the 90-day period prior to the filing of this report, we carried
+out an evaluation, under the supervision and with the participation of our
+management, including the Chief Executive Officer and the Vice-President -
+Finance, of the effectiveness of the design and operation of our disclosure
+controls and procedures. Based upon that evaluation, the Chief Executive Officer
+and the Vice-President - Finance concluded that our disclosure controls and
+procedures are effective for the purposes discussed above. There have been no
+significant changes in our internal controls or in other factors that could
+significantly affect these controls subsequent to the date of the evaluation.
+57
+PART IV
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
+(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:
+Reports of Independent Auditors....................................F-1
+Reports of Independent Public Accountants..........................F-2
+Consolidated Balance Sheets........................................F-3
+Consolidated Statements of Operations..............................F-4
+Consolidated Statements of Stockholders' Equity and
+Comprehensive Income........................................... F-5
+Consolidated Statements of Cash Flows..............................F-6
+Notes to Consolidated Financial Statements.........................F-8
+All other schedules are omitted because the required information is not
+applicable or is not present in amounts sufficient to require submission of the
+schedule or because the information required is included in the Consolidated
+Financial Statements and Notes thereto.
+(b) Reports on Form 8-K.
+St. Mary Land & Exploration Company filed the following current
+reports on Form 8-K during the quarter ended December 31, 2002:
+On October 3, 2002, we filed a current report on Form 8-K reporting
+under Item 5 that we had signed a Purchase and Sale Agreement to acquire oil and
+gas properties from Burlington Resources Oil & Gas Company LP.
+On November 7, 2002, we filed a current report on Form 8-K reporting
+under Item 9 that we had issued a press release announcing our earnings and
+financial highlights for the third quarter of 2002.
+On November 20, 2002, we filed a current report on Form 8-K reporting
+under Item 9 that in connection with the filing of the Form 10-Q on November 13,
+2002, the Chief Executive Officer and the Vice-President - Finance of the
+registrant each signed a Certification pursuant to Section 906 of the Sarbanes -
+Oxley Act of 2002.
+On December 12, 2002, we filed a current report on Form 8-K reporting
+under Item 2 that on December 3, 2002, we purchased oil and gas properties from
+Burlington Resources Oil & Gas Company LP.
+On December 16, 2002, we filed a current report on Form 8-K reporting
+under Item 5 that we had issued a press release announcing an agreement to
+acquire oil and gas properties from Flying J Oil & Gas and Big West Oil
+& Gas.
+(c) Exhibits. The following exhibits are filed with or incorporated by
+reference into this report on Form 10-K:
+58
+Exhibit
+Number Description
+------- -----------
+2.1 Agreement and Plan of Merger dated July 27, 1999 among St.
+Mary Land & Exploration Company, St. Mary Acquisition
+Corporation, King Ranch, Inc. and King Ranch Energy, Inc. as
+amended by Amendment No. 1 and Amendment No. 2 to Agreement
+and Plan of Merger dated November 8, 1999 (included as Annex A
+to the joint proxy/consent statement and prospectus contained
+in the registrant's Amendment No. 2 to Form S-4/A
+(Registration No. 333-85537) filed on November 12, 1999 and
+incorporated herein by reference)
+2.2 Stock Exchange Agreement dated June 1, 1999 among St. Mary
+Land & Exploration Company, Robert L. Nance, Penni W.
+Nance, Amy Nance Cebull and Robert Scott Nance (filed as
+Exhibit 10.27 to the registrant's Registration Statement on
+Form S-4 (Registration No. 333-85537) filed on August 19, 1999
+and incorporated herein by reference)
+2.3 Stock Exchange Agreement dated June 1, 1999 among St. Mary
+Land & Exploration Company, Robert L. Nance and Robert T.
+Hanley (filed as Exhibit 10.28 to the registrant's
+Registration Statement on Form S-4 (Registration No.
+333-85537) filed on August 19, 1999 and incorporated herein by
+reference)
+2.4 Stock Exchange Agreement dated June 1, 1999 between St. Mary
+Land & Exploration Company and Robert T. Hanley (filed as
+Exhibit 10.29 to the registrant's Registration Statement on
+Form S-4 (Registration No. 333-85537) filed on August 19, 1999
+and incorporated herein by reference)
+3.1 Restated Certificate of Incorporation of St. Mary Land &
+Exploration Company as amended in May 2001 (filed as Exhibit
+3.1 to the registrant's Quarterly Report on Form 10-Q for the
+quarter ended September 30, 2001 and incorporated herein by
+reference)
+3.2 Restated By-Laws of St. Mary Land & Exploration Company as
+amended in July 2001 (filed as Exhibit 3.1 to the registrant's
+Quarterly Report on Form 10-Q (File No. 0-20872) for the
+quarter ended September 30, 2001 and incorporated herein by
+reference)
+4.1 St. Mary Land & Exploration Company Shareholder Rights
+Plan adopted on July 15, 1999 (filed as Exhibit 4.1 to the
+registrant's Quarterly Report on Form 10-Q/A (File No.
+0-20872) for the quarter ended June 30, 1999 and incorporated
+herein by reference)
+4.2 First Amendment to Shareholders Rights Plan dated March 15,
+2002 as adopted by the Board of Directors on July 19, 2001
+(filed as Exhibit 4.2 to the registrant's Annual Report on
+Form 10-K (File No. 0-20872) for the year ended December 31,
+2001 and incorporated herein by reference)
+10.1 Stock Option Plan (filed as Exhibit 10.3 to the registrant's
+Registration Statement on Form S-1 (Registration No. 33-53512)
+and incorporated herein by reference)
+10.2 Stock Appreciation Rights Plan (filed as Exhibit 10.4 to the
+registrant's Registration Statement on Form S-1 (Registration
+No. 33-53512) and incorporated herein by reference)
+10.3 Cash Bonus Plan (filed as Exhibit 10.5 to the registrant's
+Registration Statement on Form S-1 (Registration No. 33-53512)
+and incorporated herein by reference)
+10.4 Net Profits Interest Bonus Plan, As Amended on September 19,
+1996 and July 24, 1997 and January 28, 1999 filed as Exhibit
+10.3 to registrant's Quarterly Report on Form 10-Q (File No.
+0-20872) for the quarter ended March 31, 1999 and incorporated
+herein by reference)
+59
+Exhibit
+Number Description
+------- -----------
+10.5 Summary Plan Description/Pension Plan dated December 30, 1994
+(filed as Exhibit 10.35 to the registrant's Annual Report on
+Form 10-K (File No. 0-20872) for the year ended December 31,
+1994 and incorporated herein by reference)
+10.6 Non-qualified Unfunded Supplemental Retirement Plan, as
+amended (filed as Exhibit 10.8 to the registrant's
+Registration Statement on Form S-1 (Registration No. 33-53512)
+and incorporated herein by reference)
+10.7 Summary Plan Description 401(k) Profit Sharing Plan (filed as
+Exhibit 10.34 to the registrant's Annual Report on Form 10-K
+(File No. 0-20872) for the year ended December 31, 1994 and
+incorporated herein by reference)
+10.8 St. Mary Land & Exploration Company Stock Option Plan, As
+Amended on March 29, 2001 (filed as Exhibit 99.1 to
+registrant's Registration Statement on Form S-8 (Registration
+No. 333-88780) and incorporated herein by reference)
+10.9 St. Mary Land & Exploration Company Incentive Stock Option
+Plan, As Amended on March 29, 2001 (filed as Exhibit 99.2 to
+registrant's Registration Statement on Form S-8 (Registration
+No. 333-88780) and incorporated herein by reference)
+10.10 St. Mary Land & Exploration Company Employee Stock
+Purchase Plan (filed as Exhibit 10.48 filed to the
+registrant's Annual Report on Form 10-K (File No. 0-20872) for
+the year ended December 31, 1997 and incorporated herein by
+reference)
+10.11 First Amendment to St. Mary Land & Exploration Company
+Employee Stock Purchase Plan dated February 27, 2001 (filed as
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
+(file No. 0-20872) for the quarter ended June 30, 2001 and
+incorporated herein by reference)
+10.12 Form of Change of Control Severance Agreements (filed as
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
+(File No. 0-20872) for the quarter ended September 30, 2001
+and incorporated herein by reference)
+10.13 Employment Agreement between Registrant and Mark A.
+Hellerstein (filed as Exhibit 10.15 to the registrant's
+Registration Statement on Form S-1 (Registration No. 33-53512)
+and incorporated herein by reference)
+10.14 Credit Agreement dated June 30, 1998 (filed as Exhibit 10.52
+to the registrant's Quarterly Report on Form 10-Q (File No.
+0-20872) for the quarter ended June 30, 1998 and incorporated
+herein by reference)
+10.15 Second Amendment to Credit Agreement dated June 27, 2000
+(filed as Exhibit 10.1 to the registrant's Quarterly Report on
+Form 10-Q (File No. 0-20872) for the quarter ended June 30,
+2000 and incorporated herein by reference)
+10.16 Third Amendment to Credit Agreement dated April 30, 2001
+(filed as Exhibit 10.2 to the registrant's Quarterly Report on
+Form 10-Q (File No. 0-20872) for the quarter ended June 30,
+2001 and incorporated herein by reference)
+10.17 Loan and Stock Purchase Agreement dated June 25, 1999 among
+Resource Capital Fund L.P., St. Mary Land & Exploration
+Company and St. Mary Minerals Inc. (filed as Exhibit 10.30 to
+the registrant's Registration Statement on Form S-4
+(Registration No. 333-85537) filed on August 19, 1999 and
+incorporated herein by reference)
+10.18 Credit Agreement dated June 25, 1999 among Summo Minerals
+Corporation, Summo USA Corporation, Resource Capital Fund L.P.
+and St. Mary Minerals Inc. (filed as Exhibit 10.31 to the
+registrant's Registration Statement on Form S-4 (Registration
+60
+Exhibit
+Number Description
+------- -----------
+No. 333-85537) filed on August 19, 1999 and incorporated
+herein by reference)
+10.19 Replacement Promissory Note dated June 25, 1999 payable to St.
+Mary Minerals Inc. in the amount of $1,400,000 (filed as
+Exhibit 10.32 to the registrant's Registration Statement on
+Form S-4 (Registration No. 333-85537) filed on August 19, 1999
+and incorporated herein by reference)
+10.20 Pledge and Security Agreement dated June 25, 1999 among Summo
+Minerals Corporation, Resource Capital Fund L.P., and St. Mary
+Minerals Inc. (filed as Exhibit 10.33 to the registrant's
+Registration Statement on Form S-4 (Registration No.
+333-85537) filed on August 19, 1999 and incorporated herein by
+reference)
+10.21 Pledge and Security Agreement dated June 25, 1999 among Summo
+USA Corporation, Resource Capital Fund L.P., and St. Mary
+Minerals Inc. (filed as Exhibit 10.34 to the registrant's
+Registration Statement on Form S-4 (Registration No.
+333-85537) filed on August 19, 1999 and incorporated herein by
+reference)
+10.22 Warrant Agreement dated June 25, 1999 among Summo Minerals
+Corporation, Resource Capital Fund L.P. and St. Mary Minerals
+Inc. (filed as Exhibit 10.35 to the registrant's Registration
+Statement on Form S-4 (Registration No. 333-85537) filed on
+August 19, 1999 and incorporated herein by reference)
+10.23 Agreement of Sale and Purchase dated October 16, 2000,
+effective as of September 1, 2000, between JN Exploration and
+Production Limited Partnership, Colt Resources Corporation,
+Princeps Partners, Inc., and The William G. Helis Company, LLC
+(collectively, "JN et al") and St. Mary Land & Exploration
+Company (filed as Exhibit 10.1 to the registrant's Current
+Report on Form 8-K (File No. 0-20872) dated January 5, 2001
+and incorporated herein by reference)
+10.24 Purchase and Sale Agreement dated September 28, 2001,
+effective as of September 1, 2001; between Choctaw II Oil
+& Gas, LTD and Nance Petroleum Corporation (filed as
+Exhibit 10.1 to the registrant's Current Report on Form 8-K
+(File No. 0-20872) dated December 10, 2001 and incorporated
+herein by reference)
+10.25 Registration Rights Agreement between St. Mary Land &
+Exploration Company and Bear, Stearns & Co. Inc., et al
+dated March 13, 2002 (filed as Exhibit 10.25 to the
+registrant's Annual Report on Form 10-K (File No. 0-20872) for
+the year ended December 31, 2001 and incorporated herein by
+reference)
+10.26 St. Mary Land & Exploration Company 5.75% Senior
+Convertible Notes Due 2002 Indenture dated March 13, 2002
+(filed as Exhibit 10.26 to the registrant's Annual Report on
+Form 10-K (File No. 0-20872) for the year ended December 31,
+2001 and incorporated herein by reference)
+10.27 First Amendment to Credit Agreement dated December 22, 1998
+(filed as Exhibit 10.27 to the registrant's Annual Report on
+Form 10-K (File No. 0-20872) for the year ended December 31,
+2001 and incorporated herein by reference)
+10.28 Fourth Amendment to Credit Agreement dated March 4, 2002
+(filed as Exhibit 10.28 to the registrant's Annual Report on
+Form 10-K (File No. 0-20872) for the year ended December 31,
+2001 and incorporated herein by reference)
+10.29 Purchase and Sale Agreement dated October 1, 2002, effective
+as of July 1, 2002; between Burlington Resources Oil & Gas
+Company LP and The Louisiana Land and Exploration Company and
+Nance Petroleum Corporation (filed as Exhibit 10.1 to the
+61
+Exhibit
+Number Description
+------- -----------
+registrant's Current Report on Form 8-K (File No. 001-31539)
+filed on December 12, 2002 and incorporated herein by
+reference )
+10.30 Purchase and Sale Agreement dated as of December 13, 2002
+among Flying J Oil & Gas Inc., Big West Oil & Gas
+Inc., NPC Inc. and St. Mary Land & Exploration Company
+(filed as Exhibit 10.1 to the registrant's Current Report on
+Form 8-K (File No. 001-31539) filed on February 13, 2003 and
+incorporated herein by reference)
+10.31 Addendum dated January 29, 2003 to Purchase and Sale Agreement
+dated December 13, 2002 (filed as Exhibit 10.2 to the
+registrant's Current Report on Form 8-K (File No. 001-31539)
+filed on February 13, 2003 and incorporated herein by
+reference)
+10.32 Nonrecourse Secured Promissory Note dated January 29, 2003 by
+Flying J Oil & Gas Inc. and Big West Oil & Gas Inc.
+(filed as Exhibit 10.3 to the registrant's Current Report on
+Form 8-K (File No. 001-31539) filed on February 13, 2003 and
+incorporated herein by reference)
+10.33 Stock Pledge Agreement from Flying J Oil & Gas Inc. and
+Big West Oil & Gas Inc. to St. Mary Land & Exploration
+Company executed as of January 29, 2003 (filed as Exhibit 10.4
+to the registrant's Current Report on Form 8-K (File No.
+001-31539) filed on February 13, 2003 and incorporated herein
+by reference)
+10.34 Registration Rights Agreement dated as of January 29, 2003
+among St. Mary Land & Exploration Company, Flying J Oil
+& Gas Inc. and Big West Oil & Gas Inc. (filed as
+Exhibit 10.5 to the registrant's Current Report on Form 8-K
+(File No. 001-31539) filed on February 13, 2003 and
+incorporated herein by reference)
+10.35 Put and Call Option Agreement dated as of January 29, 2003
+among St. Mary Land & Exploration Company, Flying J Oil
+& Gas Inc. and Big West Oil & Gas Inc. (filed as
+Exhibit 10.6 to the registrant's Current Report on Form 8-K
+(File No. 001-31539) filed on February 13, 2003 and
+incorporated herein by reference)
+10.36 Standstill Agreement dated as of January 29, 2003 among St.
+Mary Land & Exploration Company, Flying J Oil & Gas
+Inc. and Big West Oil & Gas Inc. (filed as Exhibit 10.7 to
+the registrant's Current Report on Form 8-K (File No.
+001-31539) filed on February 13, 2003 and incorporated herein
+by reference) 10.37 Share Transfer Restriction Agreement dated
+as of January 29, 2003 among St. Mary Land & Exploration
+Company, Flying J Oil & Gas Inc. and Big West Oil &
+Gas Inc. (filed as Exhibit 10.8 to the registrant's Current
+Report on Form 8-K (File No. 001-31539) filed on February 13,
+2003 and incorporated herein by reference)
+10.38 Indemnity Guarantee Agreement dated January 29, 2003 between
+NPC Inc. and Flying J Inc. (filed as Exhibit 10.9 to the
+registrant's Current Report on Form 8-K (File No. 001-31539)
+filed on February 13, 2003 and incorporated herein by
+reference)
+10.39 Promissory Note dated July 21, 2000 and Letter Agreement dated
+July 21, 2000 for $200,000 Relocation Loan to Robert T. Hanley
+(filed as Exhibit 10.29 to the registrant's Annual Report on
+Form 10-K/A No. 2 (File No. 0-20872) for the year ended
+December 31, 2001 and incorporated herein by reference)
+10.40 Security Agreement made as of May 1, 2002 by St. Mary Land
+& Exploration Company, St. Mary Operating Company, St.
+Mary Energy Company, Nance Petroleum Corporation, St. Mary
+Minerals Inc., Parish Corporation, Four Winds Marketing LLC,
+and Roswell LLC, in favor of Bank of America, N.A. (filed as
+62
+Exhibit
+Number Description
+------- -----------
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
+(File No. 000-20872) for the quarter ended June 30, 2002 and
+incorporated herein by reference)
+10.41 Stock Pledge Agreement made as of May 1, 2002 by St. Mary Land
+& Exploration Company in favor of Bank of America, N.A.
+(filed as Exhibit 10.2 to the registrant's Quarterly Report on
+Form 10-Q (File No. 000-20872) for the quarter ended June 30,
+2002 and incorporated herein by reference)
+10.42 LLC Pledge Agreement made as of May 1, 2002 by St. Mary Land
+& Exploration Company in favor of Bank of America, N.A.
+(filed as Exhibit 10.3 to the registrant's Quarterly Report on
+Form 10-Q (File No. 000-20872) for the quarter ended June 30,
+2002 and incorporated herein by reference)
+10.43 Guaranty made as of May 1, 2002 by St. Mary Operating Company,
+St. Mary Energy Company, Nance Petroleum Corporation, St. Mary
+Minerals, Inc., Parish Corporation, Four Winds Marketing LLC
+and Roswell LLC in favor of Bank of America, N.A. (filed as
+Exhibit 10.4 to the registrant's Quarterly Report on Form 10-Q
+(File No. 000-20872) for the quarter ended June 30, 2002 and
+incorporated herein by reference)
+10.44* Credit Agreement dated as of January 27, 2003 among St. Mary
+Land & Exploration Company, Wachovia Bank, National
+Association of Administrative Agent, and the Lenders party
+thereto
+10.45* Amendment to and Extension of Office Lease dated as of
+December 14, 2001
+12.1* Computation of Ratios of Earnings to Fixed Charges
+16.1 Letter by Arthur Andersen LLP to the Securities and Exchange
+Commission dated May 28, 2002 (filed as Exhibit 16.1 to the
+registrant's Current Report on Form 8-K (File No. 000-20872)
+filed on May 30, 2002 and incorporated herein by reference)
+21.1* Subsidiaries of Registrant
+23.1* Consent of Deloitte & Touche LLP
+23.2* Information About Lack of Consent of Arthur Andersen LLP
+23.3* Consent of Ryder Scott Company, L.P.
+24.1* Power of Attorney (included in signature page hereof)
+------------------------------
+* Filed with this Form 10-K.
+(d) Financial Statement Schedules. See Item 14(c) above.
+63
+INDEPENDENT AUDITORS' REPORT
+To the Board of Directors and Stockholders of
+St. Mary Land & Exploration Company and Subsidiaries
+We have audited the accompanying consolidated balance sheet of St. Mary Land
+& Exploration Company and subsidiaries as of December 31, 2002, and the
+related consolidated statements of operations, stockholders' equity and
+comprehensive income, and cash flows for the year then ended. These financial
+statements are the responsibility of the Company's management. Our
+responsibility is to express an opinion on these financial statements based on
+our audit. The Company's consolidated financial statements for each of the years
+in the two-year period ended December 31, 2001, were audited by other auditors
+who have ceased operations. Those auditors expressed an unqualified opinion on
+those consolidated financial statements in their report dated February 18, 2002,
+which report included an explanatory paragraph for the change in method of
+accounting for derivative instruments and hedging activities on January 1, 2001.
+We conducted our audit in accordance with auditing standards generally accepted
+in the United States of America. Those standards require that we plan and
+perform the audit to obtain reasonable assurance about whether the financial
+statements are free of material misstatement. An audit includes examining, on a
+test basis, evidence supporting the amounts and disclosures in the financial
+statements. An audit also includes assessing the accounting principles used and
+significant estimates made by management, as well as evaluating the overall
+financial statement presentation. We believe that our audit provides a
+reasonable basis for our opinion.
+In our opinion, such consolidated financial statements present fairly, in all
+material respects, the financial position of the Company as of December 31,
+2002, and the results of its operations and its cash flows for the year then
+ended in conformity with accounting principles generally accepted in the United
+States of America.
+/s/ DELOITTE & TOUCHE LLP
+Denver, Colorado
+February 19, 2003
+F-1
+REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
+To the Board of Directors and Stockholders of
+St. Mary Land & Exploration Company and Subsidiaries:
+We have audited the accompanying consolidated balance sheets of St. Mary
+Land & Exploration Company (a Delaware corporation) and subsidiaries as
+of December 31, 2001 and 2000, and the related consolidated statements of
+operations, stockholders' equity and comprehensive income, and cash flows
+for each of the three years in the period ended December 31, 2001. These
+financial statements are the responsibility of the Company's management.
+Our responsibility is to express an opinion on these financial statements
+based on our audits.
+We conducted our audits in accordance with auditing standards generally
+accepted in the United States. Those standards require that we plan and
+perform the audit to obtain reasonable assurance about whether the
+financial statements are free of material misstatement. An audit includes
+examining, on a test basis, evidence supporting the amounts and
+disclosures in the financial statements. An audit also includes assessing
+the accounting principles used and significant estimates made by
+management, as well as evaluating the overall financial statement
+presentation. We believe that our audits provide a reasonable basis for
+our opinion.
+In our opinion, the consolidated financial statements referred to above
+present fairly, in all material respects, the financial position of St.
+Mary Land & Exploration Company and subsidiaries as of December 31, 2001
+and 2000, and the results of their operations and their cash flows for
+each of the three years in the period ended December 31, 2001, in
+conformity with accounting principles generally accepted in the United
+States.
+As explained in Notes 1 and 10 to the consolidated financial statements,
+the Company changed its method of accounting for derivative instruments
+and hedging activities on January 1, 2001.
+/s/ ARTHUR ANDERSEN LLP
+Denver, Colorado,
+February 18, 2002.
+NOTE: This Report of Independent Public Accountants dated February 18, 2002 by
+Arthur Andersen LLP is a copy of the report previously issued by Arthur Andersen
+LLP and included with Arthur Andersen LLP's consent in the Annual Report on Form
+10-K for the year ended December 31, 2001 filed with the SEC on March 19, 2002
+and the Annual Report on Form 10-K/A for the year ended December 31, 2001 filed
+with the SEC on March 25, 2002. Such report has not been reissued by Arthur
+Andersen LLP for inclusion with this Annual Report on Form 10-K for the year
+ended December 31, 2002. After reasonable efforts, St. Mary Land &
+Exploration Company has been unable to obtain a reissued report of Arthur
+Andersen LLP for inclusion with this Form 10-K, and in reliance on Rule 2-02(e)
+of Regulation S-X promulgated by the SEC is including a copy of the previously
+issued report with this Form 10-K.
+F-2
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED BALANCE SHEETS
+(In thousands, except share amounts)
+December 31,
+-----------------------------
+ASSETS 2002 2001
+------------ ------------
+Current assets:
+Cash and cash equivalents $ 11,154 $ 4,116
+Short-term investments 1,933 -
+Accounts receivable 35,399 46,484
+Prepaid expenses and other 6,510 2,337
+Accrued derivative asset - 8,194
+Refundable income taxes 1,031 11,061
+Deferred income taxes 3,520 29
+------------ ------------
+Total current assets 59,547 72,221
+------------ ------------
+Property and equipment (successful efforts
+method), at cost:
+Proved oil and gas properties 683,752 518,912
+Less accumulated depletion, depreciation
+and amortization (263,436) (216,288)
+Unproved oil and gas properties, net of
+impairment allowance of $8,865 in 2002
+and $8,908 in 2001 47,984 53,054
+Other property and equipment, net of
+accumulated depreciation of $3,586 in
+2002 and $3,120 in 2001 3,639 3,252
+------------ ------------
+471,939 358,930
+------------ ------------
+------------ ------------
+Other noncurrent assets 5,653 5,838
+------------ ------------
+------------ ------------
+Total Assets $ 537,139 $ 436,989
+============ ============
+LIABILITIES AND STOCKHOLDERS' EQUITY
+Current liabilities:
+Accounts payable and accrued expenses $ 48,790 $ 34,858
+Accrued derivative liability 8,707 -
+Deferred income taxes - 3,363
+------------ ------------
+Total current liabilities 57,497 38,221
+------------ ------------
+Noncurrent liabilities:
+Long-term credit facility 14,000 64,000
+Convertible notes 99,601 -
+Deferred income taxes 60,156 47,685
+Other noncurrent liabilities 5,727 255
+------------ ------------
+Total noncurrent liabilities 179,484 111,940
+------------ ------------
+Commitments and contingencies (Notes 1,6,7,8)
+------------ ------------
+Minority interest 645 711
+------------ ------------
+Stockholders' equity:
+Common stock, $0.01 par value: authorized
+-100,000,000 shares; issued - 28,983,110
+shares in 2002 and 28,779,808 shares in
+2001; outstanding - 27,973,210 shares in
+2002 and 27,769,908 shares in 2001 290 288
+Additional paid-in capital 140,688 137,384
+Treasury stock - at cost: 1,009,900 shares
+in 2002 and 2001 (16,210) (16,210)
+Retained earnings 182,512 157,739
+Accumulated other comprehensive income
+(loss) (7,767) 6,916
+------------ ------------
+Total stockholders' equity 299,513 286,117
+------------ ------------
+Total Liabilities and Stockholders' Equity $ 537,139 $ 436,989
+============ ============
+The accompaying notes are an integral part
+of these consolidated financial statements.
+F-3
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED STATEMENTS OF OPERATIONS
+(In thousands, except per share amounts)
+For the Years Ended December 31,
+----------------------------------------------
+2002 2001 2000
+------------ ------------ ------------
+Operating revenues:
+Oil and gas production $ 185,670 $ 203,973 $ 188,407
+Gain (loss) on sale of proved properties (2,633) 367 3,404
+Marketed gas revenue 8,399 420 -
+Other oil and gas revenue 682 2,166 1,421
+Derivative gain 3,188 - -
+Other revenues 1,088 543 2,434
+------------ ------------ ------------
+Total operating revenues 196,394 207,469 195,666
+------------ ------------ ------------
+Operating expenses:
+Oil and gas production 50,839 55,000 38,461
+Depletion, depreciation and amortization 54,432 51,346 40,129
+Exploration 19,501 19,518 9,633
+Impairment of proved properties - 820 4,449
+Abandonment and impairment of unproved
+properties 2,446 3,865 1,841
+General and administrative 14,299 11,762 11,166
+Derivative loss - 1,573 -
+Marketed gas system operating expense 7,982 420 -
+Minority interest and other 1,206 1,253 1,437
+------------ ------------ ------------
+Total operating expenses 150,705 145,557 107,116
+------------ ------------ ------------
+Income from operations 45,689 61,912 88,550
+Nonoperating income (expense):
+Interest income 758 466 897
+Interest expense (3,868) (90) (160)
+------------ ------------ ------------
+Income before income taxes 42,579 62,288 89,287
+Income tax expense 15,019 21,829 33,667
+------------ ------------ ------------
+Net income $ 27,560 $ 40,459 $ 55,620
+============ ============ ============
+Basic net income per common share $ 0.99 $ 1.45 $ 2.00
+Diluted net income per common share $ 0.97 $ 1.42 $ 1.97
+Basic weighted average shares outstanding 27,856 27,973 27,781
+Diluted weighted average shares outstanding 28,391 28,555 28,271
+The accompaying notes are an integral part
+of these consolidated financial statements.
+F-4
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
+(In thousands, except share amounts)
+Accumulated
+Common Stock Additional Treasury Stock Other Total
+------------------- Paid-in Retained ------------------- Comprehensive Stockholders'
+Shares Amount Capital Earnings Shares Amount Income Equity
+---------- -------- ---------- ---------- ---------- -------- ------------- -------------
+Balances, December 31, 1999 27,893,910 $ 279 $ 123,974 $ 67,230 (365,600) $ 2,995) $ 284 $ 188,772
+Comprehensive income:
+Net Income - - - 55,620 - - - 55,620
+Unrealized net loss on marketable
+equity securities available for
+sale - - - - - - (143) (143) ------------
+Total comprehensive income 55,477 ------------
+Cash dividends, $ 0.10 per share - - - (2,775) - - - (2,775)
+Treasury stock purchases - - - - (30,000) (344) - (344)
+Issuance for Employee Stock
+Purchase Plan 32,296 - 311 - - - - 311
+ESPP disqualified distribution - - 3 - - - - 3
+Sale of common stock, including
+income tax benefit of stock
+option exercises 619,220 6 8,597 - - - - 8,603
+Directors' stock compensation 8,400 1 88 - - - - 89
+---------- -------- ---------- ---------- ---------- -------- ------------- -------------
+Balances, December 31, 2000 28,553,826 $ 286 $ 132,973 $ 120,075 (395,600)$ (3,339) $ 141 $ 250,136
+Comprehensive income:
+Net Income - - - 40,459 - - - 40,459
+Unrealized net loss on marketable
+equity securities available for
+sale - - - - - - (132) (132)
+Adoption of SFAS No. 133 (28,587) (28,587)
+Reclass to earnings - - - - - - 21,102 21,102
+Change in derivative instrument
+fair value - - - - - - 14,392 14,392 ------------
+Total comprehensive income 47,234 ------------
+Cash dividends, $ 0.10 per share - - - (2,795) - - - (2,795)
+Treasury stock purchases - - - - (614,300) (12,871) - (12,871)
+Issuance for Employee Stock
+Purchase Plan 29,772 - 575 - - - - 575
+Sale of common stock, including
+income tax benefit of stock
+option exercises 187,810 2 3,598 - - - - 3,600
+Directors' stock compensation 8,400 - 238 - - - - 238
+---------- -------- ---------- ---------- ---------- -------- ------------- -------------
+Balances, December 31, 2001 28,779,808 $ 288 $ 137,384 $ 157,739 (1,009,900)$(16,210) $ 6,916 $ 286,117
+========== ======== ========== ========== ========== ======== ============= =============
+Comprehensive income:
+Net Income - - - 27,560 - - - 27,560
+Unrealized net loss on marketable
+equity securities available for
+sale - - - - - - (725) (725)
+Reclass to earnings - - - - - - 1,447 1,447
+Change in derivative instrument
+fair value - - - - - - (14,644) (14,644)
+Minimum pension liability
+adjustment - - - - - - (761) (761) ------------
+Total comprehensive income 12,877 ------------
+Cash dividends, $ 0.10 per share - - - (2,787) - - - (2,787)
+Issuance for Employee Stock
+Purchase Plan 18,217 - 344 - - - - 344
+ESPP disqualified distribution - - 21 - - - - 21
+Sale of common stock, including
+income tax benefit of stock
+option exercises 177,085 2 2,743 - - - - 2,745
+Accelerated vesing of retiring
+director options - - 52 - - - - 52
+Directors' stock compensation 8,000 - 144 - - - - 144
+---------- -------- ---------- ---------- ---------- -------- ------------- -------------
+Balances, December 31, 2002 28,983,110 $ 290 $ 140,688 $ 182,512 (1,009,900)$(16,210) $ (7,767) $ 299,513
+========== ======== ========== ========== ========== ======== ============= =============
+The accompaying notes are an integral part
+of these consolidated financial statements.
+F-5
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED STATEMENTS OF CASH FLOWS
+(In thousands)
+For the Years Ended December 31,
+----------------------------------------------
+2002 2001 2000
+------------ ------------ ------------
+Reconciliation of net income to net cash
+provided by operating activities:
+Net income $ 27,560 $ 40,459 $ 55,620
+Adjustments to reconcile net income to net
+cash provided by operating
+activities:
+(Gain) loss on sale of proved properties 2,633 (367) (3,404)
+Gain on sale of KMOC stock (836) - (2,156)
+Depletion, depreciation and amortization 54,432 51,346 40,129
+Impairment of proved properties - 820 4,449
+Abandonment and impairment of unproved
+properties 2,446 3,865 1,841
+Unrealized derivative (gain) loss 373 1,573 -
+Deferred income taxes 14,633 23,726 21,348
+Exploratory dry hole expense 7,677 9,028 789
+Minority interest and other 40 (1,327) 1,260
+------------ ------------ ------------
+108,958 129,123 119,876
+Changes in current assets and liabilities:
+Accounts receivable 11,085 (629) (23,138)
+Prepaid expenses and other (4,173) (664) 228
+Refundable income taxes 10,030 (11,061) 26
+Accounts payable and accrued expenses 15,992 10,752 (4,652)
+Current deferred income taxes (183) (29) (73)
+------------ ------------ ------------
+Net cash provided by operating activities 141,709 127,492 92,267
+------------ ------------ ------------
+Cash flows from investing activities:
+Proceeds from sale of oil and gas properties 1,624 4,771 3,573
+Capital expenditures (97,257) (131,680) (65,241)
+Acquisition of oil and gas properties (87,466) (39,124) (52,076)
+Proceeds from distribution and sale of
+KMOC stock 3,114 6,960 -
+Deposits to short term investments
+available-for-sale (13,523) - -
+Receipts from short term investments
+available-for-sale 12,538 - -
+Other 39 (2) 876
+------------ ------------ ------------
+Net cash used in investing activities (180,931) (159,075) (112,868)
+------------ ------------ ------------
+Cash flows from financing activities:
+Proceeds from long-term debt 37,400 147,050 45,050
+Repayment of long-term debt (87,400) (105,050) (36,050)
+Proceeds from convertible debt 96,657 - -
+Proceeds from sale of common stock 2,390 2,746 7,143
+Repurchase of common stock - (12,871) (344)
+Dividends paid (2,787) (2,795) (2,775)
+Other - - 1
+------------ ------------ ------------
+Net cash provided by financing activities 46,260 29,080 13,025
+------------ ------------ ------------
+Net change in cash and cash equivalents 7,038 (2,503) (7,576)
+Cash and cash equivalents at beginning of
+period 4,116 6,619 14,195
+------------ ------------ ------------
+Cash and cash equivalents at end of period $ 11,154 $ 4,116 $ 6,619
+============ ============ ============
+The accompaying notes are an integral part
+of these consolidated financial statements.
+F-6
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
+Supplemental schedule of additional cash flow information and noncash
+activities:
+For the Years Ended December 31,
+----------------------------------------------
+2002 2001 2000
+------------ ------------ ------------
+(in thousands)
+Cash paid for interest, including amounts capitalized $ 2,498 $ 764 $ 916
+Cash paid (received) for income taxes (550) 11,205 92
+In June 2002 the Company issued 800 shares of common stock to a director and
+recorded compensation expense of $14,763.
+In January 2002 the Company issued 7,200 shares of common stock to its
+directors and recorded compensation expense of $129,683.
+In April 2002 the Company accepted 9,472,562 shares of common stock in
+Constellation Copper Corporation ("Constellation", formerly known as Summo
+Minerals Corporation) in lieu of cash payment for the relief of a $1,400,000
+loan and $15,311 in interest due to the Company.
+In January 2001 the Company issued 8,400 shares of common stock to its
+directors and recorded compensation expense of $237,852.
+In June 2000 the Company received equipment valued at $1,202,000 as
+partial proceeds for property sold.
+In January 2000 the Company issued 8,400 shares of common stock to its
+directors and recorded compensation expense of $88,368.
+The accompaying notes are an integral part
+of these consolidated financial statements.
+F-7
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+DECEMBER 31, 2002
+1. Summary of Significant Accounting Policies
+Description of Operations
+St. Mary Land & Exploration Company ("St. Mary" or the "Company")
+is an independent energy company engaged in the exploration, development,
+acquisition and production of natural gas and crude oil. The Company's
+operations are conducted entirely in the United States.
+Basis of Presentation
+The consolidated financial statements include the accounts of the
+Company and its wholly-owned subsidiaries. Subsidiaries that are not
+wholly-owned are accounted for using full consolidation with minority interest
+or by the equity or cost method as appropriate. All significant intercompany
+accounts and transactions have been eliminated.
+Stock Splits
+In July 2000 St. Mary's Board of Directors approved a two-for-one stock
+split effected in the form of a stock dividend whereby one additional common
+share of stock was distributed for each common share outstanding. The stock
+split was distributed on September 5, 2000, to shareholders of record as of the
+close of business on August 21, 2000. All share and per share amounts for all
+periods presented herein have been restated to reflect this stock split.
+Cash and Cash Equivalents
+The Company considers all highly liquid investments purchased with an
+initial maturity of three months or less to be cash equivalents. The carrying
+value of cash and cash equivalents approximates fair value due to the short-term
+nature of these instruments.
+Short-term Investments
+The Company's short-term investments consist primarily of equity
+securities and investment-grade marketable debt, which are classified as
+available-for-sale or held-to-maturity. Securities which have been categorized
+as available-for-sale are stated at fair value based on quoted market prices.
+Debt securities that the Company has the ability and intent to hold to maturity
+are accounted for as held-to-maturity securities and are carried at amortized
+cost.
+Concentration of Credit Risk
+Substantially all of the Company's receivables are within the oil and
+gas industry, primarily from purchasers of oil and gas and from joint interest
+owners. Although diversified within many companies, collectability is dependent
+upon the general economic conditions of the industry. The receivables are not
+collateralized, and to date the Company has had minimal bad debts.
+The Company has accounts with separate banks in Denver, Colorado;
+Shreveport, Louisiana; Tulsa, Oklahoma; Lafayette, Louisiana; and Billings,
+Montana. At December 31, 2002 and 2001, the Company had $4,881,000 and
+F-8
+$6,576,000 respectively, invested in money market funds, including margin
+accounts consisting of corporate commercial paper, repurchase agreements and
+U.S. Treasury obligations. The Company's policy is to invest in highly rated
+instruments and to limit the amount of credit exposure at each individual
+institution.
+Oil and Gas Producing Activities
+The Company follows the successful efforts method of accounting for its
+oil and gas properties. Under this method of accounting, all property
+acquisition costs and costs of exploratory and development wells are capitalized
+when incurred, pending determination of whether the well has found proved
+reserves. If an exploratory well does not find proved reserves, the costs of
+drilling the well are charged to expense. Exploratory dry hole costs are
+included in cash flows from investing activities within the consolidated
+statements of cash flows. The costs of development wells are capitalized whether
+productive or nonproductive.
+Geological and geophysical costs on exploratory prospects and the costs
+of carrying and retaining unproved properties are expensed as incurred. An
+impairment allowance is provided on a property-by-property basis when the
+Company determines that the unproved property will not be developed. Depletion,
+depreciation and amortization ("DD&A") of capitalized costs of proved oil
+and gas properties is provided on a field-by-field basis using the units of
+production method based upon proved reserves. The computation of DD&A takes
+into consideration restoration, dismantlement and abandonment costs and the
+anticipated proceeds from equipment salvage. The restoration, dismantlement and
+abandonment costs for onshore properties are expected to be offset by the
+residual value of lease and well equipment. The Company had a recorded offshore
+abandonment liability of $9,100,000 as of December 31, 2002, based on total
+expected abandonment costs of $11,700,000 and a liability of $9,500,000 as of
+December 31, 2001 based on total expected abandonment costs of $10,251,000. This
+liability is included in accumulated DD&A on the consolidated balance
+sheets. The Company recorded $204,000, $313,000 and $1,988,000 of offshore
+abandonment liability accretion as part of DD&A expense in the consolidated
+statements of operations for the years ended December 31, 2002, 2001 and 2000,
+respectively.
+The Company reviews its long-lived assets for impairments when events
+or changes in circumstances indicate that an impairment may have occurred. The
+impairment test compares the expected undiscounted future net revenues on a
+field-by-field basis with the related net capitalized costs at the end of each
+period. Expected future cash flows are calculated on all proved reserves using a
+15% discount rate and escalated prices. When the net capitalized costs exceed
+the undiscounted future net revenue of a property, the cost of the property is
+written down to fair value, which is determined using discounted future net
+revenues. During 2002, 2001 and 2000 the Company recorded impairment charges for
+proved properties of $-0-, $820,000 and $4,449,000, respectively.
+Sales of Producing and Nonproducing Properties
+The sale of a partial interest in a proved property is accounted for as
+normal retirement, and no gain or loss is recognized as long as this treatment
+does not significantly affect the unit-of-production amortization rate. A gain
+or loss is recognized for all other sales of producing properties and is
+included in the results of operations.
+The sale of a partial interest in an unproved property is accounted for
+as a recovery of cost when substantial uncertainty exists as to recovery of the
+cost applicable to the interest retained. A gain on the sale is recognized to
+the extent that the sales price exceeds the carrying amount of the unproved
+property. A gain or loss is recognized for all other sales of nonproducing
+properties and is included in the results of operations.
+F-9
+Other Property and Equipment
+Other property and equipment is recorded at cost. Costs of renewals and
+improvements that substantially extend the useful lives of the assets are
+capitalized. Maintenance and repairs are expensed when incurred. Depreciation is
+provided using the straight-line method over the estimated useful lives of the
+assets from 3 to 15 years. Gains and losses on dispositions of other property
+and equipment are included in the results of operations.
+Gas Balancing
+The Company uses the sales method to account for gas imbalances. Under
+this method, revenue is recorded on the basis of gas actually sold by the
+Company. The Company records revenue for its share of gas sold by other owners
+that cannot be volumetrically balanced in the future due to insufficient
+remaining reserves. Related receivables totaling $898,000 at December 31, 2002,
+and $984,000 at December 31, 2001, are included in other noncurrent assets in
+the accompanying balance sheets. The Company also reduces revenue for gas sold
+by the Company that cannot be volumetrically balanced in the future due to
+insufficient remaining reserves. Related payables totaling $531,000 at December
+31, 2002, and $353,000 at December 31, 2001, are included in other noncurrent
+liabilities in the accompanying balance sheets. The Company's remaining
+overproduced and underproduced gas balancing positions are considered in the
+Company's proved oil and gas reserves (see Note 11 - Disclosures About Oil and
+Gas Producing Activities).
+Derivative Financial Instruments
+The Company seeks to protect its rate of return on acquisitions of
+producing properties, drilling prospects and other production by hedging cash
+flows when the economic criteria from its evaluation and pricing model indicate
+it would be appropriate. The Company intends for these derivative instruments
+used for this purpose to be designated as and qualify as cash flow hedging
+instruments under Statement of Financial Accounting Standards ("SFAS") No. 133.
+Management's strategy is to hedge cash flows from investments currently
+requiring a gas price in excess of $3.25 per Mcf and an oil price in excess of
+$22.50 per Bbl in order to meet minimum rate-of-return criteria. Management
+reviews these hedging parameters on a quarterly basis. The Company generally
+limits its aggregate hedge position to no more than 50% of its total production
+but will hedge larger percentages of total production in certain circumstances.
+The Company seeks to minimize basis risk and indexes the majority of its oil
+hedges to NYMEX prices and the majority of its gas hedges to various regional
+index prices associated with pipelines in proximity to the Company's areas of
+gas production.
+The Company's hedge positions are diversified with various
+counterparties, and the Company requires that such counterparties have clear
+indications of current financial strength (See Note 10 - Derivative Financial
+Instruments for additional discussion of derivatives).
+Income Taxes
+Deferred income taxes are provided on the difference between the tax
+basis of an asset or liability and its carrying amount in the financial
+statements. This difference will result in taxable income or deductions in
+future years when the reported amount of the asset or liability is recovered or
+settled, respectively.
+F-10
+Earnings Per Share
+Basic net income per common share of stock is calculated by dividing
+net income by the weighted average of common shares outstanding during each
+year. Diluted net income per common share of stock is calculated by dividing net
+income by the weighted average of common shares outstanding and other dilutive
+securities. Potentially dilutive securities of the Company consist of
+outstanding options to purchase the Company's common stock and shares associated
+with the convertible notes that were issued in 2002. The outstanding dilutive
+securities related to in-the-money options for the years ended December 31,
+2002, 2001 and 2000 were 534,610, 582,313 and 490,288, respectively. Options
+that were out-of-the-money and therefore not considered in the diluted income
+per share calculation were 1,539,227, 625,492, and -0- for the years ended
+December 31, 2002, 2001 and 2000. Shares associated with the convertible notes
+are accounted for using the if-converted method. Potentially dilutive shares of
+3,076,922 in 2002 that related to the convertible notes were not included in the
+calculation of diluted net income per share because they were anti-dilutive.
+Stock-Based Compensation
+At December 31, 2002 the Company had stock-based employee compensation
+plans that are more fully described in Note 7. The Company accounts for
+stock-based compensation using the intrinsic value recognition and measurement
+principles prescribed in Accounting Principles Board Opinion No. 25, "Accounting
+for Stock Issued to Employees" ("APB No. 25") and related interpretations. No
+stock-based employee compensation expense is reflected in net income as all
+options granted under those plans had an exercise price equal to the market
+value of the underlying common stock on the date of grant. The following table
+illustrates the effect on net income and earnings per share if the Company had
+applied the fair value recognition provisions of SFAS No. 123, "Accounting for
+Stock-Based Compensation," to stock-based employee compensation.
+Pro Forma for the Years
+Ended December 31,
+-------------------------------------------
+2002 2001 2000
+---- ---- ----
+(In thousands, except per share amounts)
+Net income
+As reported $ 27,560 $ 40,459 $ 55,620
+Pro forma $ 22,894 $ 37,569 $ 52,515
+Basic earnings per share
+As reported $ .99 $ 1.45 $ 2.00
+Pro forma $ .82 $ 1.34 $ 1.89
+Diluted earnings per share
+As reported $ .97 $ 1.42 $ 1.97
+Pro forma $ .81 $ 1.32 $ 1.86
+For purposes of pro forma disclosures, the estimated fair values of the
+options are amortized to expense over the options' vesting periods. The effects
+of applying SFAS No. 123 in the pro forma disclosure are not necessarily
+indicative of actual future amounts. Additional awards in future years are
+anticipated.
+Comprehensive Income
+Comprehensive income consists of net income, and unrealized gains and
+losses on marketable equity securities held for sale, the effective component of
+derivative instruments classified as cash flow hedges, and accrued pension
+benefit obligation in excess of plan assets. Comprehensive income is presented
+F-11
+net of income taxes in the consolidated statements of stockholders' equity and
+comprehensive income.
+Major Customers
+During 2002 no customer individually accounted for more than 10% of the
+Company's total oil and gas production revenue. During 2001 two customers
+individually accounted for 12.0% and 11.3% of the Company's total oil and gas
+production revenue. During 2000 one customer accounted for 22.3% of the
+Company's total oil and gas production revenue.
+Industry Segment and Geographic Information
+The Company operates in one industry segment, which is the exploration,
+development and production of natural gas and crude oil, and all of the
+Company's operations are conducted in the United States. Consequently, the
+Company currently reports as a single industry segment.
+F-11
+Use of Estimates in the Preparation of Financial Statements
+The preparation of financial statements in conformity with accounting
+principles generally accepted in the United States requires management to make
+estimates and assumptions that affect the reported amounts of oil and gas
+reserves, assets and liabilities and disclosure of contingent assets and
+liabilities at the date of the financial statements and the reported amounts of
+revenues and expenses during the reporting period. Actual results could differ
+from those estimates.
+Recently Issued Accounting Standards
+In July 2001 the Financial Accounting Standards Board ("FASB") issued
+SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement
+requires companies to recognize the fair value of an asset retirement liability
+in the financial statements by capitalizing that cost as part of the cost of the
+related long-lived asset. The asset retirement liability should then be
+allocated to expense by using a systematic and rational method. The statement is
+effective January 1, 2003. The Company has not determined the impact of adoption
+of this statement.
+In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB
+Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
+Corrections." This Statement rescinds SFAS No. 4, "Reporting Gains and Losses
+from Extinguishment of Debt", and an amendment of that Statement, SFAS No. 64,
+"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." This
+Statement also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor
+Carriers." This Statement amends SFAS No. 13, "Accounting for Leases," to
+eliminate an inconsistency between the required accounting for sale-leaseback
+transactions and the required accounting for certain lease modifications that
+have economic effects that are similar to sale-leaseback transactions. This
+Statement also amends other existing authoritative pronouncements to make
+various technical corrections, clarify meanings, or describe their applicability
+under changed conditions. The provisions of this Statement shall be applied in
+fiscal years beginning after May 15, 2002. We currently do not believe that
+adoption of this Statement will have an impact on the Company.
+In June 2002 the FASB issued SFAS No. No. 146, "Accounting for Costs
+Associated with Exit or Disposal Activities." This Statement addresses financial
+accounting and reporting for costs associated with exit or disposal activities
+and nullifies Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability
+Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
+F-12
+Activity (including Certain Costs Incurred in a Restructuring)." The provisions
+of this Statement are effective for exit or disposal activities that are
+initiated after December 31, 2002, with early application encouraged. The
+Company does not believe that adoption of this Statement will have a material
+impact on the financial statements.
+In December 2002 the FASB issued SFAS No. 148, "Accounting for
+Stock-Based Compensation -- Transition and Disclosure: an amendment of FASB
+Statement No. 123." This Statement amends SFAS No. 123, "Accounting for
+Stock-Based Compensation", to provide alternative methods of transition for a
+voluntary change to the fair value based method of accounting for stock-based
+employee compensation. In addition, this Statement amends the disclosure
+requirements of SFAS No. 123 to require prominent disclosures in both annual and
+interim financial statements about the method of accounting for stock-based
+employee compensation and the effect of the method used on reported results. The
+Statement is effective for financial statements for fiscal years ending after
+December 15, 2002. The Company will continue to account for stock-based
+compensation using the methods detailed in the stock-based compensation
+accounting policy.
+2. Accounts Receivable
+Accounts receivable are composed of the following:
+December 31,
+-------------------------
+2002 2001
+---------- ----------
+(In thousands)
+Accrued oil and gas sales $25,962 $29,041
+Due from joint interest owners 8,920 17,042
+Other 517 401
+---------- ----------
+Total accounts receivable $35,399 $46,484
+========== ==========
+3. Acquisitions
+On December 3, 2002, the Company completed the acquisition of oil and
+gas properties located in Montana, North Dakota and Wyoming from Burlington
+Resources Oil & Gas Company LP. The Company paid $69,469,000 in cash after
+normal price adjustments. The Company utilized a portion of its existing credit
+facility to fund the acquisition, and the transaction was accounted for as a
+purchase.
+On November 29, 2001, the Company completed the acquisition of oil and
+gas properties located in Montana, North Dakota and Wyoming from Choctaw II Oil
+and Gas, LTD. The Company paid $40,526,000 in cash after normal price
+adjustments. The Company utilized a portion of its existing credit facility to
+fund the acquisition, and the transaction was accounted for as a purchase.
+On December 28, 2000, the Company completed the acquisition of oil and
+gas properties primarily located in the Anadarko Basin of Oklahoma from JN
+Exploration and Production Limited Partnership and affiliates for $31,613,000
+million in cash after normal purchase price adjustments. The Company utilized
+cash on hand and a portion of its existing credit facility to fund the
+acquisition. The transaction was accounted for as a purchase.
+F-13
+4. Income Taxes
+The provision for income taxes consists of the following:
+For the Years Ended December 31,
+--------------------------------
+2002 2001 2000
+---------- ---------- ----------
+(in thousands)
+Current Taxes:
+Federal $ 719 $ 1,114 $ 11,194
+State 569 620 1,181
+Deferred taxes 13,731 20,095 21,292
+---------- ---------- ----------
+Total income tax expense $ 15,019 $ 21,829 $ 33,667
+========== ========== ==========
+The above taxes from continuing operations are net of alternative fuels
+credits (Internal Revenue Code Section 29) of $167,000 in 2002, $185,000 in 2001
+and $79,000 in 2000. Current federal tax does not reflect the tax benefit for
+deductions from stock option exercises of $719,000 in 2002, $930,000 in 2001 and
+$1,771,000 in 2000 because the benefit is included in additional paid-in capital
+in the consolidated balance sheets. The net federal taxes payable for the years
+ending December 31, 2002, 2001 and 2000 are $-0-, $184,000 and $9,423,000,
+respectively.
+The components of the net deferred tax liability are as follows:
+December 31,
+---------------------
+2002 2001
+---------- ----------
+(in thousands)
+Deferred Tax Liabilities
+Oil and gas properties $ 71,448 $ 55,819
+Derivative Instruments - 3,903
+Other 62 147
+---------- ----------
+Total deferred tax liabilities 71,510 59,869
+---------- ----------
+Deferred Tax Assets
+Amounts included in Other Comprehensive Income 4,181 -
+State tax net operating loss carryforward 4,042 3,638
+Federal net operating loss carryforward 3,142 -
+Deferred capital loss 1,703 1,715
+Other, primarily employee benefits 1,325 1,716
+State and federal income tax benefit 775 3,497
+Charitable contributions carryforward 218 -
+Alternative minimum tax credit carryforward 215 184
+---------- ----------
+Total deferred tax assets 15,601 10,750
+Valuation allowance (727) (1,929)
+---------- ----------
+Net deferred tax assets 14,874 8,821
+---------- ----------
+Total net deferred tax liabilities 56,636 51,048
+Current deferred income tax assets (liabilities) 3,520 (3,363)
+---------- ----------
+Non-current net deferred tax liabilities $ 60,156 $ 47,685
+========== ==========
+Current refundable income tax $ 1,031 $ 11,061
+========== ==========
+F-14
+In accordance with SFAS No. 109 the Company records purchase
+adjustments to its long-term deferred income tax liability accounts to more
+closely align book and tax basis at the time of acquisition. These adjustments
+mitigate the effect of deferred income tax expense or reduced deferred income
+tax benefit on future net income before income tax from acquisitions that
+utilize the purchase method for accounting principles generally accepted in the
+United States and are considered to be tax-free basis transfers for tax
+accounting. During 1999 the Company adjusted its long-term deferred income tax
+liability account for a $667,000 increase relating to its Nance Petroleum
+Corporation ("Nance") stock acquisition and recorded a $10,426,000 decrease for
+its King Ranch Energy ("KRE") stock acquisition as Nance's book basis was
+greater than its tax basis, and KRE's tax basis was greater than its book basis.
+The Company has been recording adjustments to reflect the utilization of
+additional tax benefits of KRE by King Ranch, Inc. on it's 1999 Federal
+consolidated income tax return and to reflect the utilization of tax benefits or
+liabilities on its own federal consolidated returns since the original amounts
+were recorded.
+At December 31, 2002, the Company had state net operating loss
+carryforwards of approximately $61,000,000, which expire between 2003 and 2021.
+The Company's valuation allowance relates to those state net operating loss
+carryforwards that the Company anticipates will expire before they can be
+utilized. The net change in valuation allowance in 2002 results from an
+evaluation of state net operating loss carryforwards that led to a conclusion by
+the Company that more of the carryforwards will be offset by reversing state
+temporary differences, projections of future taxable income and individual state
+tax planning strategies before they expire than was anticipated in prior years.
+Federal income tax expense differs from the amount that would be
+provided by applying the statutory U.S. Federal income tax rate to income before
+income taxes for the following reasons:
+For the Years Ended December 31,
+--------------------------------
+2002 2001 2000
+--------------------------------
+(in thousands)
+Federal statutory taxes $ 14,477 $ 20,420 $ 30,267
+Increase (reduction) in taxes resulting from:
+State taxes (net of Federal benefit) 2,092 2,017 4,342
+Statutory depletion (218) (238) (71)
+Alternative fuel credits (Section 29) (167) (185) (79)
+Change in valuation allowance (1,202) 34 (826)
+Other 37 (219) 34
+---------- ---------- ----------
+Income tax expense from continuing
+operations $ 15,019 $ 21,829 $ 33,667
+========== ========== ==========
+5. Long-term Debt and Notes Payable
+In March 2002 the Company issued in a private placement a total of
+$100,000,000 of 5.75% senior convertible notes due 2022 (the "Notes") with a
+0.5% contingent interest provision (see Note 10-Derivative Financial
+Instruments). The contingent interest provision did not apply to St. Mary's
+first interest payment on September 15, 2002, but it will apply to the payment
+due on March 15, 2003. Interest payments will be made on March 15 and September
+15 in subsequent years. The Company received net proceeds of $96,661,000 after
+deducting the initial purchasers' discount and offering expenses paid by the
+Company. The Notes are general unsecured obligations and rank on parity in right
+of payment with all existing and future unsecured senior indebtedness and other
+F-15
+general unsecured obligations. They are senior in right of payment to
+all future subordinated indebtedness. The Notes are convertible into the
+Company's common stock at a conversion price of $26.00 per share, subject to
+adjustment. The Company can redeem the Notes with cash in whole or in part at a
+repurchase price of 100% of the principal amount plus accrued and unpaid
+interest (including contingent interest) beginning on March 20, 2007. The note
+holders have the option of requiring the Company to repurchase the Notes for
+cash at 100% of the principal amount plus accrued and unpaid interest (including
+contingent interest) upon (1) a change in control of St. Mary or (2) on March
+20, 2007, March 15, 2012, and March 15, 2017. If the note holders require
+repurchase on March 20, 2007, the Company may elect to pay the repurchase price
+with cash, shares of its common stock valued at a discount at the time of
+repurchase, or any combination of cash and its discounted common stock. The
+shares of common stock used in any repurchase will be discounted at 95% of
+market price if 33% or less of the repurchase price is in shares of our common
+stock; otherwise the stock will be discounted at 93% of market value. St. Mary
+is not restricted from paying dividends, incurring debt, or issuing or
+repurchasing its securities under the indenture for the Notes. There are no
+financial covenants in the indenture. The Company used a portion of the net
+proceeds from the Notes to repay its credit facility balance and used the
+remaining net proceeds to fund a portion of its 2002 capital expenditures. On
+March 25, 2002, the Company entered into a five-year fixed-rate to floating-rate
+interest rate swap on $50,000,000 of Notes. The floating rate for each
+applicable six-month period was determined as LIBOR plus 0.36%. For the
+six-month calculation period ending March 15, 2003 this rate was 2.19%. The
+interest rate swap contract was terminated on December 3, 2002. The Company
+received proceeds of $3,952,000 upon termination of the contract and recorded a
+derivative gain of $3,561,000 in the statement of operations. See Note 10 -
+Derivative Financial Instruments for a discussion of the derivative accounting
+for the interest rate swap.
+On March 4, 2002, St. Mary entered into an agreement to amend the
+existing long-term revolving credit agreement. The lender may periodically
+re-determine the aggregate borrowing base depending upon the value of St. Mary's
+oil and gas properties and other assets. The accepted borrowing base was $40.0
+million at December 31, 2002, and the stated total borrowing base was $160.0
+million. The credit agreement has a maturity date of December 31, 2006 and
+includes a revolving period that matures on June 30, 2003. Quarterly principal
+payments will begin on September 30, 2003. The amended agreement deletes all
+reference to and provisions of the short-term tranche previously available to
+St. Mary. The Company must comply with certain covenants including maintenance
+of stockholders' equity at a specified level and limitations on additional
+indebtedness. These outstanding balances accrued interest at rates determined by
+St. Mary's debt to total capitalization ratio at our option of either:
+Debt to Capitalization Ratio <30% =>30%<40% =>40%<50% =>50%
+----------------------------------------------------------------------------------------------
+Option (1)
+LIBOR plus 1.000% 1.250% 1.375% 1.625%
+Option (2) - The higher of:
+Federal funds rate plus 0.500% 0.500% 0.500% 0.500%
+Prime rate plus - - - 0.250%
+The debt to total capitalization ratio as defined under the agreement
+was 27.5% as of December 31, 2002.
+Outstanding borrowings under the revolving credit agreement were
+$14,000,000 and $64,000,000 as of December 31, 2002 and 2001, respectively.
+Borrowings under the Notes were $100,000,000 and $-0- as of December 31, 2002
+F-16
+and 2001, respectively. The weighted average interest rate paid in 2002 was 4.2%
+including commitment fees paid on the unused portion of the accepted borrowing
+base and including the effect of the interest rate swap contract. Borrowings
+under the facility are secured by a pledge of collateral in favor of the banks
+and guarantees by subsidiaries. Such collateral consists primarily of security
+interests in the oil and gas properties of St. Mary and its subsidiaries.
+The Company's estimated annual principal payments under the credit
+agreement for the next four years are as follows:
+Years Ending
+December 31, (In thousands)
+---------------- -------------
+2003 $ 2,000
+2004 4,000
+2005 4,000
+2006 4,000
+-------------
+Total $14,000
+=============
+In January 2003, this line of credit was closed and replaced, as
+described in Note 13, Subsequent Events.
+6. Commitments and Contingencies
+The Company leases office space under various operating leases with
+terms extending as far as May 31, 2012. The Company has a noncancelable sublease
+of approximately $1,685,000 through 2012. Rent expense, net of sublease income,
+was $1,082,000, $839,000 and $782,000 in 2002, 2001 and 2000, respectively. The
+Company also leases office equipment under various operating leases. The annual
+minimum lease payments for the next five years are presented below:
+Years Ending
+December 31, (In thousands)
+--------------- ------------
+2003 $1,573
+2004 1,327
+2005 1,205
+2006 1,125
+2007 861
+Thereafter 3,674
+------------
+Total $9,724
+============
+7. Compensation Plans
+The Company has a cash bonus plan that allows participants to receive
+up to 100% of their aggregate base salary. Any awards under the cash bonus plans
+are based on a combination of Company and individual performance. The Company
+accrued $2,100,000 for cash bonuses in 2002 that will be paid in 2003, $170,000
+for cash bonuses in 2001 that were paid in 2002, and $1,957,000 for cash bonuses
+in 2000 that were paid in 2001.
+Under the Company's net profits interest bonus plan, oil and gas wells
+that are completed or acquired during a year are designated as a pool. Key
+employees designated as participants by the Company's board of directors and
+employed by the Company on the last day of that year vest and become entitled to
+bonus payments after the Company recovers net revenues generated by the pool
+F-17
+equal to 100% of its investment in that pool. Thereafter, an amount generally
+equal to 10% of net revenues generated by the pool will be allocated among the
+participants and paid on a quarterly basis. The percentage of net revenues from
+the pool to be split among the participants increases to 20% after the Company
+recovers net revenues equal to 200% of its investment. The Company records
+estimated compensation expense based on a number of assumptions including
+estimates of oil and gas production, oil and gas prices, recurring and workover
+lease operating expense and a present value discount factor. The Company uses a
+discount factor to calculate present value that reflects recovery of its
+investment, the timing of payments to participants and uncertainties associated
+with the estimates. The estimates the Company uses will change from year-to-year
+based on new information and any change in estimated compensation will be
+recorded in the period that information becomes available. The Company recorded
+estimated compensation expense of $5,600,000 in 2002, $5,259,000 in 2001 and
+$877,000 in 2000 relating to the net profits interest bonus plan.
+The Company has a defined contribution pension plan ("401(k) Plan")
+that is subject to the Employee Retirement Income Security Act of 1974. The
+401(k) Plan allows eligible employees to contribute up to 60% of their base
+salaries. The Company matches each employee's contributions up to 6% of the
+employee's base salary and also may make additional contributions at its
+discretion. The Company's contributions to the 401(k) Plan were $621,000,
+$559,000, and $412,000 for the years ended December 31, 2002, 2001 and 2000,
+respectively. No discretionary contributions were made by the Company to the
+401(K) Plan in any of these three years.
+In September 1997 the Board of Directors approved the St. Mary Land
+& Exploration Company Employee Stock Purchase Plan ("Stock Purchase Plan"),
+which became effective January 1, 1998. Under the Stock Purchase Plan eligible
+employees may purchase shares of the Company's common stock through payroll
+deductions of up to 15% of eligible compensation. The purchase price of the
+stock is 85% of the lower of the fair market value of the stock on the first or
+last day of the purchase period. The Stock Purchase Plan is intended to qualify
+under Section 423 of the Internal Revenue Code. The Company has set aside
+1,000,000 shares of its common stock to be available for issuance under the
+Stock Purchase Plan. In 2002, 2001 and 2000 shares issued under the Stock
+Purchase Plan totaled 18,217, 29,772 and 32,296, respectively. Total proceeds to
+the Company for the issuance of these shares were $344,000, $575,000 and
+$311,000 in 2002, 2001 and 2000, respectively. The Company recorded compensation
+expense of $21,000, $20,000 and $3,000 in 2002, 2001 and 2000, respectively, due
+to nonqualified dispositions of stock acquired by employees under the Stock
+Purchase Plan.
+In 1996 the Company established the St. Mary Land & Exploration
+Company Stock Option Plan and the St. Mary Land & Exploration Company
+Incentive Stock Option Plan (collectively, the "Option Plans"). The Option Plans
+grant options to purchase shares of the Company's common stock to eligible
+employees, contractors, and current and former members of the Board of
+Directors. In 2001 the stockholders approved an increase in the number of shares
+of the Company's common stock reserved for issuance under the Option Plans from
+3,300,000 shares to 4,300,000 shares. All options granted to date under the
+Option Plans have been granted at exercise prices equal to the respective market
+prices of the Company's common stock on the grant dates.
+F-18
+A summary of the status of the Company's Stock Option Plans, including
+the 1990 and 1991 options and changes during the last three years follows:
+For the Years Ended December 31,
+------------------------------------------------------------------------------
+2002 2001 2000
+------------------------- ------------------------- -------------------------
+Weighted Weighted Weighted
+Average Average Average
+Exercise Exercise Exercise
+Shares Price Shares Price Shares Price
+------------- ----------- ------------ ------------ ------------ ------------
+Outstanding, start of year 2,151,675 $ 19.42 1,986,124 $ 18.95 1,998,254 $ 11.63
+Granted 1,109,541 23.55 397,009 18.86 653,848 33.31
+Exercised 177,085 11.44 187,810 11.57 619,220 11.05
+Forfeited 22,565 25.08 43,648 26.00 46,758 11.74
+------------- ------------ ------------
+Outstanding, end of year 3,061,566 21.34 2,151,675 19.42 1,986,124 18.95
+============= ============ ============
+Exercisable, end of year 1,944,382 19.79 1,418,404 17.09 1,150,196 15.00
+============= ============ ============
+Weighted average fair
+value of options
+granted during the year $ 10.77 $ 8.36 $ 14.75
+============= ============ ============
+A summary of additional information related to the options outstanding
+as of December 31, 2002 follows:
+Options Outstanding Options Exercisable
+------------------------------------------------- ------------------------
+Weighted
+Average Weighted Weighted
+Remaining Average Average
+Range of Number Contractual Exercise Number Exercise
+Exercise Prices Outstanding Life Price Exercisable Price
+---------------------- ------------- ---------------- -------------- -------------- -------------
+$ 9.25 - $10.25 332,808 4.8 years $ 9.57 328,776 $ 9.57
+12.38 - 14.69 517,367 6.7 years 12.58 517,367 12.58
+15.93 - 17.50 280,111 7.3 years 16.55 196,353 16.82
+21.19 - 25.00 1,314,209 9.5 years 23.17 430,847 22.83
+33.31 - 33.31 617,071 8.0 years 33.31 471,039 33.31
+------------- --------------
+Total 3,061,566 8.0 years 21.34 1,944,382 19.79
+============= ==============
+SFAS No. 123 establishes a fair value method of accounting for
+stock-based compensation plans either through recognition or disclosure. The
+Company accounts for stock-based compensation under APB No. 25 and has elected
+to adopt SFAS No. 123 through compliance with the disclosure requirements set
+forth in the Statement. Because the exercise price of the Company's employee
+stock options equals the market price of the underlying stock on the date of
+grant, no compensation expense is recognized under APB No. 25. Pro forma
+information regarding net income and earnings per share is required by SFAS No.
+F-19
+123 and has been determined as if the Company had accounted for its employee
+stock options under the fair value method of that Statement.
+The fair value of options is measured at the date of grant using the
+Black-Scholes option-pricing model. The fair values of options granted in 2002,
+2001 and 2000 were estimated using the following weighted-average assumptions:
+2002 2001 2000
+---- ---- ----
+Risk free interest rate 3.76% 4.35% 5.14%
+Dividend yield 0.43% 0.53% 0.32%
+Volatility Factor of the expected
+market price of the Company's
+common stock 47.54% 49.79% 47.11%
+Expected life of the options (in years) 5.9 4.8 4.8
+The Black-Scholes option valuation model was developed for use in
+estimating the fair value of traded options that have no vesting restrictions
+and are fully transferable. In addition, option valuation models require the
+input of highly subjective assumptions including the expected stock price
+volatility. Because the Company's employee stock options have characteristics
+significantly different from those of traded options, and because changes in the
+subjective input assumptions can materially affect the fair value estimate, it
+is management's opinion that the existing models do not necessarily provide a
+reliable single measure of the fair value of St Mary's employee stock options.
+F-20
+8. Pension Benefits
+The Company's employees participate in a non-contributory pension plan
+covering substantially all employees who meet age and service requirements (the
+"Qualified Pension Plan"). The Company also has a supplemental non-contributory
+pension plan covering certain management employees (the "Nonqualified Pension
+Plan"). The Company's disclosures about pension benefits are as follows:
+For the Years Ended December 31,
+2002 2001
+---- ----
+(In thousands)
+Change in benefit obligations:
+Benefit obligation at beginning of year $ 5,098 $ 3,054
+Service Cost 442 323
+Interest Cost 358 317
+Amendments (46) 0
+Actuarial loss 409 1,485
+Benefits paid (25) (81)
+-------- --------
+Benefit obligation at end of year $ 6,236 $ 5,098
+======== ========
+Change in plan assets:
+Fair value of plan assets at beginning of year $ 2,042 $ 1,775
+Actual return on plan assets (255) (13)
+Employer contribution 716 361
+Benefits paid (25) (81)
+-------- --------
+Fair value of plan assets at end of year $ 2,478 $ 2,042
+======== ========
+Funded Status $(3,758) $(3,056)
+Unrecognized net actuarial loss 2,925 2,326
+Unrecognized prior service cost (41) (20)
+-------- --------
+Accrued benefit cost $ (874) $ (750)
+======== ========
+F-20
+The Company's Qualified Pension Plan's accumulated benefit obligation
+was $3,526,000 at December 31, 2002, and $2,646,000 at December 31, 2001. The
+accumulated benefit obligation exceeds plan assets by $1,048,000. The
+tax-adjusted liability of $761,000 was recorded in other comprehensive income at
+December 31, 2002.
+The Company's Nonqualified Pension Plan's accumulated benefit
+obligation was $853,000 at December 31, 2002, and $685,000 at December 31, 2001.
+There are no plan assets in the nonqualified plan due to the nature of the plan.
+Assumptions used in the measurement of the Company's benefit obligation
+are as follows:
+For the Years Ended December 31,
+--------------------------------
+2002 2001
+---- ----
+Weighted-average assumptions:
+Discount rate 6.50% 7.25%
+Expected return on plan assets 8.00% 8.00%
+Rate of compensation increase 4.75% 5.00%
+F-21
+For the Years Ended December 31,
+--------------------------------
+2002 2001 2000
+---- ---- ----
+(In thousands)
+Components of net periodic benefit cost:
+Service cost $ 442 $ 323 $ 257
+Interest cost 358 317 193
+Expected return on plan assets (146) (129) (119)
+Amortization of prior service cost (25) (8) (7)
+Amortization of net actuarial loss 211 188 36
+------ ------ ------
+Net periodic benefit cost $ 840 $ 691 $ 360
+====== ====== ======
+Prior service costs are amortized on a straight-line basis over the
+average remaining service period of active participants. Gains and losses in
+excess of 10% of the greater of the benefit obligation and the market-related
+value of assets are amortized over the average remaining service period of
+active participants.
+9. Investment in Russian Joint Venture
+In February 2000 St. Mary exercised its option to convert its Khanty
+Mansiysk Oil Corporation ("KMOC") production payment receivable into common
+stock of KMOC. In July 2000 the Company finalized a negotiated value for the
+receivable that equated to 21,583 shares of KMOC common stock under the terms of
+the original agreement. In December 2000 the Company sold 14,662 of these shares
+for proceeds of $6,157,000, net of transaction costs and recognized a net gain
+of $2,156,000.
+In January 2002 the Company sold its remaining shares of KMOC common
+stock for proceeds of $2,772,000 and recorded a gain of $838,000.
+10. Derivative Financial Instruments
+The Company realized a net gain of $878,000 from its derivative
+contracts for the year ended December 31, 2002, a net loss of $22,675,000 for
+the year ended December 31, 2001 and a net loss of $33,641,000 for the year
+ended December 31, 2000.
+The Company's senior convertible notes contain a provision for payment
+of contingent interest if certain conditions are met. Under SFAS No. 133 this
+provision is considered an embedded equity related derivative that is not
+clearly and closely related to the fair value of an equity interest and
+therefore must be separately treated as a derivative instrument. The value of
+the derivative at issuance was $474,000. This amount was recorded as a decrease
+to the convertible notes payable in the consolidated balance sheets. Of this
+amount, $75,000 has been amortized through interest expense. Derivative gain in
+the consolidated statements of operations includes $341,000 of net loss from
+mark-to-market adjustments for this derivative.
+The Company's fixed-rate to floating rate interest rate swap on
+$50,000,000 of senior convertible notes did not qualify for fair value hedge
+treatment under SFAS No. 133. This contract was entered into on March 25, 2002,
+and was closed out on December 3, 2002. Derivative gain in the consolidated
+statement of operations includes $3,561,000 of net realized gain from the
+termination of the interest rate swap contract.
+F-22
+The following table summarizes derivative instrument activity.
+2002 2001 2000
+--------------- --------------- ---------------
+Gain (Loss)
+Derivative contract settlements included
+in oil and gas production revenues $ (2,235,000) $ (21,102,000) $ (33,641,000)
+Ineffective portion of hedges qualifying
+for hedge accounting included in
+derivative gain(loss) (32,000) 45,000 -
+Non-qualified derivative contracts included
+in derivative gain (loss) 3,220,000 (1,618,000) -
+Amortization of contingent interest derivative
+through interest expense (75,000) - -
+--------------- --------------- ---------------
+Total $ 878,000 $ (22,675,000) $ (33,641,000)
+=============== =============== ===============
+Including hedges entered into since December 31, 2002 the Company has
+the following commodity swap contracts in place to hedge cash flow and reduce
+the impact of oil and gas price fluctuations:
+Swaps
+-----
+Average Quantity Average Fixed
+Product Volumes/month Type Contract Price Duration
+---------------------------------------------------------------------------------------------
+Natural Gas 1,599,000 MMBtu $4.35 01/03 - 12/03
+Natural Gas 844,000 MMBtu $4.04 01/04 - 12/04
+Oil 206,200 Bbls $25.94 01/03 - 12/03
+Oil 144,500 Bbls $23.71 01/04 - 12/04
+Collars
+-------
+Average Floor Ceiling
+Product Volumes/month Price Price Duration
+---------------------------------------------------------------------------------------------
+Natural Gas 152,000 MMbtu $2.50 $5.96 02/03 - 12/03
+This table excludes commodity positions with Enron North America Corp,
+which filed for bankruptcy protection in December 2001. A net non-cash gain of
+$1,697,000 from these contracts is included in oil and gas production operating
+revenues in the consolidated statements of operations. The Company will amortize
+the remaining $49,000 unrealized hedge loss in 2003.
+As noted in the table above, the last of those contracts will expire by
+December 31, 2004. Derivative gain in the consolidated statement of operations
+includes a loss of $31,000 from ineffectiveness related to these hedge
+contracts. On December 31, 2002 the estimated fair value of contracts designated
+and qualifying as cash flow hedges under SFAS No. 133 was a liability of
+$9,980,000. The Company will reclassify this amount to gains or losses included
+in oil and gas production operating revenues as the hedged production quantity
+is produced. Based on current prices the net amount of existing unrealized
+after-tax loss as of December 31, 2002 to be reclassified from accumulated other
+comprehensive income to oil and gas production operating revenues in the next
+twelve months would be $5,461,000, net of deferred income taxes. The Company
+F-23
+anticipates that all original forecasted transactions will occur by the end of
+the originally specified time periods.
+The Company adopted SFAS No. 133 adopted on January 1, 2001. SFAS No.
+133 requires companies to report all derivatives at fair value as either assets
+or liabilities and bases the accounting treatment of the derivatives on the
+reasons an entity holds the instrument. The adoption of SFAS No. 133 resulted in
+the Company recording a liability of $45,699,000 for the fair value of the
+derivative instruments at January 1, 2001. The Company's adoption entry also
+resulted in deferral of the recognition of this liability to accumulated other
+comprehensive loss of $28,587,000, net of deferred income taxes.
+See also Derivative Financial Instruments in Note 1 - Summary of
+Significant Accounting Policies.
+F-23
+11. Disclosures About Oil and Gas Producing Activities
+Costs Incurred in Oil and Gas Producing Activities:
+Costs incurred in oil and gas property acquisition, exploration and
+development activities, whether capitalized or expensed, are summarized as
+follows:
+For the Years Ended December 31,
+--------------------------------
+2002 2001 2000
+---- ---- ----
+(In thousands)
+Development costs $ 74,376 $ 98,617 $ 48,996
+Exploration 22,778 24,506 17,012
+Acquisitions:
+Proved 87,706 41,188 53,482
+Unproved 8,128 18,552 5,694
+-------- -------- --------
+Total $192,988 $182,863 $125,184
+======== ======== ========
+Oil and Gas Reserve Quantities (Unaudited):
+The reserve information as of December 31, 2002, 2001, and 2000 was
+prepared by Ryder Scott Company and St. Mary. The Company emphasizes that
+reserve estimates are inherently imprecise and that estimates of new discoveries
+are more imprecise than those of proved producing oil and gas properties.
+Accordingly, these estimates are expected to change as future information
+becomes available.
+Proved oil and gas reserves are the estimated quantities of crude oil,
+natural gas and natural gas liquids which geological and engineering data
+demonstrate with reasonable certainty to be recoverable in future years from
+known reservoirs under existing economic and operating conditions. Proved
+developed oil and gas reserves are those expected to be recovered through
+existing wells with existing equipment and operating methods.
+F-24
+Presented below is a summary of the changes in estimated domestic
+reserves of the Company:
+For the Years Ended December 31,
+--------------------------------
+2002 2001 2000
+-------- ---- ----
+Oil or Oil or Oil or
+Condensate Gas Condensate Gas Condensate Gas
+---------- --- ---------- --- ---------- ---
+(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
+Total proved reserves:
+Developed and undeveloped:
+Beginning of year 23,669 241,231 20,950 225,975 18,900 207,642
+Revisions of previous estimate 3,611 4,696 (1,334) (16,421) 210 (1,172)
+Discoveries and extensions 1,250 32,813 3,131 59,830 1,707 37,702
+Purchases of minerals in place 10,578 38,118 3,774 13,086 3,149 21,689
+Sales of reserves (174) (4,522) (418) (1,748) (618) (1,540)
+Production (2,815) (38,164) (2,434) (39,491) (2,398) (38,346)
+------ ------- ------ ------- ------ -------
+End of year (a) 36,119 274,172 23,669 241,231 20,950 225,975
+====== ======= ====== ======= ====== =======
+Proved developed reserves:
+Beginning of year 20,679 205,637 19,006 192,472 16,688 169,379
+====== ======= ====== ======= ====== =======
+End of year 33,580 228,973 20,679 205,637 19,006 192,472
+====== ======= ====== ======= ====== =======
+------------------
+(a) At December 31, 2002, 2001, and 2000, includes approximately
+1,151, 869 and 1,199 MMcf, respectively, representing the
+Company's underproduced gas balancing position.
+Standardized Measure of Discounted Future Net Cash Flows (Unaudited):
+SFAS No. 69, "Disclosures About Oil and Gas Producing Activities,"
+prescribes guidelines for computing a standardized measure of future net cash
+flows and changes therein relating to estimated proved reserves. The Company has
+followed these guidelines, which are briefly discussed below.
+Future cash inflows and future production and development costs are
+determined by applying benchmark prices and costs, including transportation,
+quality and basis differential, in effect at year-end to the year-end estimated
+quantities of oil and gas to be produced in the future. Estimated future income
+taxes are computed using current statutory income tax rates, including
+consideration for estimated future statutory depletion and alternative fuels tax
+credits. The resulting future net cash flows are reduced to present value
+amounts by applying a 10% annual discount factor.
+The assumptions used to compute the standardized measure are those
+prescribed by the FASB and the Securities and Exchange Commission. These
+assumptions do not necessarily reflect the Company's expectations of actual
+revenues to be derived from those reserves, nor their present worth. The
+limitations inherent in the reserve quantity estimation process, as discussed
+previously, are equally applicable to the standardized measure computations
+since these estimates are the basis for the valuation process. The following
+prices, adjusted for transportation, quality and basis differentials, were used
+in the calculation of the standardized measure:
+For the Years Ended December 31,
+--------------------------------
+2002 2001 2000
+---- ---- ----
+Gas (per Mcf) $ 4.211 $ 2.502 $ 8.857
+Oil (per Bbl) $29.311 $18.113 $ 25.439
+F-25
+The following summary sets forth the Company's future net cash flows
+relating to proved oil and gas reserves based on the standardized measure
+prescribed in SFAS No. 69:
+For the Years Ended December 31,
+--------------------------------
+2002 2001 2000
+---- ---- ----
+(In thousands)
+Future cash inflows $2,238,513 $1,020,948 $2,648,108
+Future production and
+development costs (783,991) (444,608) (570,711)
+Future income taxes (429,618) (140,271) (727,929)
+---------- ----------- ----------
+Future net cash flows 1,024,904 436,069 1,349,468
+10% annual discount (443,042) (154,192) (630,984)
+---------- ----------- ----------
+Standardized measure of
+discounted future net cash flows $ 581,862 $ 281,877 $ 718,484
+========== =========== ==========
+The principle sources of change in the standardized measure of
+discounted future net cash flows are as follows:
+For the Years Ended December 31,
+--------------------------------
+2002 2001 2000
+---- ---- ----
+(In thousands)
+Standard measure, beginning of year $ 281,877 $ 718,484 $ 261,314
+Sales of oil and gas produced,
+net of production costs (137,066) (170,074) (183,586)
+Net changes in prices and production costs 298,079 (820,253) 772,910
+Extensions, discoveries and other,
+net of production costs 92,227 71,265 203,786
+Purchase of minerals in place 160,089 29,267 104,883
+Development costs incurred during the year 23,802 35,736 12,436
+Changes in estimated future development cost 4,265 (8,370) 351
+Revisions of previous quantity estimates 49,892 (17,593) 306
+Accretion of discount 34,749 109,912 33,871
+Sales of reserves in place (708) (10,548) (3,329)
+Net change in income taxes (177,335) 298,717 (357,780)
+Other (48,009) 45,334 (126,678)
+---------- ----------- ----------
+Standardized measure, end of year $ 581,862 $ 281,877 $ 718,484
+========== =========== ==========
+F-26
+12. Quarterly Financial Information (Unaudited)
+The Company's quarterly financial information for fiscal 2002 and 2001
+is as follows (in thousands, except per share amounts):
+First Second Third Fourth
+Quarter Quarter Quarter Quarter
+---------- ---------- ---------- ----------
+Year Ended December 31, 2002:
+Total Revenue $ 42,773 $ 50,028 $ 48,335 $ 55,258
+Less: costs and expenses 38,991 33,322 35,634 42,758
+---------- ---------- ---------- ----------
+Operating Income $ 3,782 $ 16,706 $ 12,701 $ 12,500
+Income before income taxes $ 3,440 $ 15,858 $ 1,187 $ 11,402
+Net income $ 2,318 $ 10,589 $ 7,674 $ 6,979
+Net income per common share:
+Basic $ 0.08 $ 0.38 $ 0.28 $ 0.25
+Diluted $ 0.08 $ 0.37 $ 0.27 $ 0.24
+Dividends paid per share $ - $ 0.05 $ - $ 0.05
+Year Ended December 31, 2001
+Total Revenue $ 68,347 $ 55,776 $ 42,656 $ 40,690
+Less: costs and expenses 36,626 32,804 37,129 38,998
+---------- ---------- ---------- ----------
+Operating Income 31,721 22,972 5,527 1,692
+Income before income taxes $ 31,874 $ 23,119 $ 5,595 $ 1,700
+Net income $ 20,393 $ 14,234 $ 4,861 $ 971
+Net income per common share:
+Basic $ 0.72 $ 0.51 $ 0.17 $ 0.04
+Diluted $ 0.71 $ 0.50 $ 0.17 $ 0.03
+Dividends paid per share $ - $ 0.05 $ - $ 0.05
+13. Subsequent Events (Unaudited)
+Long - Term Debt
+In January 2003 the Company entered into a new long-term revolving
+credit agreement that replaced the agreement dated June 30, 1998. The new credit
+agreement specifies a maximum loan amount of $300,000,000. Borrowings under the
+facility are secured by a pledge of collateral in favor of the lenders and by
+common stock of material subsidiaries of the Company. The borrowing base is
+currently $215,000,000 but will be increased to $250,000,000 when additional
+collateral is provided to the lenders. The lenders may periodically re-determine
+the aggregate borrowing base depending upon the value of St. Mary's oil and gas
+properties and other assets. The aggregate commitment was $150,000,000 at
+January 27, 2003, and the credit agreement has a maturity date of January 27,
+2006. The Company must comply with certain covenants. Interest is accrued based
+on the borrowing base utilization percentage as LIBOR or the Alternate Base Rate
+("ABR"), which is the Prime rate plus the following:
+F-27
+Borrowing base
+utilization percentage <30% =>30%<40% =>40%<50% =>50%
+-----------------------------------------------------------------------------------------------
+Eurodollar Loans 1.250% 1.500% 1.750% 2.000%
+ABR Loans 0.000% 0.250% 0.500% 0.750%
+Commitment Fee Rate 0.300% 0.375% 0.375% 0.500%
+Acquisitions
+On January 29, 2003, the Company closed the previously announced
+agreement to acquire oil and gas properties from Flying J Oil & Gas Inc. and
+Big West Oil & Gas Inc. St. Mary issued 3,380,818 shares of its restricted
+common stock valued at $71,594,000 for an estimated 66.9 BCFE of proved reserves
+and a net amount of $2,800,000 in cash for purchase price adjustments. In
+addition, St. Mary has made a non-recourse loan to Flying J and Big West of
+$71,594,000 at LIBOR plus 2% for up to a 39-month period that is secured by a
+pledge of these shares of St. Mary stock. During the 39-month loan period Flying
+J and Big West can elect to sell their shares of St. Mary stock to the Company
+for $71,594,000 plus accrued interest on the loan for the first thirty months,
+and St. Mary can elect to purchase the shares for $97,447,000, with the proceeds
+applied to the repayment of the loan.
+F-28
+SIGNATURES
+Pursuant to the requirements of Section 13 or 15(d) of the Securities
+Exchange Act of 1934, the registrant has duly caused this report to be signed on
+its behalf by the undersigned, thereunto duly authorized.
+ST. MARY LAND & EXPLORATION COMPANY
+---------------------------------------
+(Registrant)
+Date: March 12, 2003 By: /s/ MARK A. HELLERSTEIN
+-----------------------------------
+Mark A. Hellerstein
+Chairman of the Board of Directors,
+President and Chief Executive Officer
+GENERAL POWER OF ATTORNEY
+KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature
+appears below constitutes and appoints Mark A. Hellerstein his or her true and
+lawful attorney-in-fact and agent with full power of substitution and
+resubstitution, for him or her and in his or her name, place and stead, in any
+and all capacities, to sign any amendments to this annual report on Form 10-K,
+and to file the same, with exhibits thereto and other documents in connection
+therewith, with the Securities and Exchange Commission, hereby ratifying and
+confirming all that said attorney-in-fact, or his substitute or substitutes, may
+do or cause to be done by virtue hereof.
+Pursuant to the requirements of the Securities Exchange Act of 1934,
+this report has been signed below by the following persons on behalf of the
+registrant and in the capacities and on the dates indicated.
+Signature Title Date
+--------- ----- ----
+/s/ MARK A. HELLERSTEIN Chairman of the Board of Directors, March 12, 2003
+----------------------- President and Chief Executive Officer
+Mark A. Hellerstein
+/s/ RONALD D. BOONE Executive Vice President, Chief March 12, 2003
+----------------------- Operating Officer and Director
+Ronald D. Boone
+/s/ ROBERT L. NANCE Senior Vice President and Director March 12, 2003
+-----------------------
+Robert L. Nance
+/s/ RICHARD C. NORRIS Vice President-Finance, March 12, 2003
+----------------------- Secretary and Treasurer
+Richard C. Norris
+/s/ GARRY A. WILKENING Vice President-Administration March 12, 2003
+----------------------- and Controller
+Garry A. Wilkening
+Signature Title Date
+--------- ----- ----
+/s/BARBARA M. BAUMANN Director March 12, 2003
+-----------------------
+Barbara M. Baumann
+Director March 12, 2003
+-----------------------
+Larry W. Bickle
+Director March 12, 2003
+-----------------------
+Thomas E. Congdon
+/s/ WILLIAM J. GARDINER Director March 12, 2003
+-----------------------
+William J. Gardiner
+/s/ AREND J. SANDBULTE Director March 12, 2003
+-----------------------
+Arend J. Sandbulte
+Director March 12,2003
+-----------------------
+John M. Seidl
+CERTIFICATION
+I, Mark A. Hellerstein, certify that:
+1. I have reviewed this annual report on Form 10-K of St. Mary Land
+& Exploration Company;
+2. Based on my knowledge, this annual report does not contain any
+untrue statement of a material fact or omit to state a material fact necessary
+to make the statements made, in light of the circumstances under which such
+statements were made, not misleading with respect to the period covered by this
+annual report;
+3. Based on my knowledge, the financial statements, and other financial
+information included in this annual report, fairly present in all material
+respects the financial condition, results of operations and cash flows of the
+registrant as of, and for, the periods presented in this annual report;
+4. The registrant's other certifying officers and I are responsible for
+establishing and maintaining disclosure controls and procedures (as defined in
+Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
+a) designed such disclosure controls and procedures to ensure that
+material information relating to the registrant, including its consolidated
+subsidiaries, is made known to us by others within those entities, particularly
+during the period in which this annual report is being prepared;
+b) evaluated the effectiveness of the registrant's disclosure controls
+and procedures as of a date within 90 days prior to the filing date of this
+annual report (the "Evaluation Date"); and
+c) presented in this annual report our conclusions about the
+effectiveness of the disclosure controls and procedures based on our evaluation
+as of the Evaluation Date;
+5. The registrant's other certifying officers and I have disclosed,
+based on our most recent evaluation, to the registrant's auditors and the audit
+committee of registrant's board of directors (or persons performing the
+equivalent functions):
+a) all significant deficiencies in the design or operation of internal
+controls which could adversely affect the registrant's ability to record,
+process, summarize and report financial data and have identified for the
+registrant's auditors any material weaknesses in internal controls; and
+b) any fraud, whether or not material, that involves management or
+other employees who have a significant role in the registrant's internal
+controls; and
+6. The registrant's other certifying officers and I have indicated in
+this annual report whether there were significant changes in internal controls
+or in other factors that could significantly affect internal controls subsequent
+to the date of our most recent evaluation, including any corrective actions with
+regard to significant deficiencies and material weaknesses.
+Date: March 12, 2003
+/s/ MARK A. HELLERSTEIN
+------------------------------------
+Mark A. Hellerstein
+Chairman of the Board, President and
+Chief Executive Officer
+CERTIFICATION
+I, Richard C. Norris, certify that:
+1. I have reviewed this annual report on Form 10-K of St. Mary Land
+& Exploration Company;
+2. Based on my knowledge, this annual report does not contain any
+untrue statement of a material fact or omit to state a material fact necessary
+to make the statements made, in light of the circumstances under which such
+statements were made, not misleading with respect to the period covered by this
+annual report;
+3. Based on my knowledge, the financial statements, and other financial
+information included in this annual report, fairly present in all material
+respects the financial condition, results of operations and cash flows of the
+registrant as of, and for, the periods presented in this annual report;
+4. The registrant's other certifying officers and I are responsible for
+establishing and maintaining disclosure controls and procedures (as defined in
+Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
+a) designed such disclosure controls and procedures to ensure that
+material information relating to the registrant, including its consolidated
+subsidiaries, is made known to us by others within those entities, particularly
+during the period in which this annual report is being prepared;
+b) evaluated the effectiveness of the registrant's disclosure controls
+and procedures as of a date within 90 days prior to the filing date of this
+annual report (the "Evaluation Date"); and
+c) presented in this annual report our conclusions about the
+effectiveness of the disclosure controls and procedures based on our evaluation
+as of the Evaluation Date;
+5. The registrant's other certifying officers and I have disclosed,
+based on our most recent evaluation, to the registrant's auditors and the audit
+committee of registrant's board of directors (or persons performing the
+equivalent functions):
+a) all significant deficiencies in the design or operation of internal
+controls which could adversely affect the registrant's ability to record,
+process, summarize and report financial data and have identified for the
+registrant's auditors any material weaknesses in internal controls; and
+b) any fraud, whether or not material, that involves management or
+other employees who have a significant role in the registrant's internal
+controls; and
+6. The registrant's other certifying officers and I have indicated in
+this annual report whether there were significant changes in internal controls
+or in other factors that could significantly affect internal controls subsequent
+to the date of our most recent evaluation, including any corrective actions with
+regard to significant deficiencies and material weaknesses.
+Date: March 12, 2003
+/s/ RICHARD C. NORRIS
+------------------------------------
+Richard C. Norris
+Vice-President - Finance
\ No newline at end of file
diff --git a/raw/filings/0000893538/2002/0000893538-03-000008/filing_metadata.csv b/raw/filings/0000893538/2002/0000893538-03-000008/filing_metadata.csv
new file mode 100644
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@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000893538,SM,SM Energy Co,10-K,2003-03-13,2002-12-31,2003-03-13T22:12:55.000Z,0000893538-03-000008,asci123102_10k.htm,ANNUAL REPORT FORM 10-K 12/31/02,805172,0,0,https://www.sec.gov/Archives/edgar/data/893538/000089353803000008/asci123102_10k.htm,https://www.sec.gov/Archives/edgar/data/893538/000089353803000008/,2002,2002,1
diff --git a/raw/filings/0000893538/2002/0000893538-03-000008/item1.txt b/raw/filings/0000893538/2002/0000893538-03-000008/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..005892e5b0d0bab4589d3372fb38118eeab958aa
--- /dev/null
+++ b/raw/filings/0000893538/2002/0000893538-03-000008/item1.txt
@@ -0,0 +1,1126 @@
+ITEM 1. BUSINESS
+Background
+St. Mary Land & Exploration Company is an independent energy
+company engaged in the exploration, development, acquisition and production of
+natural gas and crude oil. St. Mary was founded in 1908 and incorporated in
+Delaware in 1915. Our operations are focused in the following five core
+operating areas in the United States:
+o the Mid-Continent region in Oklahoma and northern Texas;
+o the ArkLaTex region that spans northern Louisiana and portions
+of Arkansas, Mississippi and eastern Texas;
+o the onshore Gulf Coast and offshore Gulf of Mexico;
+o the Rocky Mountain region consisting of the Williston Basin in
+eastern Montana and western North Dakota and the Powder River,
+Green River and Wind River Basins in Wyoming; and
+o the Permian Basin in eastern New Mexico and western Texas.
+As of December 31, 2002, we had estimated proved reserves of
+approximately 36.1 MMBbls of oil and 274.2 Bcf of natural gas, or a total of
+490.9 BCFE, 88% of which were proved developed and 56% of which were natural
+gas, with a PV-10 value of $824.8 million. For the year ended December 31, 2002,
+we produced 55.1 BCFE representing average daily production of 150.8 MMCFE per
+day.
+We focus our resources in selected domestic basins where we believe
+that our expertise in geology, geophysics and drilling and completion techniques
+provides us with competitive advantages. We have assembled a balanced program of
+low-to-medium-risk development and exploitation projects to provide the
+foundation for steady growth. In addition, we have a portfolio of
+higher-potential exploration projects and non-conventional gas plays in the
+Rocky Mountain region that we believe could significantly increase our reserves
+and production. We measure and rank our investment decisions based on their
+risk-adjusted impact on per share net asset value. In the past, we have sold
+selected assets when we believed attractive prices were available, and we will
+continue to evaluate such opportunities in the future.
+We seek to develop our existing property base and acquire acreage with
+additional potential in our core areas. From January 1, 2000, through December
+31, 2002, we participated in the drilling or recompletion of 623 gross wells
+with an average success rate of 82%. During that same period we added estimated
+1
+proved reserves of 347 BCFE at an average finding cost of $1.44 per MCFE. Our
+average annual production replacement was 214% during this three-year period,
+and our production has grown at an average rate of 21% per year over the same
+time period.
+As of December 31, 2002, we had an acreage position of 1,145,507 gross
+(542,736 net) acres of which 504,873 gross (325,290 net) acres were undeveloped.
+For 2003 we have budgeted capital expenditures of $135 million for ongoing
+development, exploitation and exploration programs in our core operating areas
+and $90 million for acquisitions of oil and gas properties.
+Our principal offices are located at 1776 Lincoln Street, Suite 700,
+Denver, Colorado 80203, and our telephone number is (303) 861-8140.
+Business Strategy
+Our objective is to build stockholder value through consistent economic
+growth in reserves and production that increase net asset value per share, cash
+flow per share and earnings per share. The principal elements of our strategy
+are as follows:
+o Maintain Focused Geographic Operations. We focus on
+exploration, development and acquisition activities in five
+core operating areas where we have built a balanced portfolio
+of proved reserves, development drilling opportunities and
+higher-potential exploration and non-conventional gas
+prospects. We believe that our leasehold position is a
+strategic asset. Our senior technical managers, each
+possessing over 20 years of experience, head up regional
+technical offices supported by centralized administration in
+our Denver office. We believe that our long-standing presence,
+our established networks of local industry relationships and
+our acreage holdings in our core operating areas provide us
+with a competitive advantage. In addition, we believe that we
+can continue to expand our operations without the need to
+proportionately increase the number of employees.
+o Continue Exploitation and Development of Existing Properties.
+We use our comprehensive base of geological, geophysical,
+engineering and production experience in each of our core
+operating areas to source prospects for our ongoing
+low-to-medium-risk development and exploitation programs. We
+conduct detailed geologic studies and use an array of
+technologies and tools including 2-D and 3-D seismic imaging,
+hydraulic fracturing and reservoir stimulation techniques, and
+specialized logging tools to enhance the potential of our
+existing properties. In 2002 we participated in the drilling
+or recompletion of 168 gross wells with a 79% success rate.
+o Pursue Higher-Risk Higher-Potential Exploration Projects. We
+have allocated approximately 7% of our 2003 drilling and
+exploration capital expenditures budget to higher-potential
+exploration and unconventional gas projects. Our strategy is
+to test several of these prospects each year that in total
+have the potential to significantly increase our reserves. We
+seek to invest in a diversified mix of projects and generally
+limit our capital exposure by participating with other
+experienced industry partners. We plan to test projects in the
+Mid-Continent region and Rocky Mountain area during 2003.
+o Make Selective Acquisitions. We seek to make selective niche
+acquisitions of oil and gas properties that complement our
+existing operations, offer economies of scale and provide
+2
+further development, exploitation and exploration
+opportunities based on proprietary geologic concepts. We
+believe that the focus on smaller, negotiated transactions
+where we have specialized geologic knowledge or operating
+experience has enabled us to acquire attractively priced and
+under-exploited properties. In addition, we will pursue
+corporate acquisitions that we believe will be accretive.
+Examples of this type of acquisition include our 1999 Nance
+Petroleum Corporation and King Ranch Energy, Inc.
+acquisitions, both of which were acquired with our common
+stock. We have budgeted $90.0 million for acquisitions in
+2003, of which $74.0 million closed in January 2003, including
+the acquisition of properties from Flying J Oil & Gas Inc.
+and Big West Oil & Gas Inc. in exchange for the issuance
+of 3,380,818 restricted shares of St. Mary common stock.
+o Control Operations. We believe it is important to control
+geologic and operational decisions as well as the timing of
+those decisions. At December 31, 2002, we operated 31% of our
+properties on a volume basis and 66% on a PV-10 value basis.
+We are the operator of properties representing approximately
+81% of our 2003 capital budget.
+o Maintain Financial Flexibility. Conservative use of financial
+leverage has long been a critical element of our strategy. We
+believe that maintaining a strong balance sheet is a
+significant competitive advantage that enables us to pursue
+acquisition and other opportunities, especially in weaker
+price environments. It also provides us with the financial
+resources to weather periods of volatile commodity prices or
+escalating costs.
+Significant Developments Since December 31, 2001
+o 2002 Acquisitions of Oil and Gas Properties. In December 2002
+St. Mary completed a $69.5 million acquisition of properties
+in the Williston Basin from Burlington Resources Oil & Gas
+Company LP. The properties are located in Montana and North
+Dakota and produce approximately 3,100 barrels of oil and
+3,300 Mcf of gas per day. Smaller acquisitions during 2002
+included the $7.5 million Mid-Continent acquisition from
+Merchant Resources LP, the $4.9 million acquisition in the
+Huxley Field located in east Texas and $5.8 million in various
+other properties. We used cash from our March 2002 senior
+convertible note placement and borrowings under our bank
+credit facility to fund these acquisitions.
+o 2003 Acquisition of Oil and Gas Properties. In January 2003
+St. Mary issued 3,380,818 shares of its restricted common
+stock valued at $71.6 million to acquire Rocky Mountain
+properties from Flying J Oil & Gas Inc. and Big West Oil
+& Gas Inc. This acquisition included properties located in
+the Williston, Powder River and Green River Basins with 66.9
+BCFE of proved reserves and production of approximately 2,100
+barrels of oil and 8,200 Mcf of gas per day. We also received
+a net amount of $2.8 million in cash for normal purchase price
+adjustments. In addition, St. Mary made a non-recourse loan to
+Flying J and Big West of $71.6 million at LIBOR plus 2% for up
+to a 39-month period. The loan is secured by a pledge of the
+shares of St. Mary stock issued to Flying J and Big West. The
+loan was funded through borrowings under our bank credit
+facility.
+3
+o Increase in 2002 Year-End Reserves. Proved reserves increased
+28% from December 31, 2001 to 490.9 BCFE as of December 31,
+2002. We added 101.6 BCFE through acquisitions for cash and
+40.3 BCFE from drilling activities. There were net upward
+revisions of previous reserves totaling 26.4 BCFE. This upward
+revision was the result of a 33.9 BCFE increase from price
+revisions, which was partially offset by 7.5 BCFE in negative
+performance revisions.
+o New York Stock Exchange Listing. On November 20, 2002 St. Mary
+Land & Exploration Company's common stock began trading on
+the New York Stock Exchange. The Company believes the NYSE
+will improve visibility with investors and the auction market
+structure will help reduce intra-day volatility and increase
+the liquidity in St. Mary's stock. Prior to November 20, 2002
+St. Mary's common stock was traded on the Nasdaq National
+Market System.
+o Senior Convertible Notes. In March 2002 we issued in a private
+placement a total of $100.0 million of our 5.75% senior
+convertible notes due 2022 with a1/2% contingent interest
+provision. We received net proceeds of $96.7 million after
+deducting the initial purchasers' discount and offering
+expenses paid by us. The notes are general unsecured
+obligations and rank on a parity in right of payment with all
+our existing and future senior indebtedness and other general
+unsecured obligations. They are senior in right of payment to
+all our future subordinated indebtedness. The notes are
+convertible into our common stock at a conversion price of
+$26.00 per share, subject to adjustment. We can redeem the
+notes with cash in whole or in part at a repurchase price of
+100% of the principal amount plus accrued and unpaid interest
+beginning on March 20, 2007. The note holders have the option
+of requiring us to repurchase the notes for cash at 100% of
+the principal amount plus accrued and unpaid interest
+(including contingent interest) upon (1) a change in control
+of St. Mary or (2) on March 20, 2007, March 15, 2012 and March
+15, 2017. On March 20, 2007, we may pay the repurchase price
+with cash, shares of our common stock or any combination of
+cash and our common stock. We are not restricted from paying
+dividends, incurring debt, or issuing or repurchasing our
+securities under the indenture for the notes. There are no
+financial covenants in the indenture. We used a portion of the
+net proceeds from the notes to repay our credit facility
+balance and used the remaining net proceeds to fund a portion
+of our 2002 capital expenditures.
+o Revolving Credit Agreement. In January 2003 we entered into a
+new long-term revolving credit agreement with nine banks. The
+maximum loan amount is $300 million with a calculated
+borrowing base of $250 million. We have reduced the commitment
+amount to $150 million to meet our projected needs. The
+maturity date is January 27, 2006. Interest is accrued based
+on the borrowing base utilization and is currently LIBOR plus
+1.25%.
+Major Customers
+During 2002 there were no sales to individual customers that accounted
+for more than 10% of our total oil and gas production revenue. During 2001 sales
+to Transok Gas Company accounted for 12.0% and sales to BP Amoco accounted for
+11.3% of our total oil and gas production revenue. During 2000 sales to BP Amoco
+accounted for 22.3% of our total oil and gas production revenue.
+4
+Employees and Office Space
+As of December 31, 2002, St. Mary had 185 full-time employees. None of
+our employees are subject to a collective bargaining agreement. We consider our
+relations with our employees to be good. We lease approximately 42,660 square
+feet of office space in Denver, Colorado for our executive and administrative
+offices, of which 9,479 square feet is subleased. We also lease approximately
+14,990 square feet of office space in Tulsa, Oklahoma; approximately 11,740
+square feet in Shreveport, Louisiana; approximately 7,500 square feet in
+Lafayette, Louisiana; and approximately 15,830 square feet in Billings, Montana.
+Title to Properties
+Substantially all of our working interests are held pursuant to leases
+from third parties. A title opinion is usually obtained prior to the
+commencement of drilling operations on properties. We have obtained title
+opinions or conducted a thorough title review on substantially all of our
+producing properties and believe that we have satisfactory title to such
+properties in accordance with standards generally accepted in the oil and gas
+industry. Our properties are subject to a mortgage under our credit facility,
+customary royalty interests, liens for current taxes, and other burdens that we
+believe do not materially interfere with the use of or affect the value of such
+properties. We perform only a minimal title investigation before acquiring
+undeveloped properties.
+Competition
+The oil and gas industry is intensely competitive. Competition is
+particularly intense in the acquisition of prospective oil and natural gas
+properties and oil and gas reserves. Our competitive position depends on our
+geological, geophysical and engineering expertise, our financial resources, and
+our ability to select, acquire and develop proved reserves. We believe that the
+locations of our leasehold acreage, our exploration, drilling and production
+capabilities and the experience of our management and that of our industry
+partners generally enable us to compete effectively in our core operating areas.
+However, we compete with a substantial number of major and independent oil and
+gas companies that have larger technical staffs and greater financial and
+operational resources than we do. Many of these companies not only engage in the
+acquisition, exploration, development and production of oil and natural gas
+reserves, but also have refining operations, market refined products and
+generate electricity. We also compete with other oil and natural gas companies
+in attempting to secure drilling rigs and other equipment necessary for drilling
+and completion of wells. Drilling equipment may be in short supply from time to
+time.
+Government Regulations
+Our business is subject to various federal, state and local laws and
+governmental regulations that may be changed from time to time in response to
+economic or political conditions. Matters subject to regulation include
+discharge permits for drilling operations, drilling bonds, reports concerning
+operations, the spacing of wells, unitization and pooling of properties,
+taxation and environmental protection. From time to time, regulatory agencies
+have imposed price controls and limitations on production by restricting the
+rate of flow of oil and gas wells below actual production capacity in order to
+conserve supplies of oil and gas.
+St. Mary's operations could result in liability for personal injuries,
+property damage, oil spills, discharge of hazardous materials, remediation and
+clean-up costs and other environmental damages. We could be liable for
+environmental damages caused by previous property owners. As a result,
+substantial liabilities to third parties or governmental entities may be
+5
+incurred, and the payment of such liabilities could have a material adverse
+effect on our financial condition and results of operations. We maintain
+insurance coverage for our operations, including limited coverage for sudden
+environmental damages, but we do not believe that insurance coverage for
+environmental damage that occurs over time is available at a reasonable cost.
+Moreover, we do not believe that insurance coverage for the full potential
+liability that could be caused by sudden environmental damages is available at a
+reasonable cost. Accordingly, we may be subject to liability or may lose
+substantial portions of our properties in the event of certain environmental
+damages. St. Mary could incur substantial costs to comply with environmental
+laws and regulations.
+Energy Regulations. With respect to federal energy regulation, the
+transportation and sale for resale of natural gas in interstate commerce have
+historically been regulated pursuant to several laws enacted by Congress and
+regulations promulgated under these laws by the Federal Energy Regulatory
+Commission and its predecessor. In the past the federal government has regulated
+the prices at which gas could be sold. Congress removed all price and non-price
+controls affecting wellhead sales of natural gas effective January 1, 1993.
+However, Congress could reenact price controls in the future.
+Our sales of natural gas are affected by the availability, terms and
+cost of transportation. The price and terms of access to pipeline transportation
+are subject to extensive federal and state regulation. From 1985 to the present,
+several major regulatory changes have been implemented by Congress and the FERC
+that affect the economics of natural gas production, transportation and sales.
+In addition, the FERC is continually proposing and implementing new rules and
+regulations affecting those segments of the natural gas industry that remain
+subject to the FERC's jurisdiction, most notably interstate natural gas
+transmission companies. These initiatives may also affect the intrastate
+transportation of gas under certain circumstances. The stated purpose of many of
+these regulatory changes is to promote competition among the various sectors of
+the natural gas industry, and these initiatives generally reflect more
+light-handed regulation.
+The ultimate impact of the complex rules and regulations issued by the
+FERC since 1985 cannot be predicted. In addition, many aspects of these
+regulatory developments have not become final but are still pending judicial and
+final FERC decisions. We cannot predict what further action the FERC will take
+on these matters. Some of the FERC's more recent proposals may, however,
+adversely affect the availability and reliability of interruptible
+transportation service on interstate pipelines. Additional proposals and
+proceedings that might affect the natural gas industry are pending before
+Congress and the courts. The natural gas industry historically has been very
+heavily regulated; therefore, there is no assurance that the less stringent
+regulatory approach recently pursued by the FERC and Congress will continue. We
+do not believe that we will be affected by any action taken that differs
+materially from other natural gas producers and marketers with whom we compete.
+Our sales of crude oil, condensate and natural gas liquids are
+currently not regulated and are made at market prices. However, in a number of
+instances the ability to transport and sell such products are dependent on
+pipelines whose rates, terms and conditions of service are subject to FERC
+jurisdiction under the Interstate Commerce Act. Certain regulations implemented
+by the FERC in recent years could result in an increase in the cost of
+transportation service on certain petroleum product pipelines. We do not believe
+that these regulations affect us any differently than other producers of these
+products.
+Certain operations we conduct are on federal oil and gas leases that
+the Minerals Management Service administers. The MMS issues such leases through
+6
+competitive bidding. These leases contain relatively standardized terms and
+require compliance with detailed MMS regulations and, for offshore leases,
+orders pursuant to the Outer Continental Shelf Lands Act, which are subject to
+change by the MMS. For offshore operations, lessees must obtain MMS approval for
+exploration plans and development and production plans prior to the commencement
+of such operations. In addition to permits required from other agencies such as
+the Coast Guard, the Army Corps of Engineers and the Environmental Protection
+Agency, lessees must obtain a permit from the MMS prior to the commencement of
+drilling. Lessees must also comply with detailed MMS regulations governing,
+among other things:
+o engineering and construction specifications for offshore
+production facilities;
+o safety procedures;
+o flaring of production;
+o plugging and abandonment of Outer Continental Shelf or OCS
+wells;
+o calculation of royalty payments and the valuation of
+production for this purpose; and
+o removal of facilities.
+To cover the various obligations of lessees on the OCS, the MMS
+generally requires that lessees post substantial bonds or other acceptable
+assurances that such obligations will be met. The cost of such bonds or other
+surety can be substantial, and we cannot assure that we can continue to obtain
+bonds or other surety in all cases. Under certain circumstances the MMS may
+require our operations on federal leases to be suspended or terminated.
+Many of the states in which we conduct our oil and gas drilling and
+production activities regulate such activities by requiring, among other things,
+drilling permits and bonds and reports concerning operations. The laws of these
+states also govern a number of environmental and conservation matters, including
+the handling and disposing of waste material, plugging and abandonment of wells,
+restoration requirements, unitization and pooling of natural gas and oil
+properties and establishment of maximum rates of production from natural gas and
+oil wells. Some states prorate production to the market demand for oil and
+natural gas.
+Environmental Regulations. Our operations are subject to numerous laws
+and regulations governing the discharge of materials into the environment or
+otherwise relating to environmental protection. These laws and regulations may
+require the acquisition of a permit before drilling commences, restrict the
+types, quantities and concentration of various substances that can be released
+into the environment in connection with drilling and production activities,
+limit or prohibit drilling activities on certain lands lying within wilderness,
+wetlands and other protected areas, and impose substantial liabilities for any
+pollution resulting from our operations.
+Public interest in the protection of the environment has increased
+dramatically in recent years. Onshore and offshore drilling in some areas has
+been opposed by environmental groups and, in some areas, has been restricted.
+Legislation has also been proposed in Congress from time to time that would
+reclassify certain oil and gas exploration and production wastes as "hazardous
+wastes," which would make the reclassified wastes subject to much more stringent
+handling, disposal and clean-up requirements. To the extent laws are enacted or
+other governmental actions are taken that prohibit or restrict offshore drilling
+7
+or impose environmental protection requirements that result in increased costs
+to the natural gas and oil industry (both onshore and offshore), our business
+and prospects could be adversely affected. We believe that we are in substantial
+compliance with current applicable environmental laws and regulations and that
+continued compliance with existing requirements would not have a material
+adverse impact on us.
+Violation of environmental laws and regulations can lead to the
+imposition of administrative, civil or criminal penalties; remedial obligations;
+and in some instances injunctive relief. In addition, violations of
+environmental laws or the discharge of hazardous materials or oil could result
+in liability for personal injuries, property damage, remediation and cleanup
+costs, and other environmental damages. As a result, substantial liabilities to
+third parties or governmental entities may be incurred, and the payment of such
+liabilities could have a material adverse effect on our financial condition and
+results of operations.
+The Oil Pollution Act and regulations thereunder impose a variety of
+regulations on "responsible parties" related to the prevention of oil spills and
+liability for damages resulting from such spills in United States waters. A
+"responsible party" includes the owner or operator of an onshore facility,
+pipeline or vessel, or the lessee or permittee of the area in which an offshore
+facility is located. The OPA assigns liability to each responsible party for oil
+cleanup costs and a variety of public and private damages. While liability
+limits apply in some circumstances, a party cannot take advantage of liability
+limits if the spill was caused by gross negligence or willful misconduct or
+resulted from violation of a federal safety, construction or operating
+regulation. Likewise, if the party fails to report a spill or to cooperate fully
+in the cleanup, liability limits do not apply. Even if applicable, the liability
+limits for offshore facilities require the responsible party to pay all removal
+costs, plus up to $75 million in other damages. Few defenses exist to the
+liability imposed by the OPA.
+The OPA imposes ongoing requirements on a responsible party, including
+the preparation of oil spill response plans and proof of financial
+responsibility to cover environmental cleanup and restoration costs that could
+be incurred in connection with an oil spill. As amended by the Coast Guard
+Authorization Act of 1996, the OPA requires responsible parties for covered
+offshore facilities that have a worst case oil spill of more than 1,000 barrels
+to demonstrate financial responsibility in amounts ranging from at least $10
+million in specified state waters to at least $35 million in federal outer
+continental shelf waters, with higher amounts of up to $150 million if a formal
+risk assessment indicates that a higher amount should be required based on
+specific risks posed by the operations or if the worst case oil spill discharge
+volume possible at the facility may exceed the applicable threshold volumes
+specified under the final rule of the MMS implementing these financial
+responsibility requirements as enacted in August 1998. We do not anticipate that
+we will experience any difficulty in continuing to satisfy the MMS requirements
+for demonstrating financial responsibility under the OPA.
+The Federal Water Pollution Control Act, also known as the Clean Water
+Act, imposes restrictions and strict controls regarding the discharge of
+produced waters and other oil and gas wastes into navigable waters. Permits must
+be obtained to discharge pollutants into waters and to conduct construction
+activities in waters and wetlands. The FWPCA and similar state laws provide for
+civil, criminal and administrative penalties for any unauthorized discharges of
+pollutants and unauthorized discharges of reportable quantities of oil and other
+hazardous substances. Many state discharge regulations and the general permits
+from the Federal National Pollutant Discharge Elimination System prohibit the
+discharge of produced water and sand, drilling fluids, drill cuttings and
+certain other substances related to the oil and gas industry into coastal
+waters. Although the costs to comply with zero discharge mandates under federal
+or state law may be significant, the entire industry is expected to experience
+similar costs, and we believe that these costs will not have a material adverse
+8
+impact on our results of operations or financial position. The United States
+Environmental Protection Agency has adopted regulations requiring certain oil
+and gas exploration and production facilities to obtain permits for storm water
+discharges. Costs may be associated with the treatment of wastewater or
+developing and implementing storm water pollution prevention plans.
+The Comprehensive Environmental Response, Compensation, and Liability
+Act, also known as the "Superfund" law, imposes liability, without regard to
+fault or the legality of the original conduct, on certain classes of persons
+that are considered to be responsible for the release of a "hazardous substance"
+into the environment. These persons, including the owner or operator of the
+disposal site or sites where the release occurred and companies that transported
+or disposed or arranged for the transport or disposal of the hazardous
+substances under CERCLA, may be subject to joint and several liability for the
+costs of cleaning up the hazardous substances that have been released into the
+environment and for damages to natural resources. It is not uncommon for
+neighboring landowners and other third parties to file claims for personal
+injury and property damage allegedly caused by the hazardous substances released
+into the environment.
+We generate both hazardous and nonhazardous solid wastes which are
+subject to requirements of the Federal Resource Conservation and Recovery Act
+and comparable state statutes. From time to time, the EPA has considered making
+changes in nonhazardous waste standards that would result in stricter disposal
+requirements for these wastes. Furthermore, it is possible that some wastes that
+we generate that are currently classified as nonhazardous may be in the future
+be designated as "hazardous wastes," resulting in the wastes being subject to
+more rigorous and costly disposal requirements. Changes in applicable
+regulations may result in an increase in our capital expenditures or operating
+expenses.
+We currently own or lease, and have in the past owned or leased,
+onshore properties that for many years have been utilized for or associated with
+the exploration and production of oil and gas. Although we have utilized
+operating and disposal practices that were standard in the industry at the time,
+hydrocarbons or other wastes may have been disposed of or released on or under
+the properties owned or leased by us or on or under other locations where such
+wastes have been taken for disposal. These properties and the wastes disposed
+thereon may be subject to CERCLA, RCRA and analogous state laws. Under such
+laws, we could be required to remove or remediate previously disposed wastes
+(including waste disposed of or released by prior owners or operators) or
+property contamination (including groundwater contamination by prior owners or
+operators), or to perform remedial plugging or closure operations to prevent
+future contamination.
+Our operations are also subject to the Federal Clean Air Act and
+comparable state statutes. Amendments to the Clean Air Act adopted in 1990
+contain provisions that may result in the imposition of increasingly stringent
+pollution control requirements with respect to air emissions from the operations
+of stationary and mobile source equipment. Such air pollution control
+requirements may include specific equipment or technologies, permits with
+emissions and operational limitations, pre-approval of new or modified projects
+or facilities producing air emissions, and similar measures. Failure to comply
+with applicable air statutes or regulations may lead to the assessment of
+administrative, civil or criminal penalties, and/or result in the limitation or
+cessation of construction or operation of certain air emission sources.
+9
+Risk Factors
+Risks Related to Our Business
+In addition to the other information set forth elsewhere in this Form
+10-K, the following factors should be carefully considered when evaluating St.
+Mary.
+Oil and natural gas prices are volatile, and an extended decline in prices would
+hurt our profitability and financial condition.
+Our revenues, operating results, profitability, future rate of growth
+and the carrying value of our oil and gas properties depend heavily on
+prevailing market prices for oil and gas. We expect the markets for oil and gas
+to continue to be volatile. Any substantial or extended decline in the price of
+oil or gas would have a material adverse effect on our financial condition and
+results of operations. It could reduce our cash flow and borrowing capacity, as
+well as the value and the amount of our oil and gas reserves. Lower prices may
+also reduce the amount of oil and gas that we can economically produce.
+Historically, the markets for oil and gas have been volatile, and they
+are likely to continue to be volatile. Wide fluctuations in oil and gas prices
+may result from relatively minor changes in the supply of and demand for oil and
+gas, market uncertainty and other factors that are beyond our control,
+including:
+o worldwide and domestic supplies of oil and natural gas;
+o the ability of the members of the Organization of Petroleum
+Exporting Countries to agree to and maintain oil price and
+production controls;
+o political instability or armed conflict in oil or gas
+producing regions;
+o the price and level of foreign imports;
+o worldwide economic conditions;
+o marketability of production;
+o the level of consumer demand;
+o the price, availability and acceptance of alternative fuels;
+o the availability of pipeline capacity;
+o weather conditions; and
+o actions of federal, state, local and foreign authorities.
+These external factors and the volatile nature of the energy markets
+make it difficult to estimate future prices of oil and natural gas. Declines in
+oil and gas prices would reduce our revenue and could also reduce the amount of
+oil and gas that we can produce economically and, as a result, could have a
+material adverse effect on our financial condition, results of operations and
+reserves. Further, oil and gas prices do not necessarily move in tandem. Because
+10
+approximately 56% of our proved reserves were natural gas reserves as of
+December 31, 2002, our financial results are slightly more affected by changes
+in natural gas prices.
+A material portion of our production, revenues and cash flows are derived from
+one field.
+Production from the Judge Digby Field accounted for approximately 10%
+of our total oil and gas production volumes during 2002. If the level of
+production from this field substantially declines other than through normal
+depletion over the expected reserve life, it could have a material adverse
+impact on our overall production levels and our revenues.
+Our future success depends on our ability to replace reserves that we produce.
+Our future success depends on our ability to find, develop and acquire
+oil and gas reserves that are economically recoverable. As of December 31, 2002
+our proved reserves would last approximately 8.9 years if produced constantly at
+the 2002 rate of production. In order to maintain current production rates we
+must locate and develop or acquire new oil and gas reserves to replace those
+being depleted by production. We may do this even during periods of low oil and
+gas prices. Without successful exploration or acquisition activities, our
+reserves, production and revenues will decline rapidly. In addition,
+approximately 12% of our total estimated proved reserves at December 31, 2002,
+were undeveloped. By their nature, undeveloped reserves are less certain.
+Recovery of such reserves will require significant capital expenditures and
+successful drilling operations. We cannot assure you that we will be able to
+find and develop or acquire additional reserves at an acceptable cost.
+Our producing property acquisitions carry significant risks.
+Our recent growth is due in part to, and our growth strategy relies in
+part on, acquisitions of producing properties and exploration and production
+companies. Successful acquisitions require an assessment of a number of factors
+beyond our control. These factors include recoverable reserves, future oil and
+gas prices, operating costs and potential environmental and other liabilities.
+These assessments are inexact and their accuracy is inherently uncertain. In
+connection with these assessments, we perform a review of the subject properties
+that we believe is generally consistent with industry practices. However, such a
+review will not reveal all existing or potential problems. In addition, our
+review may not permit us to become sufficiently familiar with the properties to
+fully assess their deficiencies and capabilities. We do not inspect every well.
+Even when we do inspect a well, we may not always discover structural,
+subsurface or environmental problems that may exist or arise.
+In connection with our acquisitions, we may not be entitled to
+contractual indemnification for preclosing liabilities, including environmental
+liabilities. Normally, we acquire interests in properties on an "as is" basis
+with limited remedies for breaches of representations and warranties. In
+addition, competition for producing oil and gas properties is intense and many
+of our competitors have financial and other resources substantially greater than
+those available to us. Therefore, we cannot assure you that we will be able to
+acquire oil and gas properties that contain economically recoverable reserves or
+that we will acquire such properties at acceptable prices.
+Additionally, significant acquisitions can change the nature of our
+operations and business depending upon the character of the acquired properties,
+which may have substantially different operating and geological characteristics
+or be in different geographic locations than our existing properties. While it
+11
+is our current intention to continue to concentrate on acquiring properties with
+development, exploitation and exploration potential located in our five core
+operating areas, we cannot assure you that in the future we will not decide to
+pursue acquisitions of properties located in other geographic regions. To the
+extent that such acquired properties are substantially different than our
+existing properties, our ability to efficiently realize the expected economic
+benefits of such transactions may be limited.
+We may not be able to successfully integrate future property or corporate
+acquisitions.
+We seek to make selective niche acquisitions of oil and gas properties,
+and we will pursue corporate acquisitions that we believe will be accretive.
+However, integrating acquired properties and businesses involves a number of
+special risks. These risks include the possibility that management may be
+distracted from normal business concerns by the need to integrate operations and
+systems and in retaining and assimilating additional employees. Any of these or
+other similar risks could lead to potentially adverse short-term or long-term
+effects on our operating results. We cannot assure you that we will be able to
+obtain adequate funds for future property or corporate acquisitions,
+successfully integrate our future property or corporate acquisitions or that we
+will realize any of the anticipated benefits of the acquisitions.
+Substantial capital is required to replace and grow reserves.
+We make, and will continue to make, substantial expenditures to find,
+acquire, develop and produce oil and natural gas reserves. Our capital
+expenditures for oil and gas properties were $193.0 million for 2002 and $182.9
+million during 2001. We have budgeted total capital expenditures of $225.0
+million in 2003. With the cash provided by operating activities and borrowings
+under our credit facility, we believe we will have sufficient cash to fund
+budgeted capital expenditures in 2003. If additional development or attractive
+acquisition opportunities arise, we may consider other forms of financing,
+including the public offering or private placement of equity or debt securities.
+However, if oil and gas prices decrease or we encounter operating difficulties
+that result in our cash flow from operations being less than expected, we may
+have to reduce the capital we can spend in future years unless we raise
+additional funds through debt or equity financing. We cannot assure you that
+debt or equity financing, cash generated by operations or borrowing capacity
+will be available to us on acceptable terms to meet these requirements.
+Future cash flows and the availability of financing will be subject to
+a number of variables, such as:
+o our success in locating and producing new reserves;
+o the level of production from existing wells;
+o prices of oil and natural gas;
+o lease operating expense, including workovers and taxes; and
+o administrative expense.
+Issuing equity securities to satisfy our financing requirements could
+cause substantial dilution to existing stockholders. Debt financing could lead
+to:
+12
+o a substantial portion of our operating cash flow being
+dedicated to the payment of principal and interest;
+o us being more vulnerable to competitive pressures and economic
+downturns; and
+o restrictions on our operations.
+If our revenues were to decrease due to lower oil and natural gas
+prices, decreased production or other reasons, and if we could not obtain
+capital through our credit facility or otherwise, our ability to execute our
+development plans, replace our reserves or maintain production levels could be
+greatly limited.
+We may not obtain a bank credit facility borrowing base redetermination that
+adequately meets our anticipated financing needs.
+We closed a new long-term revolving credit facility in January 2003
+with a 9-bank group led by Wachovia Bank. Under the facility, the maximum loan
+amount is $300.0 million. The amount actually available from time to time
+depends on a borrowing base that the lenders periodically redetermine based on
+the value of our oil and gas properties and other assets. The stated total
+borrowing base is $215.0 million and will be increased to $250.0 million after
+sufficient mortgage collateral has been provided to the banks. Since we pay
+commitment fees based on the unused portion of the borrowing base, we have
+reduced the commitment that we have accepted under the borrowing base to $150.0
+million to correspond with our projected funding requirements.
+Our next borrowing base redetermination date is scheduled to occur on
+or about April 15, 2003. We cannot assure you that the banks will agree to a
+borrowing base redetermination that is adequate for our anticipated financing
+needs.
+If oil and gas prices decrease or exploration efforts are unsuccessful, we may
+be required to take additional writedowns.
+There is a risk that we will be required to write down the carrying
+value of our oil and gas properties. This could occur when oil and gas prices
+are low or if we have substantial downward adjustments to our estimated proved
+reserves, increases in our estimates of development costs or deterioration in
+our exploration results.
+We follow the successful efforts accounting method. All property
+acquisition costs and costs of exploratory and development wells are capitalized
+when incurred, pending the determination of whether proved reserves have been
+discovered. If proved reserves are not discovered with an exploratory well, the
+costs of drilling the well are expensed. All geological and geophysical costs on
+exploratory prospects are expensed as incurred. The capitalized costs of our oil
+and gas properties, on a field-by-field basis, may not exceed the estimated
+future net cash flows of that field. If capitalized costs exceed future net
+revenues we write down the costs of each such field to our estimate of fair
+market value. Unproved properties are evaluated at the lower of cost or fair
+market value. This type of charge will not affect our cash flow from operating
+activities, but it will reduce the book value of our stockholders' equity. We
+review the carrying value of our properties quarterly, based on prices in effect
+as of the end of each quarter or as of the time of reporting our results. Once
+incurred, a writedown of oil and gas properties is not reversible at a later
+13
+date even if oil or gas prices increase. St. Mary incurred impairment and
+abandonment charges on proved and unproved properties of $2.4 million, $4.7
+million and $6.3 million in 2002, 2001 and 2000, respectively.
+Information concerning our reserves and future net revenue estimates is
+uncertain.
+There are numerous uncertainties inherent in estimating quantities of
+proved oil and natural gas reserves and their values, including many factors
+beyond our control. Estimates of proved undeveloped reserves, which comprise a
+significant portion of our reserves, are by their nature uncertain. The reserve
+data included in this Annual Report on Form 10-K is estimated. Although we
+believe these estimates are reasonable, actual production, revenues and reserve
+expenditures will likely vary from estimates, and these variances may be
+material.
+Estimates of oil and natural gas reserves, by necessity, are
+projections based on geologic and engineering data, and there are uncertainties
+inherent in the interpretation of such data as well as the projection of future
+rates of production and the timing of development expenditures. Reserve
+engineering is a subjective process of estimating underground accumulations of
+oil and natural gas that are difficult to measure. The accuracy of any reserve
+estimate is a function of the quality of available data, engineering and
+geological interpretation and judgment. Estimates of economically recoverable
+oil and natural gas reserves and future net cash flows necessarily depend upon a
+number of variable factors and assumptions, such as historical production from
+the area compared with production from other producing areas, the assumed
+effects of regulations by governmental agencies and assumptions governing future
+oil and natural gas prices, future operating costs, severance and excise taxes,
+development costs and workover and remedial costs, all of which may in fact vary
+considerably from actual results. For these reasons, estimates of the
+economically recoverable quantities of oil and natural gas attributable to any
+particular group of properties, classifications of such reserves based on risk
+of recovery, and estimates of the future net cash flows may vary substantially.
+Any significant variance in the assumptions could materially affect the
+estimated quantity and value of the reserves. Actual production, revenues and
+expenditures with respect to our reserves will likely vary from estimates, and
+such variances may be material. See "Business and Properties--Reserves."
+In addition, you should not construe PV-10 value as the current market
+value of the estimated oil and natural gas reserves attributable to our
+properties. We have based the PV-10 value on prices and costs as of the date of
+the estimate, in accordance with applicable regulations, whereas actual future
+prices and costs may be materially higher or lower. For example, values of our
+reserves at December 31, 2002 were estimated starting with a calculated weighted
+average sales price of $31.20 per barrel of oil (NYMEX) and $4.74 per MMBtu of
+gas (Gulf Coast spot price), then adjusted for transportation, quality and basis
+differentials. During 2002 our monthly average realized gas prices were as high
+as $3.99 per Mcf and as low as $2.24 per Mcf. For the same period our monthly
+average realized oil prices were as high as $27.66 per Bbl and as low as $17.72
+per Bbl. Many factors will affect actual future net cash flows, including:
+o the amount and timing of actual production;
+o supply and demand for oil and natural gas;
+o curtailments or increases in consumption by natural gas
+purchasers; and
+o changes in governmental regulations or taxation.
+14
+The timing of the production of oil and natural gas properties and of
+the related expenses affect the timing of actual future net cash flows from
+proved reserves and, thus, their actual present value. In addition, the 10%
+discount factor, which we are required to use to calculate PV-10 value for
+reporting purposes, is not necessarily the most appropriate discount factor
+given actual interest rates and risks to which our business or the oil and
+natural gas industry in general are subject. As a result, our actual future net
+cash flows could be materially different from the estimates included in this
+Annual Report on Form 10-K.
+Our industry is highly competitive.
+Major oil companies, independent producers, and institutional and
+individual investors are actively seeking oil and gas properties throughout the
+world, along with the equipment, labor and materials required to operate
+properties. Many of our competitors have financial and technological resources
+vastly exceeding those available to us. Many oil and gas properties are sold in
+a competitive bidding process in which we may lack technological information or
+expertise available to other bidders. We cannot be sure that we will be
+successful in acquiring and developing profitable properties in the face of this
+competition.
+Exploration and development drilling may not result in commercially productive
+reserves.
+Oil and gas drilling and production activities are subject to numerous
+risks, including the risk that no commercially productive oil or natural gas
+will be found. The cost of drilling and completing wells is often uncertain, and
+oil and gas drilling and production activities may be shortened, delayed or
+canceled as a result of a variety of factors, many of which are beyond our
+control. These factors include:
+o unexpected drilling conditions;
+o pressure or irregularities in formations;
+o equipment failures or accidents;
+o adverse weather conditions;
+o shortages in experienced labor;
+o compliance with governmental requirements; and
+o shortages or delays in the availability of drilling rigs and
+the delivery of equipment.
+The prevailing prices of oil and gas also affect the cost of and the
+demand for drilling rigs, production equipment and related services.
+We cannot assure you that the wells we drill will be productive or that
+we will recover all or any portion of our investment in such wells. The seismic
+data and other technologies we use do not allow us to know conclusively prior to
+drilling a well that oil or gas is present or may be produced economically. The
+cost of drilling, completing and operating a well is often uncertain, and cost
+factors can adversely affect the economics of a project. Drilling activities can
+result in dry wells or wells that are productive but do not produce sufficient
+net revenues after operating and other costs to cover initial drilling costs.
+15
+Our future drilling activities may not be successful, nor can we be
+sure that our overall drilling success rate or our drilling success rate for
+activity within a particular area will not decline. Unsuccessful drilling
+activities could have a material adverse effect on our results of operations and
+financial condition. Also, we may not be able to obtain any options or lease
+rights in potential drilling locations that we identify. Although we have
+identified numerous potential drilling locations, we cannot be sure that we will
+ever drill them or that we will produce oil or natural gas from them or any
+other potential drilling locations.
+Our business is subject to operating hazards that could result in substantial
+losses.
+Oil and gas operations are subject to many risks, including well
+blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
+well fluids, fires, formations with abnormal pressures, pipeline ruptures or
+spills, pollution, releases of toxic gas and other environmental hazards and
+risks. If any of these hazards occurs, we could sustain substantial losses as a
+result of:
+o injury or loss of life;
+o severe damage to or destruction of property, natural resources
+and equipment;
+o pollution or other environmental damage;
+o clean-up responsibilities;
+o regulatory investigations and penalties; and/or
+o suspension of operations.
+In addition, we may be liable for environmental damage caused by
+previous owners of property we own or lease. As a result, we may face
+substantial liabilities to third parties or governmental entities, which could
+reduce or eliminate funds available for exploration, development or acquisitions
+or cause us to incur losses. An event that is not fully covered by insurance
+could have a material adverse effect on our financial condition and results of
+operations.
+We maintain insurance against some, but not all, of these potential
+risks and losses. We may elect not to obtain insurance if we believe that the
+cost of available insurance is excessive relative to the risks presented. In
+addition, pollution and environmental risks generally are not fully insurable.
+If a significant accident or other event occurs and is not fully covered by
+insurance, it could adversely affect us.
+Other independent oil and gas companies' limited access to capital may change
+our exploration and development plans.
+Many independent oil and gas companies have limited access to the
+capital necessary to finance their activities. As a result, some of the other
+working interest owners of our wells may be unwilling or unable to pay their
+share of the costs of projects as they become due. These problems could cause us
+to change, suspend or terminate our drilling and development plans with respect
+to the affected project.
+16
+Hedging transactions may limit our potential gains and involve other risks.
+To manage our exposure to price risks in the marketing of our oil and
+natural gas, we enter into commodity price risk management arrangements from
+time to time with respect to a portion of our current or future production.
+While intended to reduce the effects of volatile oil and natural gas prices,
+these transactions may limit our potential gains if oil or natural gas prices
+were to rise substantially over the price established by the hedge. In addition,
+such transactions may expose us to the risk of financial loss in certain
+circumstances, including instances in which:
+o our production is less than expected;
+o the counterparties to our futures contracts fail to perform
+under the contracts; or
+o a sudden, unexpected event materially impacts oil or natural
+gas prices.
+The terms of our hedging agreements may also require that we furnish
+cash collateral, letters of credit or other forms of performance assurance in
+the event that mark-to-market calculations result in settlement obligations by
+us to the counterparties, which would encumber our liquidity and capital
+resources.
+Our industry is heavily regulated.
+Federal, state and local authorities extensively regulate the oil and
+gas industry. Legislation and regulations affecting the industry are under
+constant review for amendment or expansion, raising the possibility of changes
+that may affect, among other things, the pricing or marketing of oil and gas
+production. Noncompliance with statutes and regulations may lead to substantial
+penalties, and the overall regulatory burden on the industry increases the cost
+of doing business and, in turn, decreases profitability. State and local
+authorities regulate various aspects of oil and gas drilling and production
+activities, including the drilling of wells (through permit and bonding
+requirements), the spacing of wells, the unitization or pooling of oil and gas
+properties, environmental matters, safety standards, the sharing of markets,
+production limitations, plugging and abandonment, and restoration. Federal
+authorities regulate many of these same activities for our drilling and
+production operations in federal offshore waters. To cover the various
+obligations of leaseholders in federal waters, federal authorities generally
+require that leaseholders have substantial net worth or post bonds or other
+acceptable assurances that such obligations will be met. The cost of these bonds
+or other surety can be substantial, and we cannot assure you that we will be
+able to obtain bonds or other surety in all cases. Under some circumstances,
+federal authorities may require any of our operations on federal leases be
+suspended or terminated. Any such suspension or termination could materially
+adversely affect our financial condition and results of operations.
+We must comply with complex environmental regulations.
+Our operations are subject to complex and constantly changing
+environmental laws and regulations adopted by federal, state and local
+governmental authorities where we are engaged in exploration or production
+operations. New laws or regulations, or changes to current requirements, could
+have a material adverse effect on our business. We will continue to be subject
+to uncertainty associated with new regulatory interpretations and inconsistent
+interpretations between state and federal agencies. We could face significant
+liabilities to the government and third parties for discharges of oil, natural
+gas or other pollutants into the air, soil or water, and we could have to spend
+substantial amounts on investigations, litigation and remediation. We cannot be
+sure that existing environmental laws or regulations, as currently interpreted
+17
+or enforced, or as they may be interpreted, enforced or altered in the future,
+will not materially adversely affect our results of operations and financial
+condition. As a result, we may face material indemnity claims with respect to
+properties we own or have owned.
+Our business depends on transportation facilities owned by others.
+The marketability of our oil and gas production depends in part on the
+availability, proximity and capacity of pipeline systems owned by third parties.
+The unavailability of or lack of available capacity on these systems and
+facilities could result in the shut-in of producing wells or the delay or
+discontinuance of development plans for properties. Although we have some
+contractual control over the transportation of our product, material changes in
+these business relationships could materially affect our operations. Federal and
+state regulation of oil and gas production and transportation, tax and energy
+policies, changes in supply and demand, pipeline pressures, damage to or
+destruction of pipelines and general economic conditions could adversely affect
+our ability to produce, gather and transport oil and natural gas.
+We depend on key personnel.
+Our success will continue to depend on the continued services of our
+executive officers and a limited number of other senior management and technical
+personnel with extensive experience and expertise in evaluating and analyzing
+producing oil and gas properties and drilling prospects, maximizing production
+from oil and gas properties and marketing oil and gas production. Loss of the
+services of any of these people could have a material adverse effect on our
+operations. We currently do not have employment agreements with our executive
+officers other than Mark Hellerstein, our Chief Executive Officer. We do not
+carry any key person life insurance policies.
+Ownership of working interests, royalty interests and other interests by some of
+our officers and directors may create conflicts of interest.
+As a result of their prior employment with another company with which
+St. Mary engaged in a number of transactions, Ronald D. Boone, the Executive
+Vice President and Chief Operating Officer and a director of St. Mary, and two
+other vice presidents of St. Mary own royalty interests in many of St. Mary's
+properties, which were earned as part of the prior employer's employee benefit
+programs. One vice president also owns certain working interests through
+participation in acquisitions made by his former employer. Those persons have no
+royalty participation in any new St. Mary properties.
+Mr. Boone also owns 25% of Princeton Resources LLC, which owns the oil
+and gas working interests that he acquired as a result of his prior employment.
+Although Mr. Boone does not manage this entity, he may participate in any
+investment decisions made by them.
+As a result of these transactions and relationships, conflicts of
+interest may exist between these persons and us. Although these persons owe
+fiduciary duties to our stockholders and to us, we cannot assure you that
+conflicts of interest will always be resolved in our favor.
+Risks Related to Our Common Stock
+Our certificate of incorporation and bylaws have provisions that discourage
+corporate takeovers and could prevent shareholders from realizing a premium on
+their investment.
+18
+Our certificate of incorporation and bylaws contain provisions that may
+have the effect of delaying or preventing a change of control. These provisions,
+among other things, provide for noncumulative voting in the election of the
+board of directors and impose procedural requirements on stockholders who wish
+to make nominations for the election of directors or propose other actions at
+stockholders' meetings. These provisions, alone or in combination with each
+other and with the rights plan described below, may discourage transactions
+involving actual or potential changes of control, including transactions that
+otherwise could involve payment of a premium over prevailing market prices to
+shareholders for their common stock
+On July 15, 1999, our board of directors adopted a stockholder rights
+plan. The plan is designed to enhance the board's ability to prevent an acquirer
+from depriving stockholders of the long-term value of their investment and to
+protect stockholders against attempts to acquire us by means of unfair or
+abusive takeover tactics. If the board of directors decides in accordance with
+its fiduciary obligations that the terms of a potential acquisition do not
+reflect the long-term value of St. Mary, under the plan the board of directors
+could allow the holder of each outstanding share of our common stock other than
+those held by the potential acquirer to purchase one additional share of our
+common stock with a market value of twice the exercise price. This prospective
+dilution to a potential acquirer would make the acquisition impracticable unless
+the terms were improved to the satisfaction of the board of directors. However,
+the existence of the plan may impede a takeover not supported by our board,
+including a takeover that may be desired by a majority of our stockholders or
+involving a premium over the prevailing stock price.
+Our shares that are eligible for future sale may have an adverse effect on the
+price of our common stock.
+At February 28, 2003, we had 31,433,900 shares of common stock
+outstanding. Of the shares outstanding, approximately 27,405,059 shares were
+freely tradable without substantial restriction or the requirement of future
+registration under the Securities Act. Also as of that date, options to purchase
+3,025,007 shares of our common stock were outstanding, of which 1,911,398 were
+exercisable. These options are exercisable at prices ranging from $9.25 to
+$33.3125 per share. Sales of substantial amounts of common stock, or a
+perception that such sales could occur, and the existence of options or warrants
+to purchase shares of commons stock at prices that may be below the then -
+current market price of the common stock could adversely affect the market price
+of the common stock and could impair our ability to raise capital through the
+sale of our equity securities.
+Our Former Chairman of the Board and his extended family may be able to control
+us.
+Thomas E. Congdon, a director and our former Chairman of the Board, and
+members of his extended family owned approximately 16% of the outstanding shares
+of our common stock as of February 28, 2003. While no formal arrangements exist,
+these extended family members may be inclined to act in concert with Mr. Congdon
+on matters related to control of St. Mary, including for example the election of
+directors or response to an unsolicited bid to acquire St. Mary. Accordingly,
+Mr. Congdon and his family may be able to control or influence matters presented
+to our stockholders.
+We may not always pay dividends on our common stock.
+Although we have paid cash dividends to stockholders every year since
+1940 and we expect that our practice of paying dividends will continue, the
+payment of future dividends remains in the discretion of the board of directors
+19
+and will continue to depend on our earnings, capital requirements, financial
+condition and other factors. In addition, the payment of dividends is subject to
+covenants in our bank credit facility, including the requirement that we
+maintain certain levels of stockholder's equity. The board of directors may
+determine in the future to reduce the current annual dividend rate of $0.10 per
+share or discontinue the payment of dividends altogether.
+Cautionary Statement about Forward-Looking Statements
+This Annual Report on Form 10-K includes certain statements that may be
+deemed to be "forward-looking statements" within the meaning of Section 27A of
+the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
+1934. All statements, other than statements of historical facts, included in
+this Form 10-K that address activities, events or developments that St. Mary's
+management expects, believes or anticipates will or may occur in the future are
+forward looking statements. Examples of forward-looking statements may include
+discussion of such matters as:
+o The amount and nature of future capital, development and
+exploration expenditures;
+o The drilling of wells;
+o Reserve estimates and the estimates of both future net
+revenues and the present value of future net revenues that are
+included in their calculation;
+o Future oil and gas production estimates;
+o Repayment of debt;
+o Business strategies;
+o Expansion and growth of operations; and
+o Other similar matters such as those discussed in Management's
+Discussion and Analysis of Financial Condition and Results of
+Operations.
+These statements are based on certain assumptions and analyses made by us in
+light of our experience and our perception of historical trends, current
+conditions, expected future developments and other factors we believe are
+appropriate in the circumstances. Such statements are subject to a number of
+assumptions, risks and uncertainties, including such factors as the volatility
+and level of oil and natural gas prices, uncertainties in cash flow, expected
+acquisition benefits, production rates and reserve replacement, reserve
+estimates, drilling and operating risks, competition, litigation, environmental
+matters, the potential impact of government regulations, and other matters
+discussed under the caption "Risk Factors", many of which are beyond our
+control. Readers are cautioned that forward-looking statements are not
+guarantees of future performance and that actual results or developments may
+differ materially from those expressed or implied in the forward-looking
+statements.
+20
+Available Information
+Our Internet website address is www.stmaryland.com. We make available
+free of charge through our website's financial information section our annual
+reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
+8-K, and amendments to those reports filed with or furnished to the SEC under
+applicable securities laws as soon as reasonably practical after we
+electronically file such material with, or furnish it to, the SEC. Our web site
+information is not incorporated by reference into this Annual Report on Form
+10-K.
+Glossary
+The terms defined in this section are used throughout this Annual
+Report on Form 10-K.
+2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a
+two-dimensional cross-section of the subsurface.
+3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a
+three-dimensional picture of the subsurface.
+Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
+reference to oil or other liquid hydrocarbons.
+Bcf. Billion cubic feet, used herein in reference to natural gas.
+BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using
+the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+Behind pipe reserves. Estimated net proved reserves in a formation in which
+production casing has already been set in the wellbore but has not been
+perforated and production tested.
+BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio
+of six Mcf of gas (including gas liquids) to one Bbl of oil.
+Development well. A well drilled within the proved area of an oil or gas
+reservoir to the depth of a stratigraphic horizon known to be productive in an
+attempt to recover proved undeveloped reserves.
+Dry hole. A well found to be incapable of producing either oil or gas in
+sufficient quantities to justify completion as an oil or gas well.
+Estimated net proved reserves. The estimated quantities of oil, gas and gas
+liquids which geological and engineering data demonstrate with reasonable
+certainty to be recoverable in future years from known reservoirs under existing
+economic and operating conditions.
+Exploratory well. A well drilled to find and produce oil or gas in an unproved
+area, to find a new reservoir in a field previously found to be productive of
+oil or gas in another reservoir, or to extend a known reservoir.
+Fee land. The most extensive interest that can be owned in land, including
+surface and mineral (including oil and gas) rights.
+21
+Finding cost. Expressed in dollars per BOE or MCFE. Finding costs are calculated
+by dividing the amount of total capital expenditures for oil and gas activities
+by the amount of estimated net proved reserves added during the same period
+(including the effect on proved reserves of reserve revisions).
+Gross acres. An acre in which a working interest is owned.
+Gross well. A well in which a working interest is owned.
+Hydraulic fracturing. A procedure to stimulate production by forcing a mixture
+of fluid and proppant (usually sand) into the formation under high pressure.
+This creates artificial fractures in the reservoir rock, which increases
+permeability and porosity.
+MBbl. One thousand barrels of oil or other liquid hydrocarbons.
+MMBbl. One million barrels of oil or other liquid hydrocarbons.
+MBOE. One thousand barrels of oil equivalent.
+MMBOE. One million barrels of oil equivalent.
+Mcf. One thousand cubic feet.
+MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined
+using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+MMcf. One million cubic feet.
+MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined
+using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+MMBtu. One million British Thermal Units. A British Thermal Unit is the heat
+required to raise the temperature of a one-pound mass of water one degree
+Fahrenheit.
+Net acres or net wells. The sum of the fractional working interests owned in
+gross acres or gross wells.
+Net asset value per share. The result of the fair market value of total assets
+less total liabilities, divided by the total number of outstanding shares of
+common stock.
+PV-10 value. The present value of estimated future gross revenue to be generated
+from the production of estimated net proved reserves, net of estimated
+production and future development costs, using prices and costs in effect as of
+the date indicated (unless such prices or costs are subject to change pursuant
+to contractual provisions), without giving effect to non-property related
+expenses such as general and administrative expenses, debt service and future
+income tax expenses or to depreciation, depletion and amortization, discounted
+using an annual discount rate of 10%.
+Productive well. A well that is producing oil or gas or that is capable of
+production.
+Proved developed reserves. Reserves that can be expected to be recovered through
+existing wells with existing equipment and operating methods.
+22
+Proved undeveloped reserves. Reserves that are expected to be recovered from new
+wells on undrilled acreage, or from existing wells where a relatively major
+expenditure is required for recompletion.
+Recompletion. The completion for production of an existing wellbore in another
+formation from that in which the well has previously been completed.
+Reserve life. Expressed in years, represents the estimated net proved reserves
+at a specified date divided by forecasted production for the preceding 12-month
+period.
+Royalty. The interest paid to the owner of mineral rights expressed as a
+percentage of gross income from oil and gas produced and sold unencumbered by
+expenses.
+Royalty interest. An interest in an oil and gas property entitling the owner to
+shares of oil and gas production free of costs of exploration, development and
+production. Royalty interests are approximate and are subject to adjustment.
+Undeveloped acreage. Lease acreage on which wells have not been drilled or
+completed to a point that would permit the production of commercial quantities
+of oil and gas, regardless of whether such acreage contains estimated net proved
+reserves.
+Working interest. The operating interest that gives the owner the right to
+drill, produce and conduct operating activities on the property and to share in
+the production.
\ No newline at end of file
diff --git a/raw/filings/0000893538/2002/0000893538-03-000008/item13.txt b/raw/filings/0000893538/2002/0000893538-03-000008/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..32705fa6a9452f5255bebf93bab374af494286ec
--- /dev/null
+++ b/raw/filings/0000893538/2002/0000893538-03-000008/item13.txt
@@ -0,0 +1,5 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+The information required by this Item is incorporated by reference to
+the information provided under the caption "Certain Relationships and Related
+Transactions" in St. Mary's definitive proxy statement for the 2003 annual
+meeting of stockholders to be filed within 120 days from December 31, 2002.
\ No newline at end of file
diff --git a/raw/filings/0000893538/2002/0000893538-03-000008/item9a.txt b/raw/filings/0000893538/2002/0000893538-03-000008/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2002/0000893538-03-000008/rp_note.txt b/raw/filings/0000893538/2002/0000893538-03-000008/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2002/0000893538-03-000008/rpt_disclosure.txt b/raw/filings/0000893538/2002/0000893538-03-000008/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..2e3a37cf100f06e712d318069a6d2c9c6a124dce
--- /dev/null
+++ b/raw/filings/0000893538/2002/0000893538-03-000008/rpt_disclosure.txt
@@ -0,0 +1,39 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+Set forth below is a description of transactions entered into between St.
+Mary and certain of its officers and directors during the last fiscal year. Some
+of these transactions will continue in effect and may result in conflicts of
+interest between St. Mary and these individuals. Although these persons owe
+fiduciary duties to St. Mary and its stockholders, we cannot assure you that
+conflicts of interest will always be resolved in favor of St. Mary.
+As a result of their prior employment with another company with which St.
+Mary engaged in a number of transactions, Ronald D. Boone, the Executive Vice
+President and Chief Operating Officer and a director of St. Mary, and two other
+vice presidents of St. Mary own royalty interests in many of St. Mary's
+properties, which were earned as part of the prior employer's employee benefit
+18
+programs. One vice president also owns certain working interests through
+participation in acquisitions made by his former employer. Those persons have no
+royalty participation in any new St. Mary properties.
+Mr. Boone also owns 25% of Princeton Energy LLC, which owns the oil and gas
+working interests that he acquired as a result of his prior employment. Although
+Mr. Boone does not manage this entity, he may participate in any investment
+decisions made by them.
+In July 2000, St. Mary made an interest-free loan of $200,000 to Robert T.
+Hanley at the time he was appointed Vice President - Business Development of St.
+Mary. The loan was made to enable Mr. Hanley to purchase a residence in Denver,
+Colorado in connection with St. Mary's relocation of Mr. Hanley to Denver from
+Billings, Montana, where housing costs are substantially lower. Mr. Hanley was
+previously Chief Financial Officer of Nance Petroleum Corporation, a wholly
+owned subsidiary that St. Mary acquired in June 1999, which has its principal
+offices in Billings. This loan was repaid in October 2002.
+St. Mary's by-laws provide that no director may pursue a business or
+investment opportunity for himself if he has obtained knowledge of such
+opportunity through his affiliation with the Company. Moreover, no officer or
+employee of St. Mary may pursue for his own account an oil and gas opportunity
+irrespective of the source of his knowledge of the opportunity unless (a) with
+respect to an officer of St. Mary, the interest has been approved by the board
+of directors and (b) with respect to a non-officer of St. Mary, such interest of
+the employee has been approved by a senior officer of St. Mary with full
+knowledge of such opportunity. These restrictions do not apply to the
+acquisition of less than one percent of the publicly traded stock of another
+company.
\ No newline at end of file
diff --git a/raw/filings/0000893538/2003/0000893538-04-000044/filing.txt b/raw/filings/0000893538/2003/0000893538-04-000044/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..ad652b64c295a17430aad0cdb28051440d8d34ba
--- /dev/null
+++ b/raw/filings/0000893538/2003/0000893538-04-000044/filing.txt
@@ -0,0 +1,5313 @@
+10-K
+1
+asci1203_10k.htm
+12/31/03 FORM 10-K
+12/03 10K 
+================================================================================
+UNITED STATES
+SECURITIES AND EXCHANGE COMMISSION
+Washington, D.C. 20549
+FORM 10-K
+[ x ] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
+Act of 1934
+For the fiscal year ended December 31, 2003
+or
+[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
+Exchange Act of 1934
+Commission file number 001-31539
+ST. MARY LAND & EXPLORATION COMPANY
+(Exact name of registrant as specified in its charter)
+Delaware 41-0518430
+(State or other jurisdiction (I.R.S. Employer Identification No.)
+of incorporation or organization)
+1776 Lincoln Street, Suite 700, Denver, Colorado 80203
+------------------------------------------------------
+(Address of principal executive offices) (Zip Code)
+(303) 861-8140
+(Registrant's telephone number, including area code)
+Securities registered pursuant to Section 12(b) of the Act:
+Title of each class Name of each exchange
+on which registered
+Common Stock, $.01 par value New York Stock Exchange
+---------------------------- -----------------------
+Securities registered pursuant to Section 12(g) of the Act:
+None
+Indicate by check mark whether the registrant (1) has filed all reports required
+to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
+the preceding 12 months (or for such shorter period that the registrant was
+required to file such reports), and (2) has been subject to such filing
+requirements for the past 90 days. Yes [ x ] No [ ]
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
+of Regulation S-K is not contained herein, and will not be contained, to the
+best of registrant's knowledge, in definitive proxy or information statements
+incorporated by reference in Part III of this Form 10-K or any amendment to this
+Form 10-K. [ ]
+Indicate by check mark whether the registrant is an accelerated filer (as
+defined in Rule 12-b-2 of the Act). Yes [ x ] No [ ]
+The aggregate market value of 26,911,648 shares of voting stock held by
+non-affiliates of the registrant, based upon the closing sale price of the
+common stock on June 30, 2003, the last business day of the registrant's most
+recently completed second fiscal quarter, of $24.06 per share as reported on the
+New York Stock Exchange was $647,494,251. Shares of common stock held by each
+director and executive officer and by each person who owns 10 percent or more of
+the outstanding common stock or who is otherwise believed by the Company to be
+in a control position have been excluded. This determination of affiliate status
+is not necessarily a conclusive determination for other purposes.
+As of February 20, 2004, the registrant had 28,339,963 shares of common stock
+outstanding.
+DOCUMENTS INCORPORATED BY REFERENCE
+Certain information required by Items 10, 11, 12, 13 and 14 of Part III is
+incorporated by reference from portions of the registrant's definitive proxy
+statement relating to its 2004 annual meeting of stockholders to be filed within
+120 days after December 31, 2003.
+================================================================================
+TABLE OF CONTENTS
+-----------------
+ITEM PAGE
+---- ----
+PART I
+ITEM 1. BUSINESS.........................................................1
+Background...................................................1
+Business Strategy............................................2
+Significant Developments Since December 31, 2002.............3
+Major Customers..............................................4
+Employees and Office Space...................................4
+Title to Properties..........................................5
+Seasonality..................................................5
+Competition..................................................5
+Government Regulations.......................................5
+Risk Factors.................................................7
+Cautionary Statement about Forward-Looking Statements.......18
+Available Information.......................................19
+Glossary....................................................20
+ITEM 2. PROPERTIES......................................................22
+Operations..................................................22
+Acquisitions and Divestitures...............................25
+Reserves....................................................26
+Production..................................................27
+Productive Wells............................................28
+Drilling Activity...........................................28
+Acreage.....................................................29
+ITEM 3. LEGAL PROCEEDINGS...............................................30
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.............30
+ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT............................31
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED
+STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
+EQUITY SECURITIES...............................................32
+ITEM 6. SELECTED FINANCIAL DATA.........................................34
+i
+TABLE OF CONTENTS
+-----------------
+(Continued)
+ITEM PAGE
+---- ----
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
+CONDITION AND RESULTS OF OPERATIONS.............................36
+Overview of the Company.....................................36
+Overview of Liquidity and Capital Resources.................40
+Critical Accounting Policies and Estimates..................48
+Additional Comparative Data in Tabular Format...............52
+Comparison of Financial Results and Trends Between
+2003 and 2002...............................................53
+Comparison of Financial Results and Trends Between
+2002 and 2001...............................................54
+Other Liquidity and Capital Resource Information............56
+Accounting Matters..........................................56
+Environmental...............................................57
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
+MARKET RISK (included with the content of ITEM 7)...............57
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.....................57
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
+ACCOUNTING AND FINANCIAL DISCLOSURE.............................57
+ITEM 9A. CONTROLS AND PROCEDURES.........................................57
+PART III
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..............58
+ITEM 11. EXECUTIVE COMPENSATION..........................................58
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
+AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS..................58
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..................58
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES..........................58
+PART IV
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
+REPORTS ON FORM 8-K.............................................59
+ii
+PART I
+When we use the terms "St. Mary," "we," "us" or "our," we are referring
+to St. Mary Land & Exploration Company and its subsidiaries, unless the
+context otherwise requires. We have included technical terms important to an
+understanding of our business under "Glossary". Throughout this document we make
+statements that are classified as "forward-looking". Please refer to the
+"Cautionary Statement about Forward-Looking Statements" section of this document
+for an explanation of these types of statements.
+ITEM 1. BUSINESS
+Background
+We are an independent oil and gas company engaged in the exploration,
+exploitation, development, acquisition and production of natural gas and crude
+oil. We were founded in 1908 and incorporated in Delaware in 1915. Our primary
+objective is to invest in oil and gas producing assets that result in a superior
+return on equity while preserving underlying capital, resulting in a return on
+equity to stockholders that reflects capital appreciation as well as the payment
+of cash dividends. Our operations are focused in the following five core
+operating areas in the United States:
+o the Mid-Continent region in Oklahoma and northern Texas, primarily
+in the Anadarko and Arkoma basins, with significant activity in the
+Northeast Mayfield field in Beckham County, Oklahoma;
+o the ArkLaTex region that spans northern Louisiana and portions of
+Arkansas, Mississippi and eastern Texas, with the most recent
+activity in the James Lime Horizontal trend;
+o the Gulf Coast region, including the Judge Digby field and our
+fee property in St. Mary Parish, Louisiana;
+o the Rocky Mountain region consisting of the Williston Basin in
+eastern Montana and western North Dakota and the Powder River,
+Green River and Wind River basins in Wyoming. The most recent
+activity in the Rockies includes the dolomite formations under
+the Bakken Shale; continued exploration in the Red River
+formation, most recently in the Ridgelawn field; and our
+initiation of the development of coalbed methane reserves in the
+Hanging Woman Basin; and
+o the Permian Basin in eastern New Mexico and western Texas.
+As of December 31, 2003, we had estimated proved reserves of
+approximately 47.8 MMBbl of oil and 307.0 Bcf of natural gas, or a total of
+593.7 BCFE, 89 percent of which were proved developed and 52 percent of which
+were natural gas, with a PV-10 value of $1.3 billion. This represents a 21
+percent increase in reserve volumes and a 55 percent increase in PV-10 value
+from a year earlier. For the year ended December 31, 2003, we produced 76.9 BCFE
+representing average daily production of 210.7 MMCFE per day, a 40 percent
+increase over 2002.
+We focus our resources in selected domestic basins where we believe our
+expertise in geology, geophysics and drilling and completion techniques provides
+us with competitive advantages. We have assembled a balanced program of
+low-to-medium-risk development and exploitation projects to provide the
+foundation for steady growth, including a non-conventional gas play in the Rocky
+Mountain region. In 2003, we spent $146.5 million in capital expenditures
+related to drilling activities, $77.4 million on acquisition of oil and gas
+1
+properties and $7.5 million on acquisition of leasehold.
+We measure and rank our investment decisions based on their
+risk-adjusted estimated internal rate of return and return on investment. When
+we issue stock for the acquisition of properties or a corporate entity we base
+our investment decision on the transaction's impact on net asset value per
+share.
+In the past, we have sold selected assets when we believed attractive
+prices were available, and we will continue to evaluate such opportunities in
+the future. For example, in 2003 we sold certain oil and gas properties for
+total proceeds of approximately $23.5 million, resulting in a gain for financial
+reporting purposes of $7.3 million.
+We seek to develop our existing property base and acquire acreage with
+additional potential in our core areas. From January 1, 2001, through December
+31, 2003, we participated in the drilling or recompletion of 691 gross wells
+with an average success rate of 83 percent. During that same period we added
+estimated proved reserves of 483.5 BCFE at an average finding cost of $1.27 per
+MCFE. Our average annual production replacement was 260 percent during this
+three-year period, and our production has grown from an average daily rate of
+148.2 MMCFE per day in 2001 to 210.7 MMCFE per day in 2003.
+As of December 31, 2003, we had an acreage position of 2,004,749 gross
+(1,086,367 net) acres of which 1,284,367 gross (806,326 net) acres were
+undeveloped. Our current leasehold position represents a 75 percent increase on
+a gross acre basis and a 100 percent increase on a net acre basis over 2002. In
+addition to this acreage position, we have 24,914 net acres of fee properties in
+the highly prolific St. Mary Parish of Louisiana and mineral servitudes
+representing 14,296 gross (9,534 net) acres in Louisiana.
+For 2004 we have budgeted capital expenditures of $173.4 million for
+ongoing development, exploitation and exploration programs in our core operating
+areas and $100.0 million for the acquisition of oil and gas properties.
+Our principal offices are located at 1776 Lincoln Street, Suite 700,
+Denver, Colorado 80203, and our telephone number is (303) 861-8140.
+Business Strategy
+Our objective is to build stockholder value through consistent economic
+growth in reserves and production that increase net asset value and earnings per
+share. The principal elements of our strategy are as follows:
+o Maintain Focused Geographic Operations. We focus on exploration,
+development and acquisition activities in five core operating areas
+where we have built a balanced portfolio of proved reserves,
+development drilling opportunities, leasehold and non-conventional
+gas prospects. We believe that our increased leasehold position is a
+strategic asset. Our senior technical managers, each possessing over
+20 years of experience, head up regional technical offices supported
+by centralized administration from our Denver office. We believe
+that our long-standing presence, our established networks of local
+industry relationships and our acreage holdings in our core
+operating areas provide us with a competitive advantage. We believe
+these strengths and our organizational structure will allow us to
+continue to expand our operations without the need to
+proportionately increase the number of our employees.
+2
+o Continue Exploitation and Development of Existing Properties. We use
+our comprehensive base of geological, geophysical, engineering and
+production experience in each of our core operating areas to source
+prospects for our ongoing low-to-medium-risk development and
+exploitation programs. We conduct detailed geologic studies and use
+an array of technologies and tools including 2-D and 3-D seismic
+imaging, hydraulic fracturing and reservoir stimulation techniques,
+secondary recovery and specialized logging tools to enhance the
+potential of our existing properties. In 2003 we participated in the
+drilling or recompletion of 254 gross wells with an 83 percent
+success rate.
+o Make Selective Acquisitions. We seek to make selective niche
+acquisitions of oil and gas properties that complement our existing
+operations, offer economies of scale and provide further
+development, exploitation and exploration opportunities based on
+proprietary geologic concepts. We believe that the focus on
+relatively smaller negotiated transactions where we have specialized
+geologic knowledge or operating experience has enabled us to acquire
+attractively priced and under-exploited properties. In addition, we
+will pursue corporate acquisitions that we believe will be accretive
+and are capable of being integrated into the Company. Examples of
+this type of acquisition include our 1999 Nance Petroleum
+Corporation and King Ranch Energy, Inc. acquisitions, both of which
+were accomplished with the issuance of our common stock. A more
+recent example is the January 2003 acquisition of oil and gas
+properties from Flying J. Although this transaction was not a
+corporate acquisition, we used a combination of restricted stock, a
+loan to Flying J and options on our stock. We have budgeted $100
+million for acquisitions in 2004.
+o Control Operations. We believe it is important to control geologic
+and operational decisions as well as the timing of those decisions.
+As of December 31, 2003, we operated 70 percent of our properties on
+a reserve volume basis and 66 percent on a PV-10 value basis. We are
+the operator of properties representing approximately 75 percent of
+our 2004 capital budget.
+o Maintain Financial Flexibility. Conservative use of financial
+leverage has long been a critical element of our strategy. We
+believe that maintaining a strong balance sheet is a significant
+competitive advantage that enables us to pursue acquisition and
+other opportunities, especially in weaker price environments. It
+also provides us with the financial resources to weather periods of
+volatile commodity prices or escalating costs. Our debt to total
+capitalization ratio was less than 20 percent at the end of December
+2003.
+Significant Developments Since December 31, 2002
+o 2003 Acquisition of Oil and Gas Properties from Flying J. In January
+2003 St. Mary acquired oil and gas properties in our Rocky Mountain
+region from Flying J Oil & Gas Inc. and Big West Oil & Gas
+Inc. (collectively "Flying J"). This acquisition included properties
+located in the Williston, Powder River, Wind River and Green River
+basins with 91.4 BCFE of proved reserves as of the acquisition date
+and significant undeveloped leasehold acreage. During 2003 we
+produced 2,631 MMcf of gas and 778 MBbl of oil from the properties
+acquired from Flying J. As part of the transaction, we issued
+3,380,818 shares of restricted common stock, subject to a put and
+call option agreement. In addition, we made a nonrecourse loan to
+Flying J of $71.6 million, which was secured by a pledge of the
+shares issued. This transaction was valued for financial reporting
+purposes as an acquisition of oil and gas properties in exchange for
+$71.6 million in cash and a net option valued at $1.0 million. As
+discussed below, in February 2004 we repurchased the shares and
+Flying J repaid the loan.
+3
+o Increase in 2003 Year-End Reserves. Proved reserves increased 21
+percent to 593.7 BCFE at December 31, 2003, from 490.8 BCFE at
+December 31, 2002. We added 113.0 BCFE through acquisitions,
+primarily in the Rocky Mountain region, and 91.3 BCFE from drilling
+activities. There were net upward revisions of previous reserves
+totaling 21.0 BCFE. This upward revision was the result of a 6.7
+BCFE increase from price and a 14.3 BCFE increase from performance.
+The 21 percent increase in reserves over last year is net of current
+year sales of oil and gas properties with 45.6 BCFE of reserves.
+o Mid-Continent Drilling Results. The majority of the reserve
+additions from drilling came from our Mid-Continent region and were
+primarily attributable to activity in the Northeast Mayfield area.
+This drilling activity is in the Atoka and Upper Morrow / Springer
+formations.
+o Revolving Credit Agreement. In January 2003 we entered into a new
+long-term revolving credit agreement with nine banks. The facility
+has a maximum loan amount of $300 million and is subject to periodic
+borrowing base calculations. As of the end of 2003, our borrowing
+base is $275 million and we have elected a loan commitment amount of
+$150 million. The maturity date of the facility is January 27, 2006.
+Borrowings under the facility were $11.0 million as of December 31,
+2003.
+o Coal Bed Methane Project. In December 2003, we announced that we are
+proceeding with the development of coalbed methane reserves in the
+Hanging Woman Basin located in the northern part of the Powder River
+Basin along the border between Montana and Wyoming. We have
+approximately 139,000 net lease acres in total. Our development will
+initially concentrate on approximately 65,000 net acres in Wyoming.
+We have estimated probable reserves associated with this
+development, but we have not recorded any proved reserves through
+December 31, 2003.
+o Repurchase of Shares from Flying J. In February 2004, we repurchased
+the 3,380,818 restricted shares of our common stock held by Flying J
+for $91.0 million. In connection with this transaction, Flying J
+completely repaid our $71.6 million loan to them. The $19.4 million
+net cash outlay for the share repurchase was funded from our
+existing cash balances and borrowings under our bank credit
+facility.
+Major Customers
+During 2003 sales to BP America Production Company accounted for 13.6
+percent, sales to Midcoast Energy accounted for 13.1 percent and sales to Tesoro
+Refining and Marketing accounted for 11.4 percent of our total oil and gas
+production revenue. During 2002 there were no sales to individual customers that
+accounted for more than 10 percent of our total oil and gas production revenue.
+During 2001 sales to Transok Gas Company accounted for 12.0 percent and sales to
+BP Amoco accounted for 11.3 percent of our total oil and gas production revenue.
+Employees and Office Space
+As of December 31, 2003, we had 226 full-time employees. None of our
+employees are subject to a collective bargaining agreement, and we consider our
+relations with our employees to be good. We lease approximately 47,395 square
+feet of office space in Denver, Colorado for our executive and administrative
+offices, of which 9,479 square feet is subleased. We also lease approximately
+17,318 square feet of office space in Tulsa, Oklahoma; approximately 11,740
+square feet in Shreveport, Louisiana; approximately 7,500 square feet in
+Lafayette, Louisiana; and approximately 22,160 square feet in Billings, Montana.
+4
+As of March 1, 2004, our Lafayette, Louisiana office will relocate to
+Houston, Texas. The Lafayette lease expires on November 30, 2004, and we plan to
+continue making lease payments through the term of the lease. We will lease
+approximately 11,015 square feet in Houston.
+Title to Properties
+Substantially all of our working interests are held pursuant to leases
+from third parties. A title opinion is usually obtained prior to the
+commencement of drilling operations on properties. We have obtained title
+opinions or conducted a thorough title review on substantially all of our
+producing properties and believe that we have satisfactory title to such
+properties in accordance with standards generally accepted in the oil and gas
+industry. The majority of the value of our properties is subject to a mortgage
+under our credit facility, customary royalty interests, liens for current taxes,
+and other burdens that we believe do not materially interfere with the use of or
+affect the value of such properties. We perform only a minimal title
+investigation before acquiring undeveloped properties.
+Seasonality
+Generally, but not always, the demand and price levels for natural gas
+increase during the colder winter months and decrease during the warmer summer
+months. Seasonal anomalies such as mild winters sometimes lessen this
+fluctuation. In addition, pipelines, utilities, local distribution companies and
+industrial users utilize natural gas storage facilities and purchase some of
+their anticipated winter requirements during the summer, which can lessen
+seasonal demand fluctuations.
+Competition
+The oil and gas industry is intensely competitive. This is particularly
+so in the acquisition of prospective oil and natural gas properties and oil and
+gas reserves. The foundation for a strong drilling program is our leasehold
+position. Our competitive position depends on our geological, geophysical and
+engineering expertise, our financial resources, and our ability to select,
+acquire and develop proved reserves. We believe that the locations of our
+leasehold acreage, our exploration, drilling and production capabilities and the
+experience of our management and that of our industry partners generally enable
+us to compete effectively in our core operating areas. However, we compete with
+a substantial number of major and independent oil and gas companies that have
+larger technical staffs and greater financial and operational resources than we
+do. Many of these companies not only engage in the acquisition, exploration,
+development and production of oil and natural gas reserves, but also have
+refining operations, market refined products and generate electricity. We also
+compete with other oil and natural gas companies in attempting to secure
+drilling rigs and other equipment necessary for drilling and completion of
+wells. Consequently, drilling equipment may be in short supply from time to
+time.
+Government Regulations
+Our business is subject to various federal, state and local laws and
+governmental regulations that may be changed from time to time in response to
+economic or political conditions. Matters subject to regulation include
+discharge permits for drilling operations, drilling bonds, reports concerning
+operations, the spacing of wells, unitization and pooling of properties,
+taxation and environmental protection. From time to time, regulatory agencies
+have imposed price controls and limitations on production by restricting the
+rate of flow of oil and gas wells below actual production capacity in order to
+conserve supplies of oil and gas.
+Energy Regulations. Our sales of natural gas are affected by the
+availability, terms and cost of transportation. The price and terms of access to
+pipeline transportation are subject to extensive federal and state regulation.
+5
+From 1985 to the present, several major regulatory changes have been implemented
+by Congress and the Federal Energy Regulatory Commission that affect the
+economics of natural gas production, transportation and sales. In addition, the
+FERC is continually proposing and implementing new rules and regulations
+affecting those segments of the natural gas industry that remain subject to the
+FERC's jurisdiction, most notably interstate natural gas transmission companies.
+These initiatives may also affect the intrastate transportation of gas under
+certain circumstances. The stated purpose of many of these regulatory changes is
+to promote competition among the various sectors of the natural gas industry.
+The ultimate impact of the complex rules and regulations issued by the
+FERC since 1985 cannot be predicted. In addition, many aspects of these
+regulatory developments have not become final but are still pending judicial and
+final FERC decisions. Regulations implemented by the FERC in recent years could
+result in an increase in the cost of transportation service on certain petroleum
+product pipelines. In addition, some of the FERC's more recent proposals may,
+however, adversely affect the availability and reliability of interruptible
+transportation service on interstate pipelines. Additional proposals and
+proceedings that might affect the natural gas industry are pending before
+Congress and the courts. The natural gas industry historically has been very
+heavily regulated, and there is no assurance that the less stringent regulatory
+approach recently pursued by the FERC and Congress will continue. We do not
+believe that we will be affected by any action taken that differs materially
+from other natural gas producers and marketers with whom we compete.
+Certain operations we conduct involve federal minerals that the
+Minerals Management Service administers. The MMS issues leases covering such
+lands through competitive bidding. These leases contain relatively standardized
+terms and require compliance with federal laws and detailed MMS regulations. For
+offshore operations, lessees must obtain MMS approval for exploration plans and
+development and production plans prior to the commencement of such operations.
+In addition to permits required from other agencies such as the Coast Guard, the
+Army Corps of Engineers and the Environmental Protection Agency, lessees must
+obtain a permit from the MMS prior to the commencement of drilling. Lessees must
+also comply with detailed MMS regulations governing, among other things:
+o engineering and construction specifications for offshore production
+facilities;
+o safety procedures;
+o flaring of production;
+o plugging and abandonment of Outer Continental Shelf wells;
+o calculation of royalty payments and the valuation of production for
+this purpose; and
+o removal of facilities.
+To cover the various obligations of lessees on the OCS, the MMS
+generally requires that lessees post substantial bonds or other acceptable
+assurances that such obligations will be met. The cost of such bonds or other
+surety can be substantial, and we may not be able to continue to obtain bonds or
+other surety in all cases. Under certain circumstances the MMS may require our
+operations on federal leases to be suspended or terminated.
+Many of the states in which we conduct our oil and gas drilling and
+production activities regulate such activities by requiring, among other things,
+drilling permits and bonds and reports concerning operations. The laws of these
+states also govern a number of environmental and conservation matters, including
+6
+the handling and disposing of waste material, plugging and abandonment of wells,
+restoration requirements, unitization and pooling of natural gas and oil
+properties and establishment of maximum rates of production from natural gas and
+oil wells. Some states prorate production to the market demand for oil and
+natural gas.
+Our anticipated coalbed methane gas production from the Hanging Woman
+Basin will be similar to our traditional natural gas production as to the
+physical producing facilities and the product produced. However, the subsurface
+mechanisms that allow the gas to move to the wellbore and the producing
+characteristics of coalbed methane wells are very different from traditional
+natural gas production. Unlike conventional gas wells, which require a porous
+and permeable reservoir, hydrocarbon migration and a natural structural and/or
+stratigraphic trap, the coalbed methane gas is trapped in the molecular
+structure of the coal itself until released by pressure changes resulting from
+the removal of in situ water. Frequently, coalbeds are partly or completely
+saturated with water. As the water is removed, internal pressures on the coal
+are decreased, allowing the gas to desorb from the coal and flow to the
+wellbore. Unlike traditional gas wells, new coalbed methane wells often produce
+water for several months and then, as the water production decreases, natural
+gas production increases as the coal seams de-water.
+Coalbed methane gas production in the Hanging Woman Basin requires
+state permits for the use of well-site pits and evaporation ponds for the
+disposal of produced water. Groundwater produced from the coal seams can
+generally be discharged into arroyos, surface waters, well-site pits and
+evaporation ponds without a permit if it does not exceed surface discharge
+permit levels, and meets state and federal primary drinking water standards. All
+of these disposal options require an extensive third-party water sampling and
+laboratory analysis program to ensure compliance with state permit standards.
+Where water of lesser quality is involved or the wells produce water in excess
+of the applicable volumetric permit limits, additional disposal wells would have
+to be drilled to re-inject the produced water back into deep underground rock
+formations.
+Environmental Regulations. Our operations are subject to numerous
+existing federal, state and local laws and regulations governing environmental
+quality and pollution control. These laws and regulations may require that
+permits be obtained before drilling commences, restrict the types, quantities
+and concentration of various substances that can be released into the
+environment in connection with drilling and production activities, and limit or
+prohibit drilling activities on certain lands lying within wilderness, wetlands
+and other protected areas. As a result, these laws and regulations may
+substantially increase the costs of exploring, developing or producing oil and
+gas and may prevent or delay the commencement or continuation of a project. In
+addition, these laws and regulations may impose substantial clean-up,
+remediation and other obligations in the event of any discharges or emissions in
+violation of such laws and regulations.
+To date we have not experienced any material adverse effect on our
+financial condition or results of operations from obligations under
+environmental laws and regulations. We believe that we are in substantial
+compliance with currently applicable environmental laws and regulations and that
+continued compliance with existing requirements would not have a material
+adverse impact on us.
+Risk Factors
+Risks Related to Our Business
+In addition to the other information set forth elsewhere in this Form
+10-K, the following factors should be carefully considered when evaluating St.
+Mary.
+7
+Oil and natural gas prices are volatile, and an extended decline in prices would
+hurt our profitability and financial condition.
+Our revenues, operating results, profitability, future rate of growth
+and the carrying value of our oil and gas properties depend heavily on
+prevailing market prices for oil and gas. We expect the markets for oil and gas
+to continue to be volatile. Any substantial or extended decline in the price of
+oil or gas would have a material adverse effect on our financial condition and
+results of operations. It could reduce our cash flow and borrowing capacity, as
+well as the value and the amount of our oil and gas reserves. Lower prices may
+also reduce the amount of oil and gas that we can economically produce.
+Historically, the markets for oil and gas have been volatile, and they
+are likely to continue to be volatile. Wide fluctuations in oil and gas prices
+may result from relatively minor changes in the supply of and demand for oil and
+gas, market uncertainty and other factors that are beyond our control,
+including:
+o worldwide and domestic supplies of oil and natural gas;
+o the ability of the members of the Organization of Petroleum
+Exporting Countries to agree to and maintain oil price and
+production controls;
+o political instability or armed conflict in oil or gas producing
+regions;
+o the price and level of foreign imports;
+o worldwide economic conditions;
+o marketability of production;
+o the level of consumer demand;
+o the price, availability and acceptance of alternative fuels;
+o the availability of pipeline capacity;
+o weather conditions; and
+o actions of federal, state, local and foreign authorities.
+These external factors and the volatile nature of the energy markets
+make it difficult to estimate future prices of oil and natural gas. Declines in
+oil and gas prices would reduce our revenue and could also reduce the amount of
+oil and gas that we can produce economically and, as a result, could have a
+material adverse effect on our financial condition, results of operations and
+reserves. Further, oil and gas prices do not necessarily move in tandem. Since
+approximately 52 percent of our proved reserves were natural gas reserves as of
+December 31, 2003, our financial results are slightly more affected by changes
+in natural gas prices.
+Our future success depends on our ability to replace reserves.
+Our future success depends on our ability to find, develop and acquire
+oil and gas reserves that are economically recoverable. As of December 31, 2003,
+our proved reserves would last approximately 7.7 years if produced constantly at
+the 2003 rate of production. However, our properties do not produce at a
+8
+constant rate but rather at a declining rate over time. In order to maintain
+current production rates we must locate and develop or acquire new oil and gas
+reserves to replace those being depleted by production. We may do this even
+during periods of low oil and gas prices. Without successful exploration or
+acquisition activities, our reserves, production and revenues will decline
+rapidly. In addition, approximately 11 percent of our total estimated proved
+reserves as of December 31, 2003 were undeveloped. By their nature, undeveloped
+reserves are less certain. Recovery of such reserves requires significant
+capital expenditures and successful drilling operations. We may not be able to
+find and develop or acquire sufficient additional reserves at an acceptable
+cost.
+Our producing property acquisitions carry significant risks.
+Our recent growth is due in part to, and our growth strategy relies in
+part on, the economic acquisition of producing properties. Successful
+acquisitions require an assessment of a number of factors beyond our control.
+These factors include recoverable reserves, future oil and gas prices, operating
+costs and potential environmental and other liabilities. These assessments are
+inexact and their accuracy is inherently uncertain. In connection with these
+assessments, we perform a review of the subject properties that we believe is
+generally consistent with industry practices. However, such a review will not
+reveal all existing or potential problems. In addition, our review may not
+permit us to become sufficiently familiar with the properties to fully assess
+their deficiencies and capabilities. We do not inspect every well. Even when we
+do inspect a well, we may not always discover structural, subsurface or
+environmental problems that may exist or arise.
+In connection with our acquisitions, we may not be entitled to
+contractual indemnification for preclosing liabilities, including environmental
+liabilities. Normally, we acquire interests in properties on an "as is" basis
+with limited remedies for breaches of representations and warranties. In
+addition, competition for producing oil and gas properties is intense and many
+of our competitors have financial and other resources substantially greater than
+those available to us. Therefore, we may not be able to acquire oil and gas
+properties that contain economically recoverable reserves or we may not be able
+to acquire such properties at acceptable prices.
+Additionally, significant acquisitions can change the nature of our
+operations and business depending upon the character of the acquired properties,
+which may have substantially different operating and geological characteristics
+or be in different geographic locations than our existing properties. While it
+is our current intention to continue to concentrate on acquiring properties with
+development, exploitation and exploration potential located in our five core
+operating areas, we may in the future decide to pursue acquisitions of
+properties located in other geographic regions. To the extent that such acquired
+properties are substantially different than our existing properties, our ability
+to efficiently realize the expected economic benefits of such transactions may
+be limited.
+We may not be able to successfully integrate future property or corporate
+acquisitions.
+We seek to make selective niche acquisitions of oil and gas properties,
+and we will pursue corporate acquisitions that we believe will be accretive.
+However, integrating acquired properties and businesses involves a number of
+special risks. These risks include the possibility that management may be
+distracted from normal business concerns by the need to integrate operations and
+systems and in retaining and assimilating additional employees. Any of these or
+other similar risks could lead to potentially adverse short-term or long-term
+effects on our operating results. We may not be able to obtain adequate funds
+for future property or corporate acquisitions, successfully integrate our future
+property or corporate acquisitions or we may not realize any of the anticipated
+benefits of the acquisitions.
+9
+Substantial capital is required to replace and grow reserves.
+We make, and will continue to make, substantial expenditures to find,
+acquire, develop and produce oil and natural gas reserves. Our capital
+expenditures for oil and gas properties were $231.4 million for 2003 and $193.0
+million during 2002. We have budgeted total capital expenditures of $273.4
+million in 2004. With the cash provided by operating activities and borrowings
+under our credit facility, we believe we will have sufficient cash to fund
+budgeted capital expenditures in 2004. If additional development or attractive
+acquisition opportunities arise, we may consider other forms of financing,
+including the public offering or private placement of equity or debt securities.
+However, if oil and gas prices decrease or we encounter operating difficulties
+that result in our cash flow from operations being less than expected, we may
+have to reduce the capital we can spend in future years unless we raise
+additional funds through debt or equity financing. Debt or equity financing,
+cash generated by operations or borrowing capacity may not be available to us in
+sufficient amounts or on acceptable terms to meet these requirements.
+o Future cash flows and the availability of financing will be
+subject to a number of variables, such as:
+o our success in locating and producing new reserves;
+o the level of production from existing wells;
+o prices of oil and natural gas;
+o lease operating expense, including workovers and taxes; and
+o administrative expense.
+Issuing equity securities to satisfy our financing requirements could
+cause substantial dilution to existing stockholders. Debt financing could lead
+to:
+o a substantial portion of our operating cash flow being dedicated to
+the payment of principal and interest;
+o us being more vulnerable to competitive pressures and economic
+downturns; and
+o restrictions on our operations.
+If our revenues were to decrease due to lower oil and natural gas
+prices, decreased production or other reasons, and if we could not obtain
+capital through our credit facility or otherwise, our ability to execute our
+development plans, replace our reserves or maintain production levels could be
+greatly limited.
+We could incur substantial additional loans, which could negatively impact our
+financial condition, results of operations and business prospects.
+As of December 31, 2003, we had approximately $111.0 million in
+outstanding loans, including $100.0 million outstanding under our 5.75% Senior
+Convertible Notes due 2022. Our level of debt could have important consequences
+on our operations, including:
+10
+o making it more difficult for us to satisfy our debt obligations
+and, if we fail to comply with the requirements of any of our debt
+obligations, possibly resulting in an event of default;
+o requiring us to dedicate a substantial portion of our cash flow
+from operations to required payments on debt, thereby reducing the
+availability of cash flow for working capital, capital
+expenditures and other general business activities;
+o limiting our ability to obtain additional financing in the future
+for working capital, capital expenditures and other general
+business activities;
+o limiting our flexibility in planning for, or reacting to, changes in
+our business and the industry in which we operate;
+o detracting from our ability to withstand successfully a downturn in
+our business or the economy generally; and
+o placing us at a competitive disadvantage against other less
+leveraged competitors.
+The occurrence of any one of these events could have a material adverse effect
+on our business, financial condition, results of operations and business
+prospects.
+The indenture for our Convertible Notes does not limit our ability to
+incur additional debt. We may therefore incur additional debt, including secured
+debt under our bank credit facility or otherwise, in order to make future
+acquisitions or to develop our properties. A higher level of debt increases the
+risk that we may default on our debt obligations. We may not be able to generate
+sufficient cash flow to pay the interest on our debt, and future working
+capital, borrowings or equity financing may not be available to pay or refinance
+such debt.
+In addition, our credit facility borrowing base is subject to periodic
+borrowing base redeterminations. We could be forced to repay a portion of our
+bank borrowings due to redeterminations of our borrowing base. We may not have
+sufficient funds to make such repayments. If we do not have sufficient funds and
+are otherwise unable to negotiate renewals of our borrowing or arrange new
+financing, we may have to sell significant assets. Any such sale could have a
+material adverse effect on our business and financial results.
+We may not be able to obtain bank credit facility borrowing base
+redeterminations that adequately meet our anticipated financing needs.
+Our long-term revolving credit facility with a group of banks has a
+maximum loan amount of $300 million. The amount actually available from time to
+time depends on a borrowing base that the lenders periodically redetermine based
+on the value of our oil and gas properties and other assets. In October 2003 the
+banks conducted their normal semi-annual borrowing base redetermination that
+resulted in a borrowing base of $275 million. Since we pay commitment fees based
+on the unused portion of the borrowing base, we elected to retain a total loan
+commitment amount under the facility of $150 million to correspond with our
+projected funding requirements.
+Our next borrowing base redetermination is scheduled to occur by the
+end of April 2004. The banks may not agree to a borrowing base redetermination
+that is adequate for our financing needs at that time.
+11
+If oil and gas prices decrease or exploration efforts are unsuccessful, we may
+be required to take additional writedowns.
+There is a risk that we will be required to write down the carrying
+value of our oil and gas properties. This could occur when oil and gas prices
+are low or if we have substantial downward adjustments to our estimated proved
+reserves, increases in our estimates of development costs or deterioration in
+our exploration results.
+We follow the successful efforts accounting method. All property
+acquisition costs and costs of exploratory and development wells are capitalized
+when incurred, pending the determination of whether proved reserves have been
+discovered. If proved reserves are not discovered with an exploratory well, the
+costs of drilling the well are expensed. All geological and geophysical costs on
+exploratory prospects are expensed as incurred. The capitalized costs of our oil
+and gas properties, on a field-by-field basis, may not exceed the estimated
+future net cash flows of that field. If capitalized costs exceed future net
+revenues we write down the costs of each such field to our estimate of fair
+market value. Unproved properties are evaluated at the lower of cost or fair
+market value. This type of charge will not affect our cash flow from operating
+activities, but it will reduce the book value of our stockholders' equity. We
+review the carrying value of our properties quarterly, based on prices in effect
+as of the end of each quarter or as of the time of reporting our results. Once
+incurred, a writedown of oil and gas properties is not reversible at a later
+date even if oil or gas prices increase. St. Mary incurred impairment and
+abandonment charges on proved and unproved properties of $4.0 million, $2.4
+million and $4.7 million in 2003, 2002 and 2001, respectively.
+Estimates of oil and gas reserves are not precise.
+This report and other SEC filings by us contain estimates of our proved
+oil and gas reserves and the estimated future net revenues from those reserves.
+Actual results will likely vary from amounts estimated, and any significant
+negative variance could have a material adverse effect on our future results of
+operations.
+Reserve estimates are based on various assumptions, including
+assumptions required by the SEC relating to oil and gas prices, drilling and
+operating expenses, capital expenditures, taxes and availability of funds. The
+process of estimating reserves is complex. This process requires significant
+decisions and assumptions in the evaluation of available geological,
+geophysical, engineering and economic data for each reservoir. Therefore, these
+estimates are not precise. However, the likelihood of recovery of these reserves
+is considered more likely than not.
+Actual future production, oil and gas prices, revenues, taxes,
+development expenditures, operating expenses and quantities of recoverable oil
+and gas reserves will most likely vary from those estimated. Any significant
+variance could materially affect the estimated quantities and present value of
+reserves disclosed by us. In addition, we may adjust estimates of proved
+reserves to reflect production history, results of exploration and development,
+prevailing oil and gas prices and other factors, many of which are beyond our
+control.
+As of December 31, 2003, approximately 11 percent of our estimated
+proved reserves were proved undeveloped. Estimation of proved undeveloped
+reserves and proved developed non-producing reserves is nearly always based on
+volumetric calculations rather than the performance data used to estimate
+producing reserves. Recovery of proved undeveloped reserves requires significant
+capital expenditures and successful drilling operations. Production revenues
+from proved non-producing reserves will not be realized until some time in the
+future. The reserve data assumes that we will make significant capital
+expenditures to develop our reserves. Although we have prepared estimates of our
+reserves and the costs associated with these reserves in accordance with
+12
+industry standards, these estimated costs may not be accurate, development may
+not occur as scheduled and actual results may not be as estimated.
+You should not construe the present value of future net reserves, or
+PV-10, as the current market value of the estimated oil and natural gas reserves
+attributable to our properties. Management has based the estimated discounted
+future net cash flows from proved reserves on prices and costs as of the date of
+the estimate, in accordance with applicable regulations, whereas actual future
+prices and costs may be materially higher or lower. For example, values of our
+reserves as of December 31, 2003, were estimated using a calculated weighted
+average sales price of $31.01 per barrel of oil (NYMEX) and $5.70 per Mcf of gas
+(Gulf Coast spot price), after adjustment for transportation, quality and basis
+differentials. During 2003 our monthly average realized gas prices were as high
+as $9.28 per Mcf and as low as $4.49 per Mcf. For the same period our monthly
+average realized oil prices were as high as $35.73 per Bbl and as low as $28.07
+per Bbl. Many factors will affect actual future net cash flows, including:
+o the amount and timing of actual production,
+o supply and demand for oil and natural gas,
+o curtailments or increases in consumption by oil and natural gas
+purchasers, and
+o changes in governmental regulations or taxation.
+The timing of the production of oil and natural gas properties and of
+the related expenses affects the timing of actual future net cash flows from
+proved reserves and thus their actual present value. In addition, the 10 percent
+discount factor, which we are required to use to calculate PV-10 for reporting
+purposes, is not necessarily the most appropriate discount factor given actual
+interest rates and risks to which our business or the oil and natural gas
+industry in general are subject. As a result, our actual future net cash flows
+could be materially different from the estimates included in this report.
+Our industry is highly competitive.
+Major oil companies, independent producers, and institutional and
+individual investors are actively seeking oil and gas properties throughout the
+world, along with the equipment, labor and materials required to operate
+properties. Shortages for equipment, labor or materials may result in increased
+costs or the inability to obtain such resources as needed. Many of our
+competitors have financial and technological resources vastly exceeding those
+available to us. Many oil and gas properties are sold in a competitive bidding
+process in which we may lack technological information or expertise available to
+other bidders. We may not be successful in acquiring and developing profitable
+properties in the face of this competition.
+Exploration and development drilling may not result in commercially productive
+reserves.
+Oil and gas drilling and production activities are subject to numerous
+risks, including the risk that no commercially productive oil or natural gas
+will be found. The cost of drilling and completing wells is often uncertain, and
+oil and gas drilling and production activities may be shortened, delayed or
+canceled as a result of a variety of factors, many of which are beyond our
+control. These factors include:
+o unexpected drilling conditions;
+13
+o pressure or irregularities in formations;
+o equipment failures or accidents;
+o adverse weather conditions;
+o shortages in experienced labor;
+o compliance with governmental requirements; and
+o shortages or delays in the availability of drilling rigs and the
+delivery of equipment.
+The prevailing prices of oil and gas also affect the cost of and the
+demand for drilling rigs, production equipment and related services.
+The wells we drill may not be productive and we may not recover all or
+any portion of our investment in such wells. The seismic data and other
+technologies we use do not allow us to know conclusively prior to drilling a
+well that oil or gas is present or may be produced economically. The cost of
+drilling, completing and operating a well is often uncertain, and cost factors
+can adversely affect the economics of a project. Drilling activities can result
+in dry wells or wells that are productive but do not produce sufficient net
+revenues after operating and other costs to cover initial drilling costs.
+Our future drilling activities may not be successful, nor can we be
+sure that our overall drilling success rate or our drilling success rate for
+activity within a particular area will not decline. Unsuccessful drilling
+activities could have a material adverse effect on our results of operations and
+financial condition. Also, we may not be able to obtain any options or lease
+rights in potential drilling locations that we identify. Although we have
+identified numerous potential drilling locations, we may not be able to
+economically produce oil or natural gas from all of them.
+Our business is subject to operating and environmental risks and hazards that
+could result in substantial losses.
+Oil and gas operations are subject to many risks, including well
+blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
+well fluids, fires, formations with abnormal pressures, pipeline ruptures or
+spills, pollution, releases of toxic gas and other environmental risks and
+hazards. If any of these types of events occurs, we could sustain substantial
+losses as a result of:
+o personal injuries or loss of life;
+o severe damage to or destruction of property, natural resources and
+equipment;
+o pollution or other environmental damage due to spills or other
+discharges of hazardous materials;
+o clean-up and remediation responsibilities and costs;
+o regulatory investigations and penalties; and/or
+o suspension of operations.
+14
+Under certain limited circumstances we may be liable for environmental
+damage caused by previous owners or operators of properties that we own, lease
+or operate. As a result, we may incur substantial liabilities to third parties
+or governmental entities, which could reduce or eliminate funds available for
+exploration, development or acquisitions or cause us to incur losses.
+We maintain insurance against some, but not all, of these potential
+risks and losses. We have limited coverage for sudden environmental damages. We
+do not believe that insurance coverage for the full potential liability that
+could be caused by sudden environmental damages or insurance coverage for
+environmental damage that occurs over time is available at a reasonable cost. In
+addition, pollution and environmental risks generally are not fully insurable.
+Further, we may elect not to obtain other insurance coverage under circumstances
+where we believe that the cost of available insurance is excessive relative to
+the risks presented. Accordingly, we may be subject to liability or may lose
+substantial portions of our properties in the event of environmental or other
+damages. If a significant accident or other event occurs and is not fully
+covered by insurance, it could have a material adverse effect on our financial
+condition and results of operations.
+Other independent oil and gas companies' limited access to capital may change
+our exploration and development plans.
+Many independent oil and gas companies have limited access to the
+capital necessary to finance their activities. As a result, some of the other
+working interest owners of our wells may be unwilling or unable to pay their
+share of the costs of projects as they become due. These problems could cause us
+to change, suspend or terminate our drilling and development plans with respect
+to the affected project.
+Hedging transactions may limit our potential gains and involve other risks.
+To manage our exposure to price risks in the marketing of our oil and
+natural gas, we enter into commodity price risk management arrangements from
+time to time with respect to a portion of our current or future production.
+While intended to reduce the effects of volatile oil and natural gas prices,
+these transactions may limit our potential gains if oil or natural gas prices
+were to rise substantially over the price established by the hedge. In addition,
+such transactions may expose us to the risk of financial loss in certain
+circumstances, including instances in which:
+o our production is less than expected;
+o the counterparties to our futures contracts fail to perform under
+the contracts; or
+o a sudden, unexpected event materially impacts oil or natural gas
+prices.
+The terms of our hedging agreements may also require that we furnish
+cash collateral, letters of credit or other forms of performance assurance in
+the event that mark-to-market calculations result in settlement obligations by
+us to the counterparties, which would encumber our liquidity and capital
+resources.
+Our industry is heavily regulated.
+Federal, state and local authorities extensively regulate the oil and
+gas industry. Legislation and regulations affecting the industry are under
+constant review for amendment or expansion, raising the possibility of changes
+that may affect, among other things, the pricing or marketing of oil and gas
+production. Noncompliance with statutes and regulations may lead to substantial
+penalties, and the overall regulatory burden on the industry increases the cost
+of doing business and, in turn, decreases profitability. These authorities
+15
+regulate various aspects of oil and gas drilling and production activities,
+including the drilling of wells (through permit and bonding requirements), the
+spacing of wells, the unitization or pooling of oil and gas properties,
+environmental matters, safety standards, the sharing of markets, production
+limitations, plugging and abandonment, and restoration. To cover the various
+obligations of leaseholders in federal waters, federal authorities generally
+require that leaseholders have substantial net worth or post bonds or other
+acceptable assurances that such obligations will be met. The cost of these bonds
+or other surety can be substantial, and we may not be able to obtain bonds or
+other surety in all cases. Under limited circumstances, federal authorities may
+require any of our operations on federal leases to be suspended or terminated.
+Any such suspension or termination could materially adversely affect our
+financial condition and results of operations.
+We must comply with complex environmental regulations.
+Our operations are subject to complex and constantly changing
+environmental laws and regulations adopted by federal, state and local
+governmental authorities where we are engaged in exploration or production
+operations. New laws or regulations, or changes to current requirements, could
+have a material adverse effect on our business. We will continue to be subject
+to uncertainty associated with new regulatory interpretations and inconsistent
+interpretations between state and federal agencies. We could face significant
+liabilities to the government and third parties for discharges of oil, natural
+gas or other pollutants into the air, soil or water, and we could have to spend
+substantial amounts on investigations, litigation and remediation. Existing
+environmental laws or regulations, as currently interpreted or enforced, or as
+they may be interpreted, enforced or altered in the future, may have a material
+adverse effect on our results of operations and financial condition. As a
+result, we may face material claims with respect to properties we own or have
+owned.
+Our business depends on transportation facilities owned by others.
+The marketability of our oil and gas production depends in part on the
+availability, proximity and capacity of pipeline systems owned by third parties.
+The unavailability of or lack of available capacity on these systems and
+facilities could result in the shutting-in of producing wells or the delay or
+discontinuance of development plans for properties. Although we have some
+contractual control over the transportation of our product, material changes in
+these business relationships could materially affect our operations. Federal and
+state regulation of oil and gas production and transportation, tax and energy
+policies, changes in supply and demand, pipeline pressures, damage to or
+destruction of pipelines and general economic conditions could adversely affect
+our ability to produce, gather and transport oil and natural gas.
+We depend on key personnel.
+Our success will continue to depend on the continued services of our
+executive officers and a limited number of other senior management and technical
+personnel with extensive experience and expertise in evaluating and analyzing
+producing oil and gas properties and drilling prospects, maximizing production
+from oil and gas properties and marketing oil and gas production. Loss of the
+services of any of these people could have a material adverse effect on our
+operations. We currently do not have employment agreements with our executive
+officers other than Mark Hellerstein, our Chief Executive Officer. We do not
+carry any key person life insurance policies.
+Ownership of working interests, royalty interests and other interests by a
+director and some of our officers may create conflicts of interest.
+As a result of their prior employment with another company with which
+St. Mary engaged in a number of transactions, Ronald D. Boone, a director of St.
+Mary, and two vice presidents of St. Mary own royalty interests in a number of
+St. Mary's properties, which were earned as part of the prior employer's
+employee benefit programs. Those persons have no royalty participation in any
+16
+St. Mary properties acquired or developed subsequent to the beginning of their
+employment with St. Mary.
+Mr. Boone also owns 25 percent of Princeton Resources LLC, which owns
+the oil and gas working interests that he acquired as a result of his prior
+employment. Although Mr. Boone does not manage this entity, he may participate
+in any investment decisions made by it.
+As a result of these transactions and relationships, conflicts of
+interest may exist between these persons and us. Although these persons owe
+fiduciary duties to our stockholders and to us, conflicts of interest may not
+always be resolved in our favor.
+Risks Related to Our Common Stock
+The price of our common stock may fluctuate significantly, which may result in
+losses for investors.
+The market price of our common stock has been volatile. From January 1,
+2002, to February 20, 2004, the last daily sale price of our common stock
+reported by the New York Stock Exchange or the NASDAQ National Market ranged
+from a low of $18.75 per share to a high of $30.70 per share. We expect our
+stock to continue to be subject to fluctuations as a result of a variety of
+factors, including factors beyond our control. These include:
+o changes in oil and natural gas prices;
+o variations in quarterly drilling, recompletions, acquisitions and operating results;
+o changes in financial estimates by securities analysts;
+o changes in market valuations of comparable companies;
+o additions or departures of key personnel; and
+o future sales of our common stock.
+We may fail to meet expectations of our stockholders or of securities
+analysts at some time in the future, and our stock price could decline as a
+result.
+Our certificate of incorporation and bylaws have provisions that discourage
+corporate takeovers and could prevent shareholders from realizing a premium on
+their investment.
+Our certificate of incorporation and bylaws contain provisions that may
+have the effect of delaying or preventing a change of control. These provisions,
+among other things, provide for noncumulative voting in the election of the
+Board of Directors and impose procedural requirements on stockholders who wish
+to make nominations for the election of Directors or propose other actions at
+stockholders' meetings. These provisions, alone or in combination with each
+other and with the rights plan described below, may discourage transactions
+involving actual or potential changes of control, including transactions that
+otherwise could involve payment of a premium over prevailing market prices to
+shareholders for their common stock
+We have a stockholder rights plan that was adopted by our Board of
+Directors in 1999. The plan is designed to enhance the board's ability to
+prevent an acquirer from depriving stockholders of the long-term value of their
+investment and to protect stockholders against attempts to acquire us by means
+of unfair or abusive takeover tactics. If the Board of Directors decides in
+accordance with its fiduciary obligations that the terms of a potential
+acquisition do not reflect the long-term value of St. Mary, the Board of
+17
+Directors could allow the holder of each outstanding share of our common stock
+other than those held by the potential acquirer to purchase one additional share
+of our common stock with a market value of twice the exercise price. This
+prospective dilution to a potential acquirer would make the acquisition
+impracticable unless the terms were improved to the satisfaction of the Board of
+Directors. The existence of the plan may impede a takeover not supported by our
+board even though such takeover may be desired by a majority of our stockholders
+or may involve a premium over the prevailing stock price.
+Our shares that are eligible for future sale may have an adverse effect on the
+price of our common stock.
+At February 20, 2004, we had 28,339,963 shares of common stock
+outstanding. Of the shares outstanding, approximately 27,156,818 shares were
+freely tradable without substantial restriction or the requirement of future
+registration under the Securities Act. Also as of that date, options to purchase
+3,431,278 shares of our common stock were outstanding, of which 2,347,985 were
+exercisable. These options are exercisable at prices ranging from $9.25 to
+$33.31 per share. Sales of substantial amounts of common stock, or a perception
+that such sales could occur, and the existence of options or warrants to
+purchase shares of commons stock at prices that may be below the then-current
+market price of the common stock could adversely affect the market price of the
+common stock and could impair our ability to raise capital through the sale of
+our equity securities.
+A director and his extended family may be able to control us.
+Thomas E. Congdon, a director and our former Chairman of the Board, and
+members of his extended family owned approximately 14.4 percent of the
+outstanding shares of our common stock as of February 20, 2004. While no formal
+arrangements exist, these extended family members may be inclined to act in
+concert with Mr. Congdon on matters related to control of St. Mary, including
+for example the election of Directors or response to an unsolicited bid to
+acquire St. Mary. Accordingly, Mr. Congdon and his family may be able to control
+or influence matters presented to our Board of Directors and stockholders.
+We may not always pay dividends on our common stock.
+The payment of future dividends remains in the discretion of the Board
+of Directors and will continue to depend on our earnings, capital requirements,
+financial condition and other factors. In addition, the payment of dividends is
+subject to covenants in our bank credit facility, including the requirement that
+we maintain certain levels of stockholder's equity. The Board of Directors may
+determine in the future to reduce the current annual dividend rate of $0.10 per
+share or discontinue the payment of dividends altogether. Our credit facility
+limits the annual per share dividend rate that we may pay to $0.20.
+Cautionary Statement about Forward-Looking Statements
+This Annual Report on Form 10-K includes certain statements that may be
+deemed to be "forward-looking statements" within the meaning of Section 27A of
+the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
+1934. All statements, other than statements of historical facts, included in
+this Form 10-K that address activities, events or developments that St. Mary's
+management expects, believes or anticipates will or may occur in the future are
+forward looking statements. Examples of forward-looking statements may include
+discussion of such matters as:
+o The amount and nature of future capital, development and exploration
+expenditures;
+18
+o The drilling of wells;
+o Reserve estimates and the estimates of both future net revenues and
+the present value of future net revenues that are included in their
+calculation;
+o Future oil and gas production estimates;
+o Repayment of debt;
+o Business strategies;
+o Expansion and growth of operations; and
+o Other similar matters such as those discussed in Management's
+Discussion and Analysis of Financial Condition and Results of
+Operations.
+These statements are based on certain assumptions and analyses made by us in
+light of our experience and our perception of historical trends, current
+conditions, expected future developments and other factors we believe are
+appropriate in the circumstances. Such statements are subject to a number of
+assumptions, risks and uncertainties, including such factors as the volatility
+and level of oil and natural gas prices, uncertainties in cash flow, expected
+acquisition benefits, production rates and reserve replacement, reserve
+estimates, drilling and operating risks, competition, litigation, environmental
+matters, the potential impact of government regulations, and other matters
+discussed under the caption "Risk Factors", many of which are beyond our
+control. Readers are cautioned that forward-looking statements are not
+guarantees of future performance and that actual results or developments may
+differ materially from those expressed or implied in the forward-looking
+statements.
+Available Information
+Our Internet website address is www.stmaryland.com. Through our
+website's financial information section we make available free of charge our
+annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on
+Form 8-K, and amendments to those reports filed with or furnished to the SEC
+under applicable securities laws. These materials are made available as soon as
+reasonably practical after we electronically file such material with, or furnish
+it to, the SEC.
+We also make available through our website's corporate governance
+section our corporate governance guidelines, code of business conduct and
+ethics, and the charters for our Board of Directors' audit committee,
+compensation committee, executive committee and nominating and corporate
+governance committee. These documents are also available in print to any
+stockholder who requests them. Requests for these documents may be submitted to:
+St. Mary Land & Exploration Company
+Investor Relations
+1776 Lincoln Street, Suite 700
+Denver, Colorado 80203
+Telephone: (303) 863-4322
+Information on our website is not incorporated by reference into this
+Annual Report on Form 10-K and should not be considered part of this document.
+19
+Glossary
+The terms defined in this section are used throughout this Annual
+Report on Form 10-K.
+2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a
+two-dimensional cross-section of the subsurface.
+3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a
+three-dimensional picture of the subsurface.
+Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
+reference to oil or other liquid hydrocarbons.
+Bcf. Billion cubic feet, used herein in reference to natural gas.
+BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using
+the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+Behind pipe reserves. Estimated net proved reserves in a formation in which
+production casing has already been set in the wellbore but has not been
+perforated and production tested.
+BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio
+of six Mcf of gas (including gas liquids) to one Bbl of oil.
+Development well. A well drilled within the proved area of an oil or gas
+reservoir to the depth of a stratigraphic horizon known to be productive in an
+attempt to recover proved undeveloped reserves.
+Dry hole. A well found to be incapable of producing either oil or gas in
+sufficient quantities to justify completion as an oil or gas well.
+Estimated net proved reserves. The estimated quantities of oil, gas and gas
+liquids which geological and engineering data demonstrate with reasonable
+certainty to be recoverable in future years from known reservoirs under existing
+economic and operating conditions.
+Exploratory well. A well drilled to find and produce oil or gas in an unproved
+area, to find a new reservoir in a field previously found to be productive of
+oil or gas in another reservoir or to extend a known reservoir.
+Fee land. The most extensive interest that can be owned in land, including
+surface and mineral (including oil and gas) rights.
+Finding cost. Expressed in dollars per BOE or MCFE. Finding costs are calculated
+by dividing the amount of total capital expenditures for oil and gas activities
+by the amount of estimated net proved reserves added during the same period
+(including the effect on proved reserves of reserve revisions).
+Gross acres. An acre in which a working interest is owned.
+Gross well. A well in which a working interest is owned.
+Hydraulic fracturing. A procedure to stimulate production by forcing a mixture
+of fluid and proppant (usually sand) into the formation under high pressure.
+This creates artificial fractures in the reservoir rock, which increases
+permeability and porosity.
+20
+MBbl. One thousand barrels of oil or other liquid hydrocarbons.
+MMBbl. One million barrels of oil or other liquid hydrocarbons.
+MBOE. One thousand barrels of oil equivalent.
+MMBOE. One million barrels of oil equivalent.
+Mcf. One thousand cubic feet.
+MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined
+using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+MMcf. One million cubic feet.
+MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined
+using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+MMBtu. One million British Thermal Units. A British Thermal Unit is the heat
+required to raise the temperature of a one-pound mass of water one degree
+Fahrenheit.
+Net acres or net wells. The sum of our fractional working interests owned in
+gross acres or gross wells.
+Net asset value per share. The result of the fair market value of total assets
+less total liabilities, divided by the total number of outstanding shares of
+common stock.
+PV-10 value. The present value of estimated future gross revenue to be generated
+from the production of estimated net proved reserves, net of estimated
+production and future development costs, using prices and costs in effect as of
+the date indicated (unless such prices or costs are subject to change pursuant
+to contractual provisions), without giving effect to non-property related
+expenses such as general and administrative expenses, debt service and future
+income tax expenses or to depreciation, depletion and amortization, discounted
+using an annual discount rate of 10 percent.
+Productive well. A well that is producing oil or gas or that is capable of
+production.
+Proved developed reserves. Reserves that can be expected to be recovered through
+existing wells with existing equipment and operating methods.
+Proved undeveloped reserves. Reserves that are expected to be recovered from new
+wells on undrilled acreage, or from existing wells where a relatively major
+expenditure is required for recompletion.
+Recompletion. The completion for production from an existing wellbore in another
+formation other than that in which the well has previously been completed.
+Reserve life. Expressed in years, represents the estimated net proved reserves
+at a specified date divided by forecasted production for the preceding 12-month
+period.
+Royalty. The share paid to the owner of mineral rights expressed as a percentage
+of gross income from oil and gas produced and sold unencumbered by expenses
+relating to the drilling, completing and operating of the affected well.
+Royalty interest. An interest in an oil and gas property entitling the owner to
+shares of oil and gas production free of costs of exploration, development and
+production.
+21
+Undeveloped acreage. Lease acreage on which wells have not been drilled or
+completed to a point that would permit the production of commercial quantities
+of oil and gas, regardless of whether such acreage contains estimated net proved
+reserves.
+Working interest. The operating interest that gives the owner the right to
+drill, produce and conduct operating activities on the property and to share in
+the production.
+ITEM 2. PROPERTIES
+Operations
+St. Mary's exploration, development and acquisition activities are
+focused in five core operating areas: the Mid-Continent region; the Gulf Coast
+region; the ArkLaTex region; the Rocky Mountain region in Montana, North Dakota
+and Wyoming; and the Permian Basin region in West Texas and New Mexico.
+Information concerning each of our major areas of operations, and summary of our
+estimated proved reserves as of December 31, 2003, is shown below.
+Estimated Proved Reserves
+-------------------------------------------------------
+Oil Gas MMCFE PV-10 Value
+------------------------- ------------------------------
+(MBbl) (MMcf) Amount Percent (In thousands) Percent
+----------- ----------- ----------- ---------- ----------------- ---------
+Mid-Continent 1,090 145,611 152,148 26% $ 405,304 32%
+Rocky Mountain 37,730 63,752 290,133 49% 514,134 40%
+ArkLaTex 1,299 60,032 67,826 11% 155,944 12%
+Gulf Coast 328 31,096 33,065 5% 112,426 9%
+Permian Basin 7,340 6,533 50,572 9% 90,358 7%
+----------- ----------- ----------- ---------- ----------------- ---------
+Total 47,787 307,024 593,744 100% $ 1,278,166 100%
+=========== =========== =========== ========== ================= =========
+Mid-Continent Region. Since 1973 St. Mary has been active in the
+Mid-Continent region. Operations there are managed by our 35-person Tulsa,
+Oklahoma office. We have ongoing exploration and development programs in the
+Anadarko and Arkoma basins of Oklahoma and Texas. The Mid-Continent region
+accounts for 26 percent of our estimated proved reserves as of December 31,
+2003, or 152.1 BCFE, 85 percent of which were proved developed and 96 percent of
+which were natural gas. In 2003 our capital expenditures in the Mid-Continent
+were $72.2 million. We participated in drilling 77 gross wells in this region in
+2003, 90 percent of which were completed as producers. We operated 39 of these
+drilling projects. In addition, we participated in 10 gross recompletions with
+the same 90 percent success rate.
+St. Mary's development and exploration budget in the Mid-Continent
+region for 2004 totals $59.5 million. We plan to operate 31 drilling wells in
+the Mid-Continent region during 2004 and to utilize five to seven drilling rigs
+throughout the year. Our 2004 budget also reflects participation in an
+additional 16 wells to be operated by other entities.
+Anadarko Basin. Our long history of operations and proprietary geologic
+knowledge enables us to sustain economic development and exploration programs
+despite periods of adverse industry conditions. We apply state of the art
+technology in hydraulic fracturing and innovative well completion techniques to
+accelerate production and associated cash flow from the region's tight gas
+reservoirs. We also continue to benefit from the continuing consolidation of
+operators in the basin as we pursue attractive opportunities to acquire
+properties.
+22
+Approximately 77 percent of our 2004 Mid-Continent capital budget is
+allocated to deeper, higher-potential wells in the Morrow/Springer formations as
+well as the Atoka formations at the Northeast Mayfield Field in Beckham County,
+Oklahoma on the southern edge of the Anadarko Basin. The remaining 23 percent of
+the drilling activities for 2004 will be focused on low-to-medium-risk
+development in the Cromwell, Granite Wash, Osborne, Red Fork and Spiro
+formations.
+The Northeast Mayfield prospect is the largest concentration of our
+reserves. This field represents approximately 39 BCFE or seven percent of our
+proved reserves and $123.5 million, or approximately 10 percent of our total
+PV-10 value. Our average working interest in this field is 25 percent, and we
+have an interest in approximately 48 gross wells of which we operate 38 percent.
+Other significant fields in the Mid-Continent region are the Centrahoma
+field located in Coal County, Oklahoma in the Arkoma Basin and the Elk City
+field in Beckham County, Oklahoma. Centrahoma represents three percent of total
+proved reserves and $41.4 million or three percent of total PV-10 value, and Elk
+City represents two percent of total proved reserves and $36.0 million of PV-10
+value. Here we operate 86 percent and 16 percent of the wells in the respective
+fields and have an average working interest of approximately 72 percent and 14
+percent, respectively.
+Rocky Mountain Region. Nance Petroleum Corporation, a wholly owned
+subsidiary of St. Mary, has conducted operations in the Williston Basin in
+eastern Montana and western North Dakota on our behalf since 1991. This area has
+expanded into the Green River and Wind River basins with properties acquired
+from Choctaw and Flying J and into the Hanging Woman Basin with our coal-bed
+methane project. The acquisition of the Flying J properties added approximately
+92.0 BCFE of reserves to the Company as of the acquisition date. In total, the
+Rocky Mountain region accounted for 49 percent of our estimated proved reserves
+as of December 31, 2003, or 290.1 BCFE, 95 percent of which were proved
+developed and 78 percent of which were oil.
+Our office in Billings, Montana includes a 58-person staff. A
+significant portion of the exploration and development in the Rocky Mountain
+region is based on the interpretation of 3-D seismic data. We have successfully
+used 3-D seismic imaging to delineate structure and porosity development in the
+Red River formation.
+St. Mary spent $100.3 million on exploration, development and
+acquisitions in the Williston Basin in 2003. The acquisition of the Flying J
+properties comprised $68.7 million of our total property acquisitions for the
+Company. As of the end of 2003, the Flying J properties were producing 2,112
+barrels of oil and 7,362 Mcf of gas on a daily basis. In total, the incremental
+production from the Flying J acquisition in 2003 was 7.3 BCFE.
+Our capital budget for the Rocky Mountain region is approximately $63.9
+million in 2004. This increase is a result of the increased development of the
+dolomite portion of the Bakken formation and $12.2 million is dedicated to the
+development of our coalbed methane project at Hanging Woman Basin. In 2004 we
+plan to drill 26 conventional operated wells with working interests ranging from
+25 percent to 100 percent, with nine of these wells having a working interest
+greater than 90 percent. We also plan to drill 112 wells in our coalbed methane
+project at Hanging Woman Basin, all of which we will operate. We will operate
+projects representing approximately $43.4 million of the total Rocky Mountain
+budget.
+The concentration of our fields is less significant in the Rocky
+Mountains. The total of the Rough Rider, the Bainville North, Brush Lake and
+Standard Draw fields represent approximately 47.9 BCFE (7.9 MBOE) or eight
+percent of our total proved reserves. The PV-10 value represented by these four
+fields is $90.4 million, approximately 7 percent of our total reserves. Our
+average working interest varies from a low of 27 percent in the Standard Draw
+23
+field to a high of 98 percent in the Brush Lake field.
+ArkLaTex Region. Our 18-person office in Shreveport, Louisiana manages
+St. Mary's operations in the ArkLaTex region. The ArkLaTex region accounts for
+11 percent of our estimated proved reserves as of December 31, 2003, or 67.8
+BCFE; 80 percent of which were proved developed and 89 percent of which were
+natural gas. In 1992, we acquired oil and gas properties and rights to over
+6,000 square miles of proprietary 2-D seismic data in the region. Much of the
+Shreveport office's successful exploration and development programs have derived
+from niche acquisitions. These acquisitions have provided access to strategic
+holdings of undeveloped acreage and proprietary packages of geologic and seismic
+data, resulting in an active program of additional development and exploration.
+Our holdings in the ArkLaTex region are comprised of interests in
+approximately 346 producing gross wells, including 104 wells operated by us;
+interests in leases totaling approximately 76,400 gross acres; and mineral
+servitudes totaling approximately 14,300 gross acres. The development of the
+Huxley field in Shelby County, Texas was the focus of the 2003 activity for the
+region. This field represents 14.6 BCFE or two percent of the total reserves for
+the Company. The PV-10 value attributable to the Huxley field is $41.4 million.
+The Box Church Field located in Limestone County, Texas represents three percent
+of our proved reserves and two percent of PV-10 value and continues to be a
+highly profitable area for St. Mary. Production from the Box Church Field in
+2003 was 1.3 BCFE.
+In 2004 we will continue to focus on the search for new opportunities
+and potential analog fields in which to apply our proprietary geologic models
+and production techniques. We anticipate participating in 41 gross wells in the
+ArkLaTex region and will operate 24 of those drilling projects. The total
+capital expenditures budgeted for the region in 2004 is $21.6 million and will
+include drilling in the Spider prospect and a mix of exploratory and development
+programs throughout our prospect inventory.
+Gulf Coast Region. St. Mary's presence in south Louisiana dates to the
+early 1900's when our founders acquired a franchise property in St. Mary Parish
+on the shoreline of the Gulf of Mexico. These 24,914 acres of fee lands yielded
+$4.6 million of gross oil and gas royalty revenue in 2003. Our Gulf Coast region
+presence increased significantly in 1999 with the acquisition of King Ranch
+Energy. The Gulf Coast region accounts for six percent of our estimated proved
+reserves as of December 31, 2003, or 33.1 BCFE, 94 percent of which were proved
+developed and 31.1 BCF of which were natural gas.
+Our team based in Houston, Texas manages St. Mary's diverse activities
+in our Gulf Coast and Permian Basin regions. Moving the Gulf Coast operations
+from Lafayette, Louisiana to Houston is anticipated to be a catalyst for growth
+for us in the region. Our exploration and development budget in the Gulf Coast
+region for 2004 is $18.4 million of which 55 percent of these expenditures will
+be for operated projects.
+The most significant field in the Gulf Coast region is the Judge Digby
+Field, located outside Baton Rouge, Louisiana in Point Coupee Parish. As of the
+end of December 2003, this field represented slightly more than three percent of
+our total PV-10 value with 12.6 BCFE of proved reserves. Production from the
+Judge Digby field totaled 6.5 BCFE in 2003. Production from this field continues
+to decrease and this area is becoming a smaller component of the value of the
+Company.
+24
+Fee Lands. Since the initial discovery of oil on our fee lands in 1938, our
+cumulative oil and gas revenues, primarily landowner's royalties, from the Bayou
+Sale, Horseshoe Bayou and Belle Isle fields have exceeded $245 million. We
+currently lease 9,945 acres and have granted a seismic option to Seismic
+Exchange, Inc. on the remaining 14,969 acres. A 3-D seismic shoot over the
+entire fee land has been concluded and we anticipate receiving the newly shot
+and processed 3-D seismic early in 2004. These optioned acres are located
+primarily in the middle portion of our property where little exploration has
+taken place historically. If the lease option is exercised, the lease will
+provide us a 25 percent royalty and the option to participate for up to 25
+percent as a working interest owner. This working interest election is an
+individual well-by-well election. We are hopeful this will encourage development
+drilling by our lessees, facilitate the origination of new prospects and
+stimulate exploration interest in deeper, untested horizons. However, there can
+be no assurance that such activities will result. Our principal operators on the
+fee properties are BP, Cabot and Amerada Hess.
+Permian Basin Region. The Permian Basin area covers a significant
+portion of eastern New Mexico and western Texas and is one of the major
+producing basins in the United States. The basin includes hundreds of oil fields
+undergoing secondary and enhanced oil recovery projects. 3-D seismic imaging of
+existing fields and advanced secondary recovery programs are substantially
+increasing oil recoveries in the Permian Basin. Our holdings in the Permian
+Basin resulted from a series of property acquisitions since 1995. We believe
+that our Permian Basin operations provide us with a solid base of long-lived oil
+reserves, promising longer-term exploration and development prospects and the
+potential for secondary recovery projects. The Permian Basin region accounted
+for nine percent of our estimated proved reserves as of December 31, 2003, or
+50.6 BCFE, of which 70 percent were proved developed and 87 percent were oil.
+St. Mary participated in drilling 19 gross wells in 2003 with a 74
+percent success rate. The Parkway Delaware water flood project, located in Eddy
+County, New Mexico represents 19.8 BCFE or three percent of our proved reserves.
+The East Shugart Delaware Unit is a pilot water flood located in Lea and Eddy
+Counties, New Mexico that is analogous to the Parkway Delaware Unit. In the
+fourth quarter of 2003, production increased in response to pilot water flood
+activities. Proved reserves, primarily related to increased recovery due to the
+water flood, now total 15.0 BCFE. Production from the Permian Basin properties
+represented 4 BCFE or five percent of the total production for the Company in
+2003.
+Our Permian Basin capital budget for 2004 is $10.0 million. We plan to
+drill four injection wells and perform recompletion work in the East Shugart
+Delaware waterflood, and we plan to drill six in-fill wells in the Parkway
+field.
+Acquisitions and Divestitures
+In addition to the acquisition from Flying J of the oil and gas
+properties in the Rocky Mountain region, we completed a few smaller niche
+acquisitions during the past year. In January 2003 we acquired the remaining 50
+percent interest in the Ft. Chadbourne field in Coke and Runnels Counties, Texas
+at a favorable price. Later in the year, we sold our 100 percent working
+interest ownership in the Ft. Chadbourne field, recognizing a gain on the sale.
+In total the acquisitions in 2003 added 112.4 BCFE of proved reserves
+of which 87 percent was proved developed. In addition to the proved reserves, we
+acquired significant leasehold acreage in the Flying J acquisition.
+The total dispositions of oil and gas properties in 2003 resulted in
+net proceeds of $23.5 million, and the reserves attributable to the sales were
+45.6 BCFE.
+25
+Reserves
+The following table presents summary information with respect to the
+estimates of our proved oil and gas reserves for each of the years in the
+three-year period ended December 31, 2003, as prepared by both Ryder Scott
+Company, independent petroleum engineers, and us. For the periods presented,
+Ryder Scott Company evaluated properties representing a minimum of 80 percent of
+our total PV-10 value while we evaluated the remainder. The PV-10 values shown
+in the following table are not intended to represent the current market value of
+the estimated proved oil and gas reserves owned by St. Mary. Neither prices nor
+costs have been escalated. You should read the following table along with the
+sections entitled "Risk Factors - Risks Related to Our Business - Estimates of
+oil and gas reserves are not precise."
+As of December 31,
+-------------------------------------------------------------------
+Proved Reserves Data: 2003 2002 2001
+--------------------------------------------- --------------------- ------------------- -------------------
+Oil (MBbl) 47,787 36,119 23,669
+Gas (MMcf) 307,024 274,172 241,231
+MMCFE 593,744 490,887 383,247
+PV-10 value, without tax effect (in
+thousands) (1) $ 1,278,166 $ 824,808 $ 363,795
+Standardized measure of discounted
+future net cash flows (in thousands) $ 859,956 $ 581,862 $ 281,877
+Proved developed reserves 89% 88% 86%
+Production replacement 293% 306% 166%
+Reserve life (years) (2) 7.7 8.9 7.1
+----------------
+(1) PV-10 value as of December 31, 2003, was calculated using the weighted
+average sales price of $31.01 per barrel of oil and $5.70 per Mcf of
+gas. These prices are based on NYMEX prices for oil and a Gulf Coast
+spot price for gas in effect on December 31, 2003, and are then
+adjusted for transportation, quality and basis differentials.
+(2) Reserve life represents the estimated proved reserves at the dates
+indicated divided by actual production for the preceding 12-month
+period.
+26
+Production
+The following table summarizes the average volumes of oil and gas
+produced from properties in which St. Mary held an interest during the periods
+indicated:
+Years Ended December 31,
+-----------------------------------------------------
+2003 2002 2001
+---------------- ---------------- ----------------
+Operating Data:
+Net production:
+Oil (MBbl) 4,541 2,815 2,434
+Gas (MMcf) 49,663 38,164 39,491
+MMCFE 76,909 55,055 54,093
+Average net daily production:
+Oil (Bbl) 12,441 7,713 6,667
+Gas (Mcf) 136,062 104,558 108,195
+MCFE 210,709 150,836 148,199
+Average sales price (1):
+Oil (per Bbl) $ 26.96 $ 25.34 $ 23.29
+Gas (per Mcf) $ 4.89 $ 3.00 $ 3.73
+Additional per MCFE data:
+Lease operating expense $ 0.77 $ 0.66 $ 0.75
+Transportation costs $ 0.09 $ 0.06 $ 0.04
+Production taxes $ 0.29 $ 0.20 $ 0.23
+General and administrative $ 0.33 $ 0.26 $ 0.22
+Depreciation, depletion, amortization
+and liability accretion $ 1.07 $ 0.99 $ 0.95
+--------------------------------
+(1) Includes the effects of St. Mary's hedging activities. See
+"Management's Discussion and Analysis of Financial Condition and
+Results of Operations."
+27
+Productive Wells
+As of December 31, 2003, we had working interests in 1,449 gross (737
+net) productive oil wells and 1,616 gross (370 net) productive gas wells.
+Productive wells are either producing wells or wells capable of commercial
+production although currently shut in. One or more completions in the same
+wellbore are counted as one well. A well is categorized under state reporting
+regulations as an oil well or a gas well based upon the ratio of gas to oil
+produced when it first commenced production, and such designation may not be
+indicative of current production.
+Drilling Activity
+All of our drilling activities are conducted on a contract basis with
+independent drilling contractors. We do not own any drilling equipment. The
+following table sets forth the wells drilled and recompleted in which St. Mary
+participated during each of the three years indicated:
+Years Ended December 31,
+-----------------------------------------------------------------------------
+2003 2002 2001
+------------------------- ------------------------ ------------------------
+Gross Net Gross Net Gross Net
+------------ ----------- ----------- ----------- ---------- ------------
+Development:
+Oil 36 14.88 26 11.52 48 14.49
+Gas 140 43.79 103 38.89 154 33.28
+Non-productive 37 15.98 27 14.42 31 7.13
+------------ ----------- ----------- ----------- ---------- ------------
+213 74.65 156 64.83 233 54.90
+------------ ----------- ----------- ----------- ---------- ------------
+Exploratory:
+Oil 7 3.03 3 1.22 3 1.55
+Gas 14 7.20 1 0.10 9 1.84
+Non-productive 7 4.40 8 2.64 7 2.56
+------------ ----------- ----------- ----------- ---------- ------------
+28 14.63 12 3.96 19 5.95
+------------ ----------- ----------- ----------- ---------- ------------
+Farmout or non-consent 10 - 8 - 9 -
+------------ ----------- ----------- ----------- ---------- ------------
+Total (1) 251 89.28 176 68.79 261 60.85
+============ =========== =========== =========== ========== ============
+----------------------
+(1) Does not include 15, 14 and 12 gross wells completed on St. Mary's fee
+lands during 2003, 2002 and 2001, respectively, in which we have only a
+royalty interest.
+28
+Acreage
+The following table sets forth the gross and net acres of developed and
+undeveloped oil and gas leases, fee properties, mineral servitudes and lease
+options held by St. Mary as of December 31, 2003. Undeveloped acreage includes
+leasehold interests that may already have been classified as containing proved
+undeveloped reserves.
+Developed Acres (1) Undeveloped Acres (2) Total
+------------------------- ------------------------- --------------------------
+Gross Net Gross Net Gross Net
+---------- ----------- ----------- ---------- ----------- -----------
+Arkansas 2,136 356 167 28 2,303 384
+Colorado 2,645 2,553 26,164 13,120 28,809 15,673
+Louisiana 93,833 33,184 30,168 14,923 124,001 48,107
+Montana 72,200 38,703 527,930 365,336 600,130 404,039
+New Mexico 7,480 2,255 1,280 916 8,760 3,171
+North Dakota 147,110 81,178 140,466 89,349 287,576 170,527
+Oklahoma 231,386 62,246 47,835 23,230 279,221 85,476
+Texas 101,407 31,027 63,192 19,875 164,599 50,902
+Utah (3) 480 115 10,107 8,906 10,587 9,021
+Wyoming 58,861 27,562 427,382 264,503 486,243 292,065
+Other (4) 2,824 857 9,676 6,140 12,500 6,997
+---------- ---------- ----------- --------- ----------- -----------
+720,362 280,036 1,284,367 806,326 2,004,729 1,086,362
+---------- ---------- ----------- --------- ----------- -----------
+Louisiana Fee Properties 9,944 9,944 14,970 14,970 24,914 24,914
+Louisiana Mineral Servitudes 9,745 5,306 4,551 4,228 14,296 9,534
+---------- ---------- ----------- --------- ----------- -----------
+19,689 15,250 19,521 19,198 39,210 34,448
+---------- ---------- ----------- --------- ----------- -----------
+Total 740,051 295,286 1,303,888 825,524 2,043,939 1,120,810
+========== ========== =========== ========= =========== ===========
+-----------------
+(1) Developed acreage is acreage assigned to producing wells for the
+spacing unit of the producing formation. Developed acreage in certain of
+St. Mary's properties that include multiple formations with different well
+spacing requirements may be considered undeveloped for certain formations,
+but have only been included as developed acreage in the presentation above.
+(2) Undeveloped acreage is lease acreage on which wells have not been
+drilled or completed to a point that would permit the production of
+commercial quantities of oil and gas regardless of whether such acreage
+contains estimated proved reserves.
+(3) St. Mary holds an overriding royalty interest in an additional 41,523
+gross acres in Utah.
+(4) Includes interests in Alabama, Kansas, Mississippi, Nevada, South Dakota,
+and Washington.
+29
+ITEM 3. LEGAL PROCEEDINGS
+From time to time, we may be involved in litigation relating to claims
+arising out of our operations in the normal course of business. As of this date,
+no legal proceedings are pending against us that individually or collectively
+could have a material adverse effect upon our financial condition or results of
+operations.
+As previously reported Nance Petroleum Corporation, a wholly owned
+subsidiary is named along with several other leaseholders and interested parties
+as an additional co-defendant in a lawsuit that was originally filed in the U.S.
+District Court for the District of Montana on June 12, 2001. The plaintiff, the
+Northern Plains Resource Council, Inc. ("NPRC"), an environmental public
+interest group, sued the U.S. Bureau of Land Management, the U.S. Secretary of
+the Interior, the Montana BLM State Director and Fidelity Exploration &
+Production Company. The lawsuit seeks the cancellation of all federal leases
+related to coalbed methane development in Montana issued by the BLM since
+January 1, 1997. This cancellation is sought primarily on the grounds of an
+alleged failure of the BLM to comply with federal environmental laws. NPRC
+alleges that the environmental impacts of coalbed methane development were not
+properly analyzed before the challenged leases were issued. The Montana portion
+of our Hanging Woman Basin coalbed methane project contains approximately 74,000
+total net acres. The lawsuit potentially affects approximately 47,000 net acres
+that are subject to federal leases. Based on information presently available, we
+believe that the BLM complied with the applicable environmental laws, and the
+District Court agreed by granting the defendants' motion for summary judgment in
+December 2003. The court held that the issuance process regarding the federal
+leases in question complied with the applicable environmental laws. The
+plaintiff has appealed this decision and the Ninth Circuit Court of Appeals has
+granted expedited status to this appeal. Briefing should be complete by the end
+of the first quarter of 2004, but that does not necessarily indicate when the
+Ninth Circuit Court of Appeals will render a decision. Notwithstanding our
+success in the lower court, there is no assurance as to the outcome of the
+lawsuit, and therefore, there is no assurance that it will not adversely affect
+our coalbed methane project. Even if the federal leases in Montana become
+unavailable, we are proceeding with this project on non-federal leases in
+Wyoming, and we anticipate acquiring additional non-federal leases in Montana
+and Wyoming.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
+There were no matters submitted to a vote of our security holders
+during the fourth quarter of 2003.
+30
+ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
+The following table sets forth the names, ages and positions held by
+St. Mary's executive officers.
+Name Age Position
+---- --- --------
+Mark A. Hellerstein 51 Chairman of the Board, President and Chief
+Executive Officer
+Douglas W. York 42 Executive Vice President and Chief Operating
+Officer
+Robert L. Nance 67 Senior Vice President, and President and Chief
+Executive Officer of Nance Petroleum
+Corporation, a wholly-owned subsidiary of
+St. Mary
+Jerry R. Schuyler 48 Senior Vice President and Regional Manager
+Kevin E. Willson 47 Senior Vice President - Mid-Continent Drilling
+and Production
+Robert T. Hanley 57 Vice President - Investor Relations and
+Management Reporting
+David W. Honeyfield 37 Vice President - Finance, Treasurer and
+Secretary
+Milam Randolph Pharo 51 Vice President - Land and Legal
+Garry A. Wilkening 53 Vice President - Administration and Controller
+Each executive officer has held his respective position during the past
+five years, except as follows:
+Mark A. Hellerstein was appointed Chairman of the Board in September
+2002.
+Douglas W. York was appointed Executive Vice President and Chief
+Operating Officer in September 2003. Mr. York served as Vice-President -
+Acquisitions and Reservoir Engineering from 1996 to September 2003.
+Robert L. Nance was appointed Senior Vice President in March 2001.
+Jerry R. Schuyler joined St. Mary in December 2003 as Senior Vice
+President and Regional Manager of the Gulf Coast region. From November 2001 to
+July 2002, Mr. Schuyler was Senior Vice President and General Manager - Eastern
+Onshore Division for Dominion Exploration & Production, Inc., where he
+managed all operations and exploration for Dominion's Gulf Coast and eastern
+onshore U.S. regions. From March 2000 to November 2001, Mr. Schuyler was Senior
+Vice President and General Manager of Dominion's Onshore U.S. Division, where he
+managed all operations and exploration for all of Dominion's onshore U.S.
+regions. From 1996 to 2000, Mr. Schuyler was President and Managing Director,
+ARCO Middle East & Central Asia, where he managed all operations for ARCO
+International Oil & Gas Company in the Arabian Peninsula, Turkey and
+Pakistan.
+Kevin E. Willson was appointed Senior Vice President and Regional
+Manager in November 2003. Mr. Willson served as Vice President - Mid-Continent
+Exploration/Production from October 1998 to November 2003. Mr. Willson joined
+Anderman/Smith, a predecessor to St. Mary's interests in the Mid-Continent
+region, in 1990 and was appointed Vice President - Mid-Continent Engineering for
+St. Mary in 1995.
+Robert T. Hanley was appointed Vice President - Investor Relations and
+Management Reporting in April 2003. Mr. Hanley served as Vice President -
+Business Development from July 2000 to April 2003. Mr. Hanley was Chief
+Financial Officer of Nance Petroleum Corporation from 1999 to 2000 and Chief
+31
+Financial Officer of Panterra Petroleum, a partnership between St. Mary and
+Nance Petroleum Corporation, from 1992 to 1999.
+David W. Honeyfield joined St. Mary in May 2003 as Vice President -
+Finance, Treasurer and Secretary. Prior to joining St. Mary, Mr. Honeyfield was
+Controller and Chief Accounting Officer of Cimarex Energy Co. from September
+2002 to May 2003 and Controller and Chief Accounting Officer of Key Production
+Company, Inc., which was acquired by Cimarex in September 2003. Prior to joining
+Key Production Company in April 2002, Mr. Honeyfield was a senior audit manager
+with Arthur Andersen LLP in Denver. Mr. Honeyfield had been with Arthur Andersen
+since January 1991.
+Garry A. Wilkening was appointed Vice President - Administration in
+February 1999.
+The executive officers of the Company serve at the pleasure of the
+Board of Directors and do not have fixed terms. Executive officers generally are
+elected at the regular meeting of the board immediately following the annual
+stockholders meeting. Any officer or agent elected or appointed by the board may
+be removed by the board whenever in its judgment the best interests of the
+Company will be served thereby without prejudice, subject however, to
+contractual rights, if any, of the person so removed. Mr. Hellerstein is
+chairman of the Board of Directors and has an employment agreement with St.
+Mary. The agreement is terminable at any time upon 30 days' notice by either
+party. Upon termination of the agreement by St. Mary for any reason other than
+death, disability or misconduct by Mr. Hellerstein, St. Mary is obligated to
+continue to pay his compensation and insurance benefits, at the level at the
+time of termination, for a period of one year.
+There are no family relationships, first cousin or closer, between any
+executive officer and director. There are no arrangements or understandings
+between any officer and any other person pursuant to which that officer was
+elected.
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER
+MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
+Market Information. St. Mary's common stock is currently traded on the
+New York Stock Exchange under the symbol SM after transferring from the NASDAQ
+National Market System on November 20, 2002. The range of high and low sales
+prices for the quarterly periods in 2003 and 2002, as reported by the New York
+Stock Exchange after November 19, 2002, and the NASDAQ National Market System
+before November 20, 2002, is set forth below:
+Quarter Ended High Low
+------------------------- ----------------- -----------------
+December 31, 2003 $ 29.19 $ 24.45
+September 30, 2003 28.85 24.45
+June 30, 2003 29.75 24.65
+March 31, 2003 27.23 23.80
+December 31, 2002 $ 27.35 $ 23.16
+September 30, 2002 24.71 19.00
+June 30, 2002 25.05 21.00
+March 31, 2002 23.25 18.75
+32
+Holders. As of February 20, 2004, the number of record holders of St.
+Mary's common stock was 173. Management believes, after inquiry, that the number
+of beneficial owners of our common stock is in excess of 3,700.
+Dividends. St. Mary has paid cash dividends to stockholders every year
+since 1940. Annual dividends of $0.10 per share were paid in each of the years
+1998 through 2003. We expect that our practice of paying dividends on our common
+stock will continue, although the payment of future dividends on our common
+stock will continue to depend on our earnings, capital requirements, financial
+condition and other factors. In addition, the payment of dividends is subject to
+covenants in our bank credit facility, including the requirement that we
+maintain certain levels of stockholders' equity and the limitations of our
+annual dividend rate to no more than $0.20 per share. Dividends are currently
+paid on a semi-annual basis. Dividends paid totaled $3.1 million in 2003 and
+$2.8 million in 2002.
+Restricted Shares. On January 29, 2003, St. Mary issued 3,380,818
+restricted shares of our common stock in connection with the acquisition of oil
+and gas properties from Flying J Oil & Gas Inc. and Big West Oil & Gas
+Inc. As of December 31, 2003 these shares were subject to contractual
+restrictions on transfer for a period of two years. The Company repurchased
+these shares on February 9, 2004 in a separately negotiated transaction.
+Issuer Purchases of Equity Securities. St. Mary did not repurchase any
+shares of its common stock during the fourth quarter of 2003.
+Equity Compensation Plans. St. Mary has a stock option plan, an
+incentive stock option plan, an employee stock purchase plan and a non-employee
+director stock compensation plan under which options and shares of St. Mary
+common stock are authorized for grant or issuance as compensation to eligible
+employees, consultants and members of the Board of Directors. Our stockholders
+have approved each of these plans. See Note 7 of the Notes to Consolidated
+Financial Statements included in this report for further information about the
+material terms of these plans. The following table is a summary of the shares of
+common stock authorized for issuance under our equity compensation plans as of
+December 31, 2003:
+( a ) ( b )
+Number of securities Weighted-average ( c )
+to be issued upon exercise price of Number of securities
+Exercise of outstanding options, remaining available for
+outstanding options, Warrants and rights future issuance under
+warrants and rights equity compensation
+plans (excluding
+securities reflected in
+Plan Category column (a))
+----------------------------------- --------------------- --------------------- --------------------------
+Equity compensation plans approved
+by security holders 3,525,128 $ 23.12 1,723,013 (1)
+Equity compensation plans not
+approved by security holders - - -
+--------------------- --------------------- --------------------------
+Total 3,525,128 $ 23.12 1,723,013
+===================== ===================== ==========================
+--------------
+(1) Includes shares that are authorized for issuance under our employee
+stock purchase plan.
+33
+ITEM 6. SELECTED FINANCIAL DATA
+The following table sets forth selected consolidated financial data for
+St. Mary as of the dates and for the periods indicated. The financial data for
+each of the five years presented were derived from the consolidated financial
+statements of St. Mary. The following data should be read in conjunction with
+"Management's Discussion and Analysis of Financial Condition and Results of
+Operations," which includes a discussion of factors materially affecting the
+comparability of the information presented, and in conjunction with St. Mary's
+consolidated financial statements included elsewhere in this report.
+Years Ended December 31,
+-------------------------------------------------------------------
+2003 2002 2001 2000 1999
+------------- ------------ ------------ ------------- -------------
+(In thousands, except per share data)
+Income Statement Data:
+Operating revenues:
+Oil and gas production $365,114 $185,670 $203,973 $188,407 $ 73,387
+Gas marketing revenue 13,438 8,399 420 - -
+Gain (loss) on sale of proved properties 7,278 (2,633) 367 3,404 (55)
+Derivative gain - 3,188 - - -
+Other
+8,104 1,770 2,709 3,855 1,582
+------------- ------------ ------------ ------------- -------------
+Total operating revenues 393,934 196,394 207,469 195,666 74,914
+------------- ------------ ------------ ------------- -------------
+Operating expenses:
+Oil and gas production 88,509 50,839 55,000 38,461 19,574
+Depletion, depreciation & amortization 81,960 54,432 51,346 40,129 22,574
+Exploration 26,653 19,501 19,518 9,633 11,593
+Impairment of proved properties 185 - 820 4,449 3,982
+Abandonment and impairment of
+unproved properties 3,796 2,446 3,865 1,841 6,616
+General and administrative 25,179 14,299 11,762 11,166 9,172
+Gas marketing expense 12,229 7,982 420 - -
+Derivative loss 310 - 1,573 - -
+Other 1,802 1,206 1,253 1,437 1,802
+------------- ------------ ------------ ------------- -------------
+Total operating expenses 240,623 150,705 145,557 107,116 75,313
+------------- ------------ ------------ ------------- -------------
+Income (loss) from operations 153,311 45,689 61,912 88,550 (399)
+Non-operating (expense) income (7,241) (3,110) 376 737 75
+Income tax (expense) benefit (55,930) (15,019) (21,829) (33,667) 406
+------------- ------------ ------------ ------------- -------------
+Income before cumulative effect of change
+in accounting principle 90,140 27,560 40,459 55,620 82
+Cumulative effect of change in accounting
+principle, net of income taxes 5,435 - - - -
+------------- ------------ ------------ ------------- -------------
+Net income $ 95,575 $ 27,560 $ 40,459 $ 55,620 $ 82
+============= ============ ============ ============= =============
+34
+Years Ended December 31,
+------------------------------------------------------------------
+2003 2002 2001 2000 1999
+------------ ------------ ------------- ------------ --------------
+(In thousands, except per share data)
+Basic earnings per common share
+Income before cumulative effect of change
+in accounting principle $ 2.89 $ 0.99 $ 1.45 $ 2.00 $ -
+Cumulative effect of change in accounting
+principle 0.17 - - - -
+------------ ------------ ------------- ------------ --------------
+Basic net income per common share $ 3.06 $ 0.99 $ 1.45 $ 2.00 $ -
+============ ============ ============= ============ ==============
+Diluted earnings per common share:
+Income before cumulative effect of change
+in accounting principle $ 2.65 $ 0.97 $ 1.42 $ 1.97 $ -
+Cumulative effect of change in accounting
+principle 0.15 - - - -
+------------ ------------ ------------- ------------ --------------
+Diluted net income per common share $ 2.80 $ 0.97 $ 1.42 $ 1.97 $ -
+============ ============ ============= ============ ==============
+Basic weighted average common shares
+outstanding 31,233 27,856 27,973 27,781 22,198
+Diluted weighted average common shares
+outstanding 35,534 28,391 28,555 28,271 22,329
+Cash dividends per share $ 0.10 $ 0.10 $ 0.10 $ 0.10 $ 0.10
+Balance Sheet Data (end of period):
+Working capital $ 3,101 $ 2,050 $ 34,000 $ 40,639 $ 13,440
+Net property and equipment 611,287 471,939 358,930 252,411 180,664
+Total assets 735,854 537,139 436,989 321,895 230,438
+Long-term obligations 110,696 113,601 64,000 22,000 13,000
+Total stockholders' equity 390,653 299,513 286,117 250,136 188,772
+Other Data:
+Net Cash provided by (used in):
+Operating activities 204,319 141,709 127,492 92,267 40,755
+Investing activities (196,939) (180,931) (159,075) (112,868) (22,243)
+Financing activities (3,707) 46,260 29,080 13,025 (12,138)
+Capital and exploration expenditures, cash and
+non cash, including asset retirement
+obligation 236,949 192,988 182,863 125,184 91,184
+35
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
+FINANCIAL CONDITION AND RESULTS OF OPERATION
+This discussion includes forward-looking statements. Please refer to
+the Cautionary Statement about Forward-Looking Statements section in Part I,
+Item 1 of this document for an explanation of these types of statements.
+Overview of the Company
+General Overview
+We are an independent energy company focused on the exploration,
+exploitation, acquisition and production of natural gas and crude oil in the
+United States. We earn our revenues and generate our cash flows from operations
+primarily from the sale at the wellhead of produced natural gas and crude oil.
+Our oil and gas reserves and operations are concentrated primarily in the
+Anadarko, Arkoma, Permian and various Rocky Mountain basins and the onshore Gulf
+Coast and offshore Gulf of Mexico. We maintain a balanced portfolio of proved
+reserves, development drilling opportunities and non-conventional gas prospects.
+As of December 31, 2003, we had estimated proved reserves of 593.7 BCFE, with a
+before income tax PV-10 value of $1.3 billion and an after income tax value of
+$860.0 million.
+Oil and Gas Prices
+Our results of operations and financial condition are significantly
+affected by oil and natural gas commodity prices, which can fluctuate
+dramatically. In 2003 oil and gas producers enjoyed high oil and gas commodity
+prices, primarily due to colder winter weather in the northeast, falling
+domestic gas deliverability, and very low gas storage levels creating a near
+shortage situation early in the year.
+Reserve Replacement and Growth
+Like all oil and gas exploration and production companies, we face the
+challenge of natural resource production decline. As oil and gas is depleted
+from a well, oil and gas production from that well naturally decreases. An oil
+and gas exploration and production company depletes part of its asset base with
+each unit of oil and gas it produces. Historically we have been able to grow our
+production, despite this natural decline by adding, through acquisitions and
+drilling, more reserves than we produce. Future growth will depend on our
+ability to continue to add reserves in excess of production.
+We believe that growth in net asset value per share drives appreciation
+in our stock price. Our challenge to grow net asset value per share has always
+been a difficult one. To do this we set a goal of economically replacing 200
+percent of our annual production. We have successfully achieved this goal over
+time. Sustainability in our business is dependent on the ability to create new
+ideas and new value year after year. The challenges we face are becoming
+increasingly difficult as North American oil and gas production continues to
+decline and other exploration and production companies compete for available
+reserves. We believe we have a formula for meeting these challenges. We have
+placed talented geoscientists, engineers and landmen in each of our regional
+offices where their local knowledge and experience can be fully utilized. They
+are supported with a strong balance sheet and fiscal and operating discipline.
+36
+In 2003 our pre-tax PV-10 value for proved reserves increased 55
+percent to $1.3 billion, with a standardized measure value of $860.0 million,
+reflecting a 21 percent increase in reserves as well as 5 percent and 37 percent
+respective increases in oil and gas reserve pricing, to $31.01 per barrel and
+$5.70 per Mcf.
+Included in the proved reserve increase noted above is a positive
+revision of 21.0 BCFE, of which 14.3 BCFE related to positive well performance.
+We replaced 293 percent of our 2003 production at a finding cost of $1.05 per
+MCFE, including the impact of asset retirement obligations. Relative to our
+peers we have a very low PUD percentage of 11 percent at year-end. We are
+pleased with these results and believe they compare favorably with industry
+results.
+2003 Highlights
+In 2003 we enjoyed record earnings, high oil and gas prices, a 40
+percent increase in production, a 21 percent increase in proved reserves
+obtained at a low reserve replacement cost, moderate increases in operating
+costs, profitable sales of non-strategic assets, and advancement of the Hanging
+Woman Basin coalbed methane project to the development stage. Highlights for
+2003 also include good drilling results at Huxley in East Texas and Northeast
+Mayfield in Oklahoma; participation in the new Bakken horizontal dolomite play
+in the Williston Basin; better than expected production performance at the
+Parkway Delaware waterflood project in the Permian Basin and at the Judge Digby
+field in South Louisiana; and increased production from the acquisition of
+properties in the Rocky Mountain region from Flying J in January 2003 and from
+Burlington Resources in December 2002. We opened a Houston office, which will
+now be directing our Gulf Coast and Permian Basin regional operations.
+In 2003 colder winter weather in the northeast, falling domestic gas
+deliverability, and very low gas storage levels created a near shortage
+situation early in the year and acted as a catalyst for extremely high prices
+during the first quarter. Moderate summer weather and decreased demand allowed
+gas storage to refill to normal levels at the beginning of the 2003-2004 winter
+season. Despite these factors, gas prices remained strong due to the industry's
+inability to grow deliverability from the maturing basins of North America and
+due to difficulties encountered in both obtaining access to the vast public
+lands of the western United States and building a pipeline to transport Alaskan
+natural gas to the lower 48 states. Oil prices were also very strong, reflecting
+low inventories and uncertainties resulting from a Venezuelan strike, West
+African unrest, the Iraqi war, the OPEC action to curtail production to maintain
+its desired price target and crude oil refining issues in the United States.
+NYMEX prices for the year averaged $5.39 per MMBtu and $30.97 per barrel, up 41
+percent on a realized MCFE basis. At December 31, 2003, the 12-month NYMEX strip
+was $29.98 per barrel for oil and $5.37 per MMBtu for gas.
+Net income for the year 2003 was a record $95.6 million or $2.80 per
+diluted share compared to $27.6 million or $0.97 per diluted share for the prior
+year. Net cash provided by operating activities was $204.3 million, up 44
+percent, from 2002. Production increased 40 percent to 76.9 BCFE. Our average
+realized price increased 41 percent to $4.75 per MCFE. Unit costs increased
+modestly for the period as lease operating expense (including taxes) increased
+$0.23 to $1.15 per MCFE, DD&A (including impairments) increased $0.08 to
+$1.07 per MCFE and general and administrative expense increased $0.06 to $0.33
+per MCFE.
+2004 Outlook
+We enter 2004 on a positive note. Oil and gas prices are high, and the
+long-term outlook is positive. We have attractive prospects to be drilled. Rig
+and other service costs are moderate. The country's ability to supply gas
+remains challenging as the average decline rate for natural gas has increased
+37
+from 17 percent to 28 percent over the past thirteen years. This change is a
+result of increased activity in the Gulf of Mexico where reserve lives are very
+short, the use of 3D seismic to identify smaller reservoirs, and better
+completion techniques that allow reserves to be produced faster. New sources of
+gas such as LNG, frontier regions (e.g. deepwater Gulf of Mexico and Mackenzie
+Delta, Alaska) and unconventional gas plays are both more costly and have long
+lead times, but at some point could have a positive impact on supply. We believe
+oil prices are unusually high now due to low inventory levels. Longer term,
+however, we are beginning to see excess oil capacity in the world diminish and
+OPEC informally appearing to target a higher price range due to the decline in
+the value of the dollar. As the global economy continues to recover from the
+recent economic downturn, we anticipate the demand for oil will increase.
+We enter 2004 in very good financial condition and with a capital
+expenditure budget of $273.4 million. Here is our plan to build value in 2004:
+o Of the $273.4 million capital expenditures budget, 36 percent is
+allocated for acquisitions, 22 percent for exploration and
+development in the Mid-Continent region, 19 percent in the Rocky
+Mountain region, 8 percent in the ArkLaTex region, 7 percent in the
+Gulf Coast region and 4 percent in the Permian region. Four percent
+of the budget is allocated to development of our Hanging Woman Basin
+coalbed methane play and other CBM projects. The 2004 exploration
+and development budget is $173.4 million, which represents a 28
+percent increase over the 2003 exploration and development budget.
+o We will begin development of our Hanging Woman Basin coalbed methane
+project with the drilling of approximately 100 wells in Wyoming and
+the construction of infrastructure such as electric grid and
+pipeline. We currently expect production of natural gas to begin in
+2005.
+o In early 2004 we will receive newly shot and processed 3-D seismic
+covering our entire 24,914 fee acreage position in St. Mary Parish,
+Louisiana. We have optioned 14,969 acres for lease primarily in the
+middle portion of our property where little exploration has
+historically taken place. Providing the option is exercised, the
+lease terms will give us a 25 percent royalty interest and the
+option to participate for up to 25 percent as a working interest
+owner if the lease option is exercised. We can make the working
+interest elections on an individual well-by-well basis.
+38
+A year-to-year overview of selected reserve, production and financial
+information, including trends:
+Selected Operations Data (In Thousands, Except Price and Per MCFE Amounts):
+---------------------------------------------------------------------------
+As of and for the Years Ended % of Change Between
+------------------------------------------
+2003 2002 2001 2003/2002 2002/2001
+------------ ----------- ----------- --------- ---------
+Total Proved Reserves (SEC Case 10 Basis)
+------------------------------------------
+Natural Gas (Mcf) 307,024 274,172 241,231
+Oil (Bbl) 47,787 36,119 23,669
+MCFE 593,744 490,887 383,247 21% 28%
+Net Production Volumes
+----------------------
+Natural Gas (Mcf) 49,663 38,164 39,491
+Oil (Bbl) 4,541 2,815 2,434
+MCFE 76,909 55,055 54,093 40% 2%
+Oil & Gas Production Revenues
+---------------------------------
+Gas Production $ 242,670 $ 114,334 $ 147,292
+Oil Production 122,444 71,336 56,681
+------------ ----------- -----------
+Total $ 365,114 $ 185,670 $ 203,973 97% (9)%
+============ =========== ===========
+Oil & Gas Production Costs
+------------------------------
+Lease Operating Expenses $ 59,152 $ 36,472 $ 40,505
+Transportation Costs 7,197 3,184 2,321
+Production Taxes 22,160 11,183 12,174
+------------ ----------- -----------
+Total $ 88,509 $ 50,839 $ 55,000 74% (8)%
+============ =========== ===========
+Average Realized Sales Price (1)
+--------------------------------
+Natural Gas (Per Mcf) $ 4.89 $ 3.00 $ 3.73 63% (20)%
+Oil (Per Bbl) $ 26.96 $ 25.34 $ 23.29 6% 9%
+Per MCFE Data:
+--------------
+Net Realized Price $ 4.75 $ 3.37 $ 3.77 41% (11)%
+Lease Operating Expense (0.77) (0.66) (0.75) 17% (12)%
+Transportation Costs (0.09) (0.06) (0.04) 50% 50%
+Production Taxes (0.29) (0.20) (0.23) 45% (13)%
+General and Administrative (0.33) (0.26) (0.22) 27% 19%
+------------ ----------- -----------
+Operating Profit $ 3.27 $ 2.19 $ 2.53 49% (13)%
+============ =========== ===========
+Depletion, Depreciation and Amortization $ 1.07 $ 0.99 $ 0.95 8% 4%
+Financial Information (In Thousands, Except Per Share Amounts):
+---------------------------------------------------------------
+As of and for the Years Ended % of Change Between
+------------------------------------------
+2003 2002 2001 2003/2002 2002/2001
+------------ ----------- ----------- --------- ---------
+Working Capital $ 3,101 $ 2,050 $ 34,000 51% (94)%
+Long-Term Debt $ 110,696 $ 113,601 $ 64,000 (3)% 78%
+Stockholders' Equity $ 390,653 $ 299,513 $ 286,117 30% 5%
+Net Income $ 95,575 $ 27,560 $ 40,459 247% (32)%
+Basic Net Income Per Common Share $ 3.06 $ 0.99 $ 1.45 209% (32)%
+Diluted Net Income Per Common Share $ 2.80 $ 0.97 $ 1.42 189% (32)%
+Basic Weighted Average Shares Outstanding 31,233 27,856 27,973 12% -%
+Diluted Weighted Average Shares Outstanding 35,534 28,391 28,555 25% (1)%
+Net Cash Provided By Operating Activities $ 204,319 $ 141,709 $ 127,492 44% 11%
+Net Cash Used In Investing Activities $ (196,939) $(180,931) $(159,075) 9% 14%
+Net Cash Provided By (Used In) Financing
+Activities $ (3,707) $ 46,260 $ 29,080 (108)% 59%
+---------------------
+(1) Includes the effects of our hedging activities.
+39
+We present this table as a summary of information relating to those key
+indicators of financial condition and operating performance that we believe to
+be important.
+We have experienced a 60 percent increase in reserve volumes over the
+two years presented above. These increases are a result of drilling results
+which added 131.6 BCFE, acquisitions which added 214.6 BCFE, a 130 percent
+increase in natural gas prices used to evaluate reserves, and a 71 percent
+increase in crude oil prices used to evaluate reserves. We target replacing 200
+percent of our production each year. We anticipate that we must continue our
+successful drilling program and make one or more relatively significant
+acquisitions per year in the current price environment to achieve this level of
+growth. If we achieve our goal but commodity prices decrease, we may not be able
+to sustain the 2003 results we attained.
+The changes in production volumes, oil and gas production revenues and
+costs reflect the cyclical and highly volatile nature of prices our industry
+receives for production and the effect of the timing of acquisitions. Actual
+results in 2002 reflected a lower price environment than in either 2001 or 2003.
+We closed our acquisition of Burlington properties in late 2002 and our
+acquisition of Flying J properties in early 2003. Production of 13.8 MMCFE from
+these two acquisitions was realized in 2003. These were the two largest
+acquisitions in our history and combined with our successful drilling results in
+2002 and 2003 to result in a 40 percent increase in production from 2002 to
+2003.
+We present per MCFE information since we use this information to
+evaluate our performance relative to our peers and to measure trends that we
+believe require analysis. Our year-to-year comparison of financial results
+presented later provides additional details for the changes between years. We
+expect oil and gas production expenses will increase in 2004 as a result of
+increased activity in our higher-cost Rocky Mountain region, increased
+production taxes, and general inflation due to higher oil and gas pricing.
+Depreciation, depletion and amortization will continue to increase due to the
+higher costs associated with finding and acquiring crude oil and natural gas.
+General and administrative expense is also projected to increase for
+compensation expense associated with our net profits interest bonus plan,
+expensing of stock-based compensation and costs we incur to comply with
+legislative responses to the recent scandals that have plagued corporate
+America.
+Excluding the cumulative effect of change in accounting principle, our
+net income increase in 2003 was primarily driven by a 40 percent production
+increase combined with realized price increases of 63 percent for natural gas
+and 6 percent for oil. We note that we contained our costs and, as a result, our
+operating profit as a percentage of net realized price was 69 percent in 2003
+compared to 65 percent in 2002 and 67 percent in 2001. Net income as a
+percentage of oil and gas revenue increased from 20 percent in 2001 and 15
+percent in 2002 to 25 percent in 2003.
+We have in-the-money stock options and convertible notes that can be
+considered dilutive securities. At times these dilutive securities can affect
+our earnings per share, and both basic and diluted earnings per share are
+presented in the table above. You should review Note 1 of Part IV, Item 15 of
+this report for a detailed explanation. Our basic earnings per share in 2003
+reflects an increase in net income from operations, the effect of a change in
+accounting principle offset by increases in outstanding shares related to stock
+options, and the shares issued in the Flying J transaction, which we repurchased
+in early 2004. The change in diluted earnings per share in 2003 reflects the
+inclusion of shares related to our convertible debt offset by the add-back of
+interest expense related to that debt.
+The remaining information in the table relates to information we have
+provided in operations update press releases and is intended to supplement the
+discussion above.
+Overview of Liquidity and Capital Resources
+We own depleting assets. In order to maintain our current size and to
+sustain our projected growth levels, we will have to successfully invest capital
+into new projects and acquisitions. The following analysis and discussion
+40
+includes our assessments of market risk and possible effects of inflation and
+changing prices.
+Sources of cash
+Our primary sources of liquidity are the cash provided by operating
+activities, debt financing, sales of non-strategic properties and access to the
+capital markets. All of these sources can be impacted by the general condition
+of our industry and significant fluctuations in oil and gas prices, operating
+costs and volumes produced. An unexpected decrease in prices would reduce
+expected cash flow from operating activities, might reduce the borrowing base on
+our credit facility, could reduce the value of our non-strategic properties and
+historically has limited our industry's access to the capital markets.
+Our current credit facility. On January 29, 2003, we entered into a new
+$300.0 million credit facility with Wachovia Bank as Administrative Agent and
+eight other participating banks. This new credit facility replaced a previous
+credit facility and has a maturity date of January 27, 2006. The calculated
+borrowing base as of December 31, 2003 is $275.0 million. We have elected a
+commitment amount of $150.0 million under this facility, which results in lower
+commitment fees payable to the bank syndicate. We believe this commitment level
+is adequate for our near-term liquidity requirements. We must comply with
+certain financial and non-financial covenants, and we are currently in
+compliance with all of these covenants. Interest and commitment fees are accrued
+based on the borrowing base utilization percentage. LIBOR based borrowings
+accrue interest at LIBOR plus the applicable margin from the utilization table,
+and Alternate Base Rate borrowings accrue interest at prime plus the applicable
+margin from the utilization table located in Note 5 of Part IV, Item 15 of this
+report. Commitment fees are accrued on the unused portion of the aggregate
+commitment amount and are included in interest expense in the consolidated
+statements of operations. Our loan balance of $11.0 million on December 31,
+2003, was comprised of ABR borrowings.
+Our weighted average interest rate paid in 2003 was 6.3 percent and
+included commitment fees paid on the unused portion of the credit facility
+borrowing base, amortization of deferred financing costs, and amortization of
+the contingent interest embedded derivative associated with the convertible
+notes.
+Interest Rate Risk. Market risk is estimated as the potential change in
+fair value resulting from an immediate hypothetical one-percentage point
+parallel shift in the yield curve. The sensitivity analysis discussed below
+presents the hypothetical change in fair value of those financial instruments we
+held at December 31, 2003, that are sensitive to changes in interest rates. For
+fixed-rate debt, interest rate changes affect the fair market value but do not
+impact results of operations or cash flows. Conversely, interest rate changes
+for floating-rate debt generally do not affect the fair market value but do
+impact future results of operations and cash flows, assuming other factors are
+held constant. The carrying amount of our floating rate debt approximates its
+fair value. After consideration of the effect of the interest rate swaps, we had
+floating-rate debt of $61.0 million and had $50.0 million of fixed-rate debt at
+December 31, 2003. Assuming constant debt levels, the cash flow impact for the
+next year resulting from a one-percentage point change in interest rates would
+be approximately $610,000 before taxes. The results of operations impact might
+be less than this amount as a direct effect of the capitalization of interest to
+wells drilled in the next year. In prior years when our debt amount was at a
+reduced level we capitalized a larger percentage of our interest expense. Since
+we cannot predict the exact amount that would be capitalized, we cannot predict
+the exact affect that a one-percentage point shift would have on the results of
+operations.
+41
+Uses of cash
+We use cash for the acquisition, exploration and development of oil and
+gas properties and for the payment of debt obligations, trade payables and
+stockholder dividends. Exploration and development programs are generally
+financed from internally generated cash flow, debt financing and cash and cash
+equivalents on hand. Cash used for the acquisition of oil and gas properties and
+the payment of stockholder dividends is discretionary and can be reduced or
+eliminated in the event of an unexpected decrease in oil and gas prices. At any
+given point in time we may be obligated to pay for commitments to explore for or
+develop oil and gas properties or incur trade payables. However, future
+obligations can be reduced or eliminated when necessary. Over the next year we
+are required to only make interest payments on our debt obligations. An
+unexpected increase in oil and gas prices provides flexibility to modify our
+uses of cash flow.
+Over the course of 2003 we reduced our outstanding debt by a net $3.0
+million, paid $76.4 million for property acquisitions including the $71.6
+million loan to Flying J and spent $123.8 million on capital development using
+cash flows from operations. We have also made $28.9 million of cash payments for
+income taxes.
+On February 9, 2004, we repurchased for $91.0 million the 3,380,818
+restricted shares of common stock that we issued to Flying J on January 29,
+2003. Flying J used the proceeds to repay their outstanding loan principal
+balance to us of $71.6 million. Accrued interest on the loan, which was not
+recorded by us for financial reporting purposes due to the non-recourse nature
+of the loan, was forgiven. The $19.4 million net cash outlay was funded from our
+existing cash balance and borrowings under our bank credit facility. See Note 13
+of Part IV, Item 15 of this report. At February 20, 2004, we have $10.0 million
+outstanding on our credit facility.
+The following table presents amounts and percentage changes between
+years in net cash flows from our operating, investing and financing activities.
+The analysis following the table should be read in conjunction with our
+consolidated statements of cash flows in Part IV, Item 15 of this report.
+Amount of Change Between Percent of Change Between
+----------------------------- -----------------------------
+2003/2002 2002/2001 2003/2002 2002/2001
+------------- ------------ ------------- ------------
+Net Cash Provided By Operating Activities $ 62,610 $ 14,217 44% 11%
+============= ============ ============= ============
+Net Cash Used In Investing Activities $ (16,008) $ (21,856) 9% 14%
+============= ============ ============= ============
+Net Cash Provided By (Used In) Financial Activities $ (49,967) $ 17,180 (108)% 59%
+============= ============ ============= ============
+Analysis of cash flow changes between 2003 and 2002
+Operating activities. The differences above reflect increases in
+sources of cash flow from oil and gas sales due to a 40 percent increase in
+production and a 41 percent increase in price. We did not see the full $99.2
+million benefit of the net change between years in our cash flow since $40.8
+million of the change in net income adjusted for non-cash items related to an
+increase in outstanding accounts receivable of $29.7 million at December 31,
+2003. The remaining $5.7 million difference relates to proceeds from asset
+sales, collections of refundable income tax and increases in prepaid expenses
+and accounts payable.
+Investing Activities. The increase results primarily from additional
+capital and exploration costs. Total 2003 capital expenditures for cash,
+including acquisitions of oil and gas properties, increased $15.5 million or 8
+percent to $200.2 million in 2003 compared to $184.7 million in 2002. Increases
+42
+in proceeds from sales were partially offset by amounts deposited in long-term
+restricted cash accounts for the tax-deferred exchange of oil and gas
+properties. The long-term restricted cash may be used for acquisition of oil and
+gas properties in 2004. The amount of cash invested in long-term restricted cash
+reflects our projection of the likelihood we will be successful. Our sales of
+proved oil and gas properties in 2003 resulted in $23.5 million of cash
+proceeds. The volumes, revenue and net operating margin from the properties that
+we sold were not a material component of the current year or any prior year
+component of the consolidated statements of operations or balance sheets, nor do
+they represent a group of assets that would qualify for discontinued operation
+accounting treatment.
+Cash expended in 2003 for acquisitions of oil and gas properties
+includes our utilization of $71.6 million of short-term investments, cash
+equivalents and increased borrowings under our credit facility to provide a loan
+to Flying J as part of our acquisition of properties. This loan was secured by
+the shares of our common stock issued in the transaction.
+In December 2002 we purchased oil and gas properties from Burlington
+Resources Oil & Gas Company LP for $69.5 million in cash. We financed this
+acquisition using cash on hand and a portion of our bank credit facility.
+Financing activities. The $50.0 million decrease from 2002 to 2003
+reflects the issuance of our convertible notes and a $3.0 million pay down of
+our credit facility in 2003.
+Our senior convertible notes. In March 2002 we issued in a private
+placement a total of $100.0 million of our 5.75% convertible notes due 2022 with
+a 0.5% contingent interest provision. Interest payments are due on March 15 and
+September 15 of every year. We received net proceeds of $96.8 million after
+deducting the initial purchasers' discount and offering expenses payable by us.
+The convertible notes are general unsecured obligations and rank on a parity in
+right of payment with all our existing and future senior indebtedness and other
+general unsecured obligations, and are senior in right of payment with all our
+future subordinated indebtedness. The convertible notes convert into our common
+stock at a conversion price of $26.00 per share, subject to adjustment. See Note
+5 of Part IV, Item 15 of this report for a more detailed discussion of the
+conversion features. The first date that St. Mary may redeem the notes is in
+2007. Our current stock price is in excess of the $26.00 conversion price. We
+used a portion of the net proceeds from the convertible notes to repay our
+credit facility balance and used the remaining net proceeds to fund a portion of
+our 2002 capital expenditures. On October 3, 2003, we executed new interest rate
+swaps on a total notional amount of $50.0 million of the convertible notes which
+we expect will lower interest expense in 2004.
+St. Mary had $14.8 million in cash and cash equivalents and had working
+capital of $3.1 million as of December 31, 2003, compared to $11.2 million in
+cash and cash equivalents and working capital of $2.1 million as of December 31,
+2002.
+Analysis of cash flow changes between 2002 and 2001
+Operating activities. The increase reflects a change between years of
+$29.3 million in other current assets relating to the collection of receivables,
+payment of prepaid items and collection of refundable income taxes. We also had
+a change between years of $5.2 million from increased accounts payable. These
+items increasing cash flow from operations were offset by a decrease in net
+income of $13.1 million and a $7.1 million decrease in the effect of non-cash
+items between the periods.
+Investing activities. Total 2002 capital expenditures for cash,
+including acquisitions of oil and gas properties, increased $13.9 million or 8
+percent to $184.7 million in 2002 compared to $170.8 million in 2001 due to an
+increase in acquisition activity in 2002 offset by our planned decrease in cash
+expended on drilling activities.
+43
+In November 2001 we purchased oil and gas properties from Choctaw II
+Oil & Gas, Ltd. for $40.5 million in cash. We used a portion of our credit
+facility for this acquisition.
+Financing activities. Net cash provided by financing activities
+increased $17.2 million to $46.3 million in 2002 compared to $29.1 million in
+2001. This increase reflects our March 2002 private placement of $100.0 million
+of 5.75% senior convertible notes due 2022. A portion of the net proceeds of
+$96.7 million was used to repay the balance due on our credit facility at that
+time. By year end we had borrowed $14.0 million on our credit facility.
+Capital Expenditure Budget
+We continuously evaluate opportunities in the marketplace for oil and
+gas properties and, accordingly, may be a buyer or a seller of properties at
+various times. We will continue to emphasize smaller niche acquisitions
+utilizing our technical expertise, financial flexibility and structuring
+experience. In addition, we are also actively seeking larger acquisitions of
+assets or companies that would afford opportunities to expand our existing core
+areas, to acquire additional geoscientists and/or engineers, or gain a
+significant acreage and production foothold in a new basin.
+Expenditures for exploration and development of oil and gas properties
+and acquisitions are the primary use of our capital resources. We anticipate
+spending approximately $273 million for capital and exploration expenditures in
+2004 with $100 million allocated for acquisitions of producing properties.
+Anticipated ongoing exploration and development expenditures for each of our
+core areas are as follows (in millions):
+o Mid-Continent region $ 59.5
+o Rocky Mountain region 51.7
+o ArkLaTex region 21.6
+o Gulf Coast region 18.4
+o Coal Bed Methane 12.2
+o Permian Basin region 10.0
+--------
+$ 173.4
+========
+We regularly review our capital expenditure budget to reflect changes
+in current and projected cash flow, acquisition opportunities, debt requirements
+and other factors. The above allocations are subject to change based on various
+factors and results.
+44
+The following table sets forth certain information regarding the costs
+incurred by us in our oil and gas activities and the amounts we budgeted for
+those activities during the periods indicated.
+Years Ended December 31,
+----------------------------------------------------
+2003 2002 2001
+--------------- --------------- ---------------
+(In thousands)
+Development costs $ 111,908 $ 74,376 $ 98,617
+Exploration costs 34,631 22,778 24,506
+Acquisitions:
+Proved 77,398 87,706 41,188
+Unproved 7,480 8,128 18,552
+--------------- --------------- ---------------
+Total before asset retirement obligation $ 231,417 $ 192,988 $ 182,863
+=============== =============== ===============
+Total including asset retirement Obligation $ 236,949 $ 192,988 $ 182,863
+=============== =============== ===============
+Original Budgeted Amount $ 225,000 $ 164,000 $ 155,000
+=============== =============== ===============
+Long-term debt outstanding on
+revolving credit facility $ 11,000 $ 14,000 $ 64,000
+=============== =============== ===============
+Excluding asset retirement obligation amounts, our costs incurred for
+capital and exploration activities in 2003 increased $38.4 million or 20 percent
+compared to 2002. We spent $154.0 million in 2003 for unproved property
+acquisitions and exploration and development costs compared to $105.3 million in
+2002. This increase was a result of a planned $29.7 million increase in the
+drilling activity budget and an additional $19.0 million spent on opportunities
+that arose during 2003. We reallocated $12.6 million from the acquisitions
+budget for these opportunities.
+In December 2003 we decided to proceed with the development of coalbed
+methane reserves in our Hanging Woman Basin project. We have 139,000 net lease
+acres in the basin and plan to concentrate our initial development on 65,000 net
+acres located in Wyoming. Outstanding legal challenges filed by environmental
+public interest groups affect 47,000 net acres in Montana relating to this
+project. See Legal Proceedings under Part I, Item 3 of this report.
+In 2002 we used a portion of the proceeds from our convertible debt
+offering to fund our capital expenditures budget, but historically we have used
+internally generated cash flow, existing cash and our bank credit facility. We
+believe that internally generated cash flow and our credit facility will be
+utilized in 2004. The amount and allocation of future capital and exploration
+expenditures will depend upon a number of factors including the number and size
+of available acquisition opportunities, whether we can make an economic
+acquisition and our ability to assimilate acquisitions we are considering. Also,
+the impact of oil and gas prices on investment opportunities, the availability
+of capital and borrowing capability and the success of our development and
+exploratory activity could lead to funding requirements for further development.
+The budgeted amounts and the long-term debt amounts in the table above indicate
+the flexibility we have to respond to investment opportunities.
+Financing alternatives
+In 2003 and continuing into 2004 we are seeing the debt and equity
+financing capital markets open up to energy companies who operate in the
+exploration and production segment. This is a result of relatively strong
+commodity prices and the general strength reflected in the balance sheets of the
+45
+companies in this segment. We are not currently considering accessing the
+capital markets in 2004. However, if additional development or attractive
+acquisition opportunities arise that exceed our current available resources, we
+may consider other forms of financing, including the public offering or private
+placement of equity or debt securities. To maintain our financial flexibility we
+are likely to begin negotiations on a new credit facility later in the year.
+Sensitivity analysis
+The next table reflects our estimate of the effect on cash flow from
+operations for the years presented of a 10 percent change in our average
+realized sales price for natural gas, for oil and in total. These amounts have
+been reduced by the effective income tax rate applicable to each period since a
+reduction in revenue would reduce cash requirements to pay income taxes. General
+and administrative expenses have not been adjusted. To fund the capital and
+exploration expenditures we incurred in those years we would have been required
+to access our credit facility as a source of funds. In each of these years we
+had sufficient borrowing base available under our credit facility to meet this
+contingency without reducing or eliminating expenditures and affecting our
+growth strategy. Taking into account the February 20, 2004 loan balance of our
+credit facility we believe we have sufficient borrowing base available to
+continue our growth strategy if prices should change.
+Pro Forma effect on revenues of a 10
+percent change in average sales price:
+---------------------------------------
+As of and for the Years Ended December 31,
+-----------------------------------------------------
+2003 2002 2001
+-------------- ---------------- ---------------
+(In thousands)
+Natural Gas $ 13,889 $ 6,944 $ 8,982
+Oil $ 6,979 $ 4,350 $ 3,476
+-------------- ---------------- ---------------
+Total $ 20,868 $ 11,294 $ 12,458
+============== ================ ===============
+Summary of oil and gas production hedges in place
+Our net realized oil and gas prices are impacted by hedges we have
+placed on future forecasted transactions. We have historically entered into
+hedges of existing production around the time we make acquisitions of producing
+oil and gas properties. Our intent is to lock-in a significant portion of an
+equivalent amount of production to the prices we used to elevate the economics
+of our acquisition. The percentage of our production that is hedged currently is
+a direct result of the timing of our acquisitions from Burlington and Flying J.
+Aside from the major acquisitions our discretionary hedging activity has been
+limited.
+46
+The table below describes the volumes and average contract prices of
+hedges we have in place. All of our oil and gas derivatives are swap agreements.
+These hedges tend to make our earnings less sensitive to movements in commodity
+price and were factored in the analysis of sensitivity above.
+Gas (per MMBtu) Oil (per Bbl)
+--------------- -------------
+Contract Weighted Average Weighted Average
+Month Volumes Contract Price Volumes Contract Price
+----- ------- -------------- ------- --------------
+2004
+January 1,544,500 $ 4.61 157,500 $ 23.71
+February 1,298,300 4.56 153,500 23.71
+March 1,293,000 4.57 174,800 24.48
+April 738,900 3.72 178,000 24.66
+May 731,600 3.72 174,800 24.67
+June 725,500 3.73 173,000 24.67
+July 722,700 3.73 172,500 24.65
+August 716,600 3.74 170,900 24.65
+September 712,400 3.74 169,300 24.64
+October 710,300 3.74 167,700 24.64
+November 620,000 3.83 165,200 24.64
+December 617,000 3.83 163,100 24.64
+----------------- ------------------- --------------- -------------------
+Total 2004 10,430,800 4.08 2,020,300 24.49
+----------------- ------------------- --------------- -------------------
+2005
+January - - 27,000 29.20
+February - - 27,000 29.20
+March - - 5,900 29.20
+----------------- ------------------- --------------- -------------------
+Total 2005 - - 59,900 29.20
+----------------- ------------------- --------------- -------------------
+All Contracts 10,430,800 $ 4.08 2,080,200 $ 24.63
+================= =================== =============== ===================
+We anticipate that all hedge transactions will occur as expected.
+For contracts in place on December 31, 2003, a hypothetical change of
+10 percent in future gas strip prices representing a $0.52 increase per MMBtu
+applied to a notional amount of 10.4 million MMBtu covered by natural gas swaps
+would cause a change in hedge gain or loss included in gas revenue of $5.5
+million in 2004. A hypothetical change of 10 percent in the future NYMEX strip
+oil prices representing a $3.01 increase per Bbl applied to a notional amount of
+2.1 MMBbl covered by crude oil swaps would cause a change in hedge gain or loss
+included in oil revenue of $6.1 million in 2004 and $168,000 in 2005.
+Summary of interest rate hedges in place
+We entered into fixed-rate to floating-rate interest rate swaps on
+$50.0 million of convertible notes on October 3, 2003. As we do not believe we
+have the ability to predict interest rates, we attempt to maintain a balanced
+allocation between fixed and floating rate debt. As our usage of the credit
+facility was nearing zero we elected to exchange fixed rate payments for
+floating rate payments on a portion of the interest on our convertible notes.
+This hedge does not qualify for fair value hedge treatment under Statement of
+Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
+and Hedging Activities."
+47
+Excluding accrued payments due to us at December 31, 2003, the interest rate
+swaps had a fair value liability of $104,000. Unless we access our credit
+facility to make an acquisition or interest rates increase dramatically,
+interest expense next year should decrease due to these fixed to floating
+interest rate swaps.
+Schedule of contractual obligations
+The following table summarizes our future estimated principal payments
+and minimum lease payments for the periods specified (in millions):
+Less than More than 5
+Contractual Obligations Total 1 year 1-3 years 3-5 years years
+---------------------------------- ----------- ----------- ----------- ----------- -------------
+Long-Term Debt $ 111.0 $ - $ 11.0 $ 100.0 $ -
+Operating Leases 10.5 2.2 3.0 2.2 3.1
+Other Long-Term Liabilities 8.9 1.0 1.1 0.2 6.6
+----------- ----------- ----------- ----------- -------------
+Total $ 130.4 $ 3.2 $ 15.1 $ 102.4 $ 9.7
+=========== =========== =========== =========== =============
+This table includes our 2004 estimated pension liability payment of
+approximately $987,000, but excludes the remaining unfunded portion of $1.4
+million, as we cannot determine with accuracy the timing of future payments. We
+have not included asset retirement obligations for the same reason. Pension
+liabilities and asset retirement obligations are discussed in Note 8 and Note 9,
+respectively, of Part IV, Item 15 of this report.
+In the next year we have one office space lease that will expire. A
+second lease for office space will expire in year 3, and a third office space
+lease will expire in year 4. Estimated costs to replace these leases are not
+included in the table above. For purposes of the table we assume that the
+holders of our convertible notes will not exercise the conversion feature. If
+the holders do exercise their conversion feature, we will not have to repay the
+$100.0 million. However, our common shares outstanding would increase by
+3,846,150 shares.
+Our projected requirements for cash to pay interest, dividends and
+income taxes in 2004 are $7.9 million, $3.2 million, and $29.5 million,
+respectively.
+Off-Balance Sheet Arrangements
+Aside from operating leases we do not have any off-balance sheet
+financing nor do we have any unconsolidated subsidiaries.
+Critical Accounting Policies and Estimates
+We are engaged in the exploration, development, acquisition and
+production of natural gas and crude oil. Our discussion of financial condition
+and results of operation is based upon the information reported in our
+consolidated financial statements. The preparation of these consolidated
+financial statements requires us to make assumptions and estimates that affect
+the reported amounts of assets, liabilities, revenues and expenses as well as
+the disclosure of contingent assets and liabilities at the date of our financial
+statements. We base our decisions affecting the estimates we use on historical
+experience and various other sources that are believed to be reasonable under
+the circumstances. Actual results may differ from the estimates we calculated
+due to changing business conditions or unexpected circumstances. Policies we
+believe are critical to understanding our business operations and results of
+operations are detailed below. For additional information on our significant
+48
+accounting policies you should see Note 1 - Summary of Significant Accounting
+Policies and Note 11 - Disclosures About Oil and Gas Producing Activities in
+Part IV, Item 15 of this report.
+Oil and gas reserve quantities. Estimated reserve quantities and the
+related estimates of future net cash flows are the most important estimate an
+exploration and production company has because they affect the perceived value
+of our company and are used in significant accounting estimates including the
+periodic calculations of depletion, depreciation and impairment for our proved
+oil and gas properties. Proved oil and gas reserves are the estimated quantities
+of crude oil, natural gas and natural gas liquids which geological and
+engineering data demonstrate with reasonable certainty to be recoverable in
+future periods from known reservoirs under existing economic and operating
+conditions. Future cash inflows and future production and development costs are
+determined by applying benchmark prices and costs, including transportation,
+quality and basis differentials, in effect at the end of each period to the
+estimated quantities of oil and gas remaining to be produced at the end of that
+period. Expected cash flows are reduced to present value using a discount rate
+that depends upon the purpose for which the reserve estimates will be used. For
+example, the standardized measure calculation required by SFAS No. 69,
+"Disclosures about Oil and Gas Producing Activities," requires a 10 percent
+discount to be applied. Although reserve estimates are inherently imprecise, and
+estimates of new discoveries and undeveloped locations are more imprecise than
+those of established proved producing oil and gas properties, we make
+considerable effort to estimate our reserves. We expect that periodic reserve
+estimates will change in the future as additional information becomes available
+or as oil and gas prices and operating and capital costs change. Changes in
+depletion, depreciation or impairment calculations caused by changes in reserve
+quantities or net cash flows are recorded in the period that the reserve
+estimates changed.
+The following table reflects the estimated MMCFE change and percentage
+change to our reported reserve volumes from the described hypothetical changes:
+Years Ended December 31,
+--------------------------------------------------------------------------------
+2003 2002 2001
+------------------------ ----------------------- -------------------------
+MMCFE Percent MMCFE Percent MMCFE Percent
+Change Change Change Change Change Change
+----------- --------- ---------- --------- ----------- ----------
+A 10% decrease in Pricing 9,479 2% 8,700 2% 22,629 6%
+=========== ========== ===========
+A 10% decrease in Proven
+Undeveloped Reserves 6,744 1% 6,043 1% 5,353 1%
+=========== ========== ===========
+Successful efforts method of accounting. Generally accepted accounting
+principles provide for two alternative methods for the oil and gas industry to
+use in accounting for oil and gas producing activities. These two methods are
+generally known in our industry as the full cost method and the successful
+efforts method. Both methods are widely used. The methods are different enough
+that in many circumstances the same set of facts will provide materially
+different financial statement results within a given year. We have chosen the
+successful efforts method of accounting for our oil and gas producing activities
+and a detailed description is included in Note 1 of Part IV, Item 15 of this
+report.
+Revenue recognition. Our revenue recognition policy is significant
+because revenue is a key component of our results of operations and our
+forward-looking statements contained in our analyses of liquidity and capital
+resources. We derive our revenue primarily from the sale of produced natural gas
+and crude oil. Revenue is recorded in the month our production is delivered to
+the purchaser, but payment is generally received between 30 and 90 days after
+the date of production. At the end of each month we make estimates of the amount
+of production delivered to the purchaser and the price we will receive. We use
+our knowledge of our properties; their historical performance; the anticipated
+effect of weather conditions during the month of production; NYMEX and local
+spot market prices; and other factors as the basis for these estimates.
+49
+Variances between our estimates and the actual amounts received are recorded in
+the month payment is received. A 10 percent change in our year-end revenue
+accrual would have impacted net income before tax by $5.9 million in 2003, $3.7
+million in 2002 and $3.3 million in 2001.
+Crude oil and natural gas hedging. Our crude oil and natural gas
+hedging contracts will usually qualify for cash flow deferral hedge accounting
+under SFAS No. 133. This policy is significant because it affects the timing of
+revenue recognition in our statements of operations and is discussed prominently
+in our forward looking statements contained in our discussions of liquidity and
+capital resources. Under this accounting pronouncement a majority of the gain or
+loss from a contract qualifying as a cash flow hedge is deferred as to statement
+of operations recognition. The position reflected in the statement of operations
+is based on the actual settlements with the counterparty. We include this gain
+or loss in oil and gas production revenues. If our natural gas and crude oil
+hedge contracts did not qualify for hedge accounting treatment or we chose not
+to use this hedge accounting methodology, our periodic statements of operations
+could include significant changes in the estimate of non-cash derivative gain or
+loss due to swings in the value of these contracts. Consequently we would report
+a different amount for oil and gas production revenues in our statement of
+operations. These fluctuations could be especially significant in a volatile
+pricing environment such as we have encountered over the last three years. Net
+income after tax would have increased or (decreased) for 2003, 2002 and 2001 by
+the following amounts: $(14.3 million), $(6.3 million), and $6.9 million,
+respectively.
+Asset retirement obligations. Under SFAS No. 143, "Accounting for Asset
+Retirement Obligations," we are required to recognize an estimated liability for
+future costs associated with the abandonment of our oil and gas properties. We
+base our estimate of the liability on our historical experience in abandoning
+oil and gas wells projected into the future based on our current understanding
+of federal and state regulatory requirements. Our projections require us to
+estimate economic lives of our properties, future inflation rates applied to
+external estimates as well as a credit adjusted risk-free rate to use in present
+value calculations. The statement of operations impact of this calculation is
+reflected in our depreciation, depletion and amortization calculations and
+occurs over the remaining life of our oil and gas properties.
+Valuation of long-lived and intangible assets. Our property and
+equipment is recorded at cost. An impairment allowance is provided on unproved
+property when we determine that the property will not be developed. We evaluate
+the realizability of our proved producing and other long-lived assets whenever
+events or changes in circumstances indicate that an impairment may have
+occurred. Our impairment test compares the expected undiscounted future net
+revenues from a property, using escalated pricing with the related net
+capitalized costs of the property at the end of each period. When the net
+capitalized costs exceed the undiscounted future net revenue of a property, the
+cost of the property is written down to our estimate of fair value, which is
+determined by applying a 15 percent discount rate to future net revenues. Our
+criteria for an acceptable internal rate of return are subject to change over
+time. Different pricing assumptions or discount rates could result in a
+different calculated impairment
+Income taxes. We provide for deferred income taxes on the difference
+between the tax basis of an asset or liability and its carrying amount in our
+financial statements in accordance with SFAS No. 109, "Accounting for Income
+Taxes." This difference will result in taxable income or deductions in future
+years when the reported amount of the asset or liability is recovered or
+settled, respectively. Considerable judgment is required in determining when
+these events may occur and whether recovery of an asset is more likely than not.
+Additionally, our federal and state income tax returns are generally not filed
+before the consolidated financial statements are
+50
+prepared, therefore we estimate the tax basis of our assets and liabilities at
+the end of each period as well as the effects of tax rate changes, tax credits
+and net operating and capital loss carryforwards. Adjustments related to
+differences between the estimates we used and actual amounts we reported are
+recorded in the period in which we file our income tax returns. These
+adjustments and changes in our estimates of asset recovery could have an
+impact on our results of operations. A 1.0 percent change in our effective tax
+rate would have affected our calculated income tax expense by $1.5 million,
+$426,000 and $623,000 for the years ended December 31, 2003, 2002 and 2001,
+respectively.
+Stock options. In December 2002 the FASB issued SFAS No. 148,
+"Accounting for Stock-Based Compensation -- Transition and Disclosure: an
+amendment of FASB Statement No. 123." This statement amends SFAS No. 123,
+"Accounting for Stock-Based Compensation", to provide alternative methods of
+transition for a voluntary change to the fair value based method of accounting
+for stock-based employee compensation. We account for stock-based compensation
+using the intrinsic value recognition and measurement principles detailed in
+Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
+Employees." No stock-based employee compensation expense has been reflected in
+our net income as all options granted under our plans had an exercise price
+equal to the market value of the underlying common stock on the date of grant.
+We currently use the Black-Scholes option valuation model to calculate required
+disclosures under SFAS No. 123. This model requires us to make estimates
+regarding the risk free interest rate, our dividend yield, the volatility of our
+stock price, and the expected life of the options. A change in any one of these
+estimates can have a material impact on the amount of calculated compensation
+expense. See Notes 1 and 7 of Part IV, Item 15 of this report for additional
+details.
+51
+Additional Comparative Data in Tabular Format:
+Change Between Years
+----------------------------------------
+Oil and Gas Production Revenues 2003 and 2002 2002 and 2001
+------------------ ------------------
+Increase (decrease) in oil and gas production
+revenues (in thousands) $ 179,444 $ (18,303)
+================== ==================
+Components of Revenue Increases (Decreases):
+Natural Gas
+-----------
+Price change per Mcf $ 1.89 $ (0.73)
+Price percentage change 63% (20)%
+Production change (MMcf) 11,499 (1,327)
+Production percentage change 30% (3)%
+Oil
+---
+Price change per Bbl $ 1.62 $ 2.05
+Price percentage change 6% 9%
+Production change (MBbl) 1,726 381
+Production percentage change 61% 16%
+Our product mix as a percentage of total oil and gas revenue and production:
+Revenue 2003 2002 2001
+------- -------------- -------------- -------------
+Natural Gas 66% 62% 72%
+Oil 34% 38% 28%
+Production
+Natural Gas 65% 69% 73%
+Oil 35% 31% 27%
+Information regarding the effects of oil and gas hedging activity:
+Natural Gas Hedging 2003 2002 2001
+------------------- ------------------ ------------------ ------------------
+Percentage of gas production hedged 40% 45% 41%
+Natural gas MMBtu hedged 21.7 million 18.9 million 17.6 million
+Decrease in gas revenue ($11.4 million) ($4.1 million) ($19.2 million)
+Average realized gas price per Mcf before hedging $ 5.12 $ 3.10 $ 4.22
+Oil Hedging 2003 2002 2001
+----------- ------------------ ------------------ ------------------
+Percentage of oil production hedged 54% 54% 35%
+Oil volumes hedged (MBbl) 2,474 1,518 841
+Increase (decrease) in oil revenue ($11.1 million) $1.9 million ($1.9 million)
+Average realized gas price per Bbl before hedging $ 29.40 $ 24.69 $ 24.08
+Information regarding the components of exploration expense:
+Summary of Exploration Expense (In millions) 2003 2002 2001
+--------------------------------------------- ------------------ ------------------ ------------------
+Geological and geophysical expenses $ 5.1 $ 3.5 $ 4.6
+Exploratory dry holes 8.5 7.7 9.0
+Overhead and other expenses 13.1 8.3 5.9
+------------------ ------------------ ------------------
+$ 26.7 $ 19.5 $ 19.5
+================== ================== ==================
+52
+Comparison of Financial Results and Trends between 2003 and 2002
+Oil and Gas Production Revenues. Average net daily production increased
+40 percent to 210.7 MMCFE for 2003 compared with 150.8 MMCFE in 2002. Included
+in our 2003 production volumes are 13.8 MMCFE from the Burlington and Flying J
+acquisitions. Wells completed in 2002 and 2003 and properties acquired in 2002
+and during 2003 have added revenue of $135.3 million and average net daily
+production of 71.0 MMCFE in 2003 compared to 2002.
+The hedging activity table reflects increased hedging of oil production
+as a result of our Burlington and Flying J acquisitions.
+Gain (loss) on sale of proved properties. In 2003 we closed the sale of
+certain Texas, Wyoming and other properties and recognized net gains of $8.8
+million.
+Oil and Gas Production Expenses. Total production costs increased $37.7
+million to $88.5 million for 2003, from $50.8 million in 2002. Our acquisition
+of properties from Burlington and Flying J added $24.9 million of incremental
+production costs, and wells completed in 2002 and 2003 added $7.9 million of
+incremental production costs in 2003 that were not reflected in 2002.
+Additionally, we experienced an increase in production taxes consistent with the
+increase in revenue from higher realized prices.
+Total oil and gas production costs per MCFE increased $0.23 to $1.15
+for 2003, compared with $0.92 for 2002. This increase is comprised of the
+following:
+o A $0.09 increase in production taxes due to higher realized per MCFE
+prices;
+o A $0.03 increase due to rising transportation costs in our Rockies
+and Mid-Continent regions;
+o A $0.03 increase in LOE relating to workover charges for projects in
+our Gulf Coast, Rocky Mountain and ArkLaTex regions;
+o A $0.14 increase in LOE that reflects our additions of higher cost
+oil properties in our; Rocky Mountain region through our
+acquisitions from Burlington and Flying J; and
+o A $0.06 decrease reflecting general decreases in LOE per MCFE in our
+other core areas.
+Exploration. Exploration expense increased 37 percent in 2003. The most
+significant component of our increase to exploration expense was $4.8 million
+for increased exploration overhead due to increases in our geologic and
+exploration staff as a result of the acreage we have acquired in the Williston,
+Green River, Wind River and Powder River basins and due to increases in our
+exploration-related incentive compensation.
+General and Administrative. General and administrative expenses
+increased $10.9 million or 76 percent to $25.2 million for 2003, compared with
+$14.3 million in 2002. Approximately $5.3 million of the 2003 expense is
+non-cash and relates to the mark-to-market effect of our net profits interest
+bonus plan. The increase in cost on a per MCFE basis reflects a higher
+percentage increase in G&A, primarily due to an increase in our compensation
+expense, than the proportionate increase in production of 40 percent for the
+period.
+An increase in our employee count from 185 to 226 has resulted in a
+general increase in G&A of $5.4 million between 2003 and 2002. That increase
+plus a $12.4 million increase in expense associated with our incentive
+compensation plans, a $1.0 million increase in accrued charitable contributions
+expense and a $539,000 increase in insurance and corporate governance costs were
+53
+offset by an $8.3 million increase in COPAS overhead reimbursement from
+operations and G&A we allocated to exploration expense. COPAS overhead
+reimbursement from operations has increased by $3.5 million due to an increase
+of 413 in the number of properties we operate in our Rocky Mountain region as a
+result of our Burlington and Flying J acquisitions. During 2003 we sold 74 of
+these properties. The increase in expense associated with our incentive
+compensation plans reflects both the benefit we have received from the current
+price environment for past employee performance and the performance of our
+employees during the current year.
+Interest Expense. Interest expense increased by $4.1 million to $8.0
+million for 2003 compared to $3.9 million for 2002. The increase reflects a full
+year of accrued interest in 2003 on our 5.75% convertible notes that were issued
+in March 2002, the benefit of an interest rate swap that reduced interest
+expense in 2002 by $839,000, the 0.5% contingent interest provision which
+applied in all of 2003 but for only 15 days during the comparable period in
+2002, and increased borrowings under our credit facility in 2003 relative to the
+prior year.
+Income Taxes. Income tax expense totaled $55.9 million for 2003 and
+$15.0 million in 2002, resulting in effective tax rates of 38.3 percent and 35.3
+percent, respectively. The effective rate change from 2002 reflects an increase
+in our highest marginal federal tax rate, the expiration of the Section 29 tax
+credit, adjustments to valuation allowances to reflect the likelihood that prior
+Alternative Minimum Tax credits created by Section 29 credits will not be used,
+changes in the composition of the highest marginal state tax rates as a result
+of our recent acquisitions and the 2002 adjustment to valuation allowances
+against state income taxes from net operating loss carryovers.
+The current portion of the income tax expense in 2003 is $32.2 million
+compared to $569,000 in 2002. These amounts are 58 percent and 4 percent of the
+total tax for the respective periods. The difference results from increased
+taxable income caused by significantly higher oil and gas prices and production,
+and a reduction in the percentage of deductible intangible drilling costs
+relative to total income. We have increased our budget for drilling expenditures
+and revenues are projected for a slight increase in 2004. Therefore, we believe
+that current taxable income will be lower and that the current portion of income
+tax as a percentage of total income tax will decrease.
+Cumulative effect of change in accounting principal, net of income tax.
+On January 1, 2003 we adopted SFAS No. 143. The impact of adoption resulted in
+income to us of $8.8 million offset by the deferred income tax effect of $3.4
+million. See Note 9 of the Notes to Consolidated Financial Statements under Part
+IV, Item 15 of this report.
+Comparison of Financial Results and Trends between 2002 and 2001
+Oil and Gas Production Revenues. Average net daily production increased
+to 150.8 MMCFE in 2002 compared to 148.2 MMCFE in 2001. Our November 2001
+acquisition from Choctaw II Oil & Gas, Ltd. added $13.7 million of revenue
+and average daily production of 11.2 MMCFE in 2002. Wells completed in 2002 and
+our acquisitions added average net daily production of 19.7 MMCFE. These
+increases offset declines in average daily production from older properties that
+include an average 5.8 MMCFE/day decline from the Judge Digby field.
+Gain (loss) on sale of proved properties. In December 2002 we closed
+the sale of certain Texas properties and recognized a $2.6 million net loss.
+Oil and Gas Production Expenses. Total production expenses decreased
+$4.2 million, or 8 percent in 2002 to $50.8 million compared with $55.0 million
+in 2001. In the second quarter of 2002 our Gulf Coast region experienced a $2.7
+54
+million decrease in LOE that was comprised of a decrease in workover expense and
+an adjustment due to the issuance of a revised Authorization for Expenditure by
+the operator at Judge Digby. This revised AFE indicated that workover LOE we
+previously expensed under the original AFE should have been capitalized and
+recorded as property, plant and equipment. Our total workover expense decreased
+$5.1 million from 2001 to 2002. Other decreases in LOE attributable to our
+efforts to reduce LOE in total and on a per MCFE basis were offset by $7.3
+million of LOE incurred on properties acquired since November 2001, wells
+completed in 2002 and the $863,000 increase in transportation costs. The
+$991,000 decrease in production taxes reflects the decrease in revenue discussed
+above.
+Total oil and gas production costs per MCFE decreased 10 percent to
+$0.92 for 2002 compared with $1.02 in 2001. This decrease is comprised of the
+following:
+o A $0.03 decrease in production taxes due to lower realized per MCFE
+prices;
+o A $0.09 decrease in LOE, net of general inflation increases, due to
+our efforts to decrease LOE in total and on a per MCFE basis;
+o A $0.10 decrease in LOE attributable to the decrease in total
+workover expense in excess of general cost inflation increases;
+o A $0.03 increase in LOE and transportation costs attributable to
+property acquisitions and 2002 well additions outside of the
+Williston Basin; and
+o A $0.09 increase in LOE and transportation costs attributable to
+increased activity in the higher cost Williston Basin.
+General and Administrative. General and administrative expenses
+increased $2.5 million or 22 percent to $14.3 million in 2002 compared to $11.8
+million in 2001. On a per MCFE basis these costs increased 18 percent to $0.26
+in 2002 from $0.22 in 2001. We experienced an increase in non-compensation
+general expenses of $1.0 million due primarily to increased personnel and
+general cost inflation. This amount plus a $3.7 million increase in compensation
+expense associated with increased personnel and our incentive plans were
+partially offset by a $2.2 million increase in COPAS overhead reimbursement from
+operations and costs allocated to exploration expense.
+Interest Expense. Interest expense increased to $3.9 million in 2002.
+This amount reflects accrued interest on our convertible notes. The amount we
+accrued and paid in 2002 was affected by a fixed-rate to floating-rate interest
+rate swap we entered into in March 2002 and closed at a net gain in December
+2002. Without this swap, interest expense for the period ending December 31,
+2002, would have been $4.6 million.
+Income Taxes. Income tax expense totaled $15.0 million in 2002
+resulting in an effective tax rate of 35.3 percent compared to $21.8 million in
+2001 at an effective tax rate of 35.0 percent. The effective rate change from
+2001 reflects increased accrued state income taxes from marginal rate
+adjustments offset by adjustments to valuation allowances against state net
+operating loss carryovers. We adjusted the valuation allowance after we
+considered a number of factors, including our prior utilization of net operating
+losses and carryovers, tax planning strategies for utilizing both federal and
+state net operating loss and capital loss carryovers and projections of future
+taxable income. We also took into account the reversal of prior temporary timing
+differences and the effect that recent acquisitions will have on anticipated
+expenditures for intangible drilling costs. Based on the weight of positive and
+negative evidence regarding the recoverability of our net deferred tax assets,
+we concluded that only a partial valuation allowance was required.
+55
+Other Liquidity and Capital Resource Information
+Common Stock Activity
+On January 29, 2003, we financed the acquisition of oil and gas
+properties by issuing a total of 3,380,818 restricted shares of our common stock
+to Flying J Oil & Gas Inc. and Big West Oil & Gas Inc. In addition, we
+made a non-recourse loan to Flying J and Big West in the amount of $71.6 million
+at LIBOR plus 2 percent for up to a 39-month period. We also entered into a put
+and call option agreement with Flying J whereby during the 39-month loan period
+Flying J could elect to put these shares to us for $71.6 million plus accrued
+interest on the loan during the first thirty months of the loan period, and we
+could elect to call the shares for $97.4 million, with the proceeds from the
+exercise of either the put option or the call option to be applied to the
+repayment of the loan. For financial reporting purposes the above arrangements
+have been treated as an acquisition of properties in exchange for $71.6 million
+of cash plus the net option to Flying J valued at $1.0 million, resulting in a
+total valuation of $72.6 million. Operating results from the acquired properties
+have been included in the consolidated statements of operations only from the
+date of closing. See Note 3 of Part IV, Item 15 of this report. See the overview
+to liquidity and capital resources for a description of the repurchase of these
+shares.
+Pension Benefits
+Substantially all of our employees who meet age and service
+requirements participate in a non-contributory defined benefit pension plan. At
+December 31, 2003, we have recorded a $914,000 pre-tax loss in accumulated other
+comprehensive income related to this plan. We believe this obligation will be
+funded from future cash flow from operating activities. For purposes of
+calculating our obligation under the plan, we have used an expected return on
+plan assets of 8 percent. We think this rate of return is appropriate over the
+long-term given the 60 percent equity and 40 percent debt securities mix of
+investment for plan assets and the historical rate of return provided by equity
+and debt securities since the 1920s. Our estimated rate of return for 2003 was
+24.5 percent and was a negative 10.0 percent for 2002. The difference in
+investment income using our projected rate of return compared to our actual
+rates of return for the past two years was not material and will not have a
+material effect on statements of operation or cash flow from operating
+activities in future years.
+For the 2003 plan year, a 0.25 percent decrease in the discount rate
+combined with a 1.25 percent decrease in the rate of future compensation
+increases caused a $43,000 decrease in the projected benefit obligation of the
+plan. We do not believe this change was material and project that it will not
+have a material effect on the results of operations or on cash flow from
+operating activities in future periods.
+We also have a supplemental non-contributory defined benefit pension
+plan that covers certain management employees. There are no plan assets for this
+plan. For the 2003 plan year, a 0.25 percent decrease in the discount rate
+combined with a 0.25 percent decrease in the rate of future compensation
+increases caused a $227,000 increase in the projected benefit obligation for
+this plan. This plan's accumulated benefit obligation was $1.2 million at
+December 31, 2003, and was $853,000 at December 31, 2002. We believe this
+obligation will be funded from future cash flow from operating activities.
+Accounting Matters
+We recognized a $5.4 million gain net of income tax in 2003 from the
+adoption of SFAS No. 143 effective January 1, 2003.
+56
+We refer you to Note 1 of Part IV, Item 15 of this report for a
+detailed discussion regarding the adoption of SFAS No. 141 and SFAS No. 142 and
+the reporting issue that has arisen regarding these statements and for a
+discussion of recently issued accounting standards. We have addressed this issue
+in accordance with the best available information at the time of filing this
+report.
+Environmental
+St. Mary's compliance with applicable environmental regulations has not
+resulted in any significant capital expenditures or materially adverse effects
+to our liquidity or results of operations. We believe we are in substantial
+compliance with environmental regulations and foresee that no material
+expenditures will be incurred in the future. However, we are unable to predict
+the impact that future compliance with regulations may have on future capital
+expenditures, liquidity and results of operations.
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
+The information required by this item is provided under the captions
+"Interest Rate Risk" and "Sensitivity Analysis" in Item 7 above and is
+incorporated herein by reference.
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
+The Consolidated Financial Statements that constitute Item 8 follow the
+text of this report. An index to the Consolidated Financial Statements and
+Schedules appears in Item 15(a) of this report.
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
+AND FINANCIAL DISCLOSURE
+As previously reported in our current reports on Form 8-K filed with
+the SEC on May 30, 2002, and June 5, 2002, we dismissed Arthur Andersen LLP as
+our independent accountants on May 23, 2002, and we engaged Deloitte & Touche
+LLP as our new independent accountants on June 3, 2002. The St. Mary Audit
+Committee and Board of Directors approved this change in accountants.
+ITEM 9A. CONTROLS AND PROCEDURES
+We maintain a system of disclosure controls and procedures that are
+designed for the purposes of ensuring that information required to be disclosed
+in our SEC reports is recorded, processed, summarized and reported within the
+time periods specified in the SEC's rules and forms, and that such information
+is accumulated and communicated to our management, including the Chief Executive
+Officer and the Vice-President - Finance, as appropriate to allow timely
+decisions regarding required disclosure.
+We carried out an evaluation, under the supervision and with the
+participation of our management, including the Chief Executive Officer and the
+Vice-President - Finance, of the effectiveness of the design and operation of
+our disclosure controls and procedures as of the end of the period covered by
+this Annual Report on Form 10-K. Based upon that evaluation, the Chief Executive
+Officer and the Vice-President - Finance concluded that our disclosure controls
+and procedures are effective for the purposes discussed above as of the end of
+the period covered by this Annual Report on Form 10-K. There was no significant
+change in our internal control over financial reporting that occurred during our
+most recent fiscal quarter that has materially affected, or is reasonably likely
+to materially affect, our internal control over financial reporting.
+57
+PART III
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
+The information required by this Item concerning St. Mary's Directors
+is incorporated by reference to the information provided under the captions
+"Election of Directors" and "Nominees for Election of Directors" in St. Mary's
+definitive proxy statement for the 2004 annual meeting of stockholders to be
+filed within 120 days from December 31, 2003. The information required by this
+Item concerning St. Mary's executive officers is incorporated by reference to
+the information provided in Part I--Item 4A--Executive Officers of the
+Registrant, included in this Form 10-K.
+The information required by this Item concerning compliance with
+Section 16(a) of the Securities Exchange Act of 1934 is incorporated by
+reference to the information provided under the caption "Section 16(a)
+Beneficial Ownership Reporting Compliance" in St. Mary's definitive proxy
+statement for the 2004 annual meeting of stockholders to be filed within 120
+days from December 31, 2003.
+ITEM 11. EXECUTIVE COMPENSATION
+The information required by this Item is incorporated by reference to
+the information provided under the captions, "Director Compensation," "Executive
+Compensation," "Report of the Compensation Committee on Executive Compensation,"
+"Retirement Plans," "Performance Graph," and "Employee Agreements and
+Termination of Employment and Change-in-Control Arrangements" in St. Mary's
+definitive proxy statement for the 2004 annual meeting of stockholders to be
+filed within 120 days from December 31, 2003.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
+MANAGEMENT AND RELATED STOCKHOLDER MATTERS
+The information required by this Item concerning security ownership of
+certain beneficial owners and management is incorporated by reference to the
+information provided under the caption "Security Ownership of Certain Beneficial
+Owners and Management" in St. Mary's definitive proxy statement for the 2004
+annual meeting of stockholders to be filed within 120 days from December 31,
+2003.
+The information required by this Item concerning securities authorized
+for issuance under equity compensation plans is incorporated by reference to the
+information provided under the caption "Equity Compensation Plans" in Part II -
+Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters,
+included in this Form 10-K.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+The information required by this Item is incorporated by reference to
+the information provided under the caption "Certain Relationships and Related
+Transactions" in St. Mary's definitive proxy statement for the 2004 annual
+meeting of stockholders to be filed within 120 days from December 31, 2003.
+ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
+The information required by this Item is incorporated by reference to
+the information provided under the caption "Independent Accountants" in St.
+Mary's definitive proxy statement for the 2004 annual meeting of stockholders to
+be filed within 120 days from December 31, 2003.
+58
+PART IV
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
+FORM 8-K
+(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:
+Reports of Independent Auditors.....................................F-1
+Reports of Independent Public Accountants...........................F-2
+Consolidated Balance Sheets.........................................F-3
+Consolidated Statements of Operations...............................F-4
+Consolidated Statements of Stockholders' Equity and
+Comprehensive Income.............................................F-5
+Consolidated Statements of Cash Flows...............................F-6
+Notes to Consolidated Financial Statements..........................F-8
+All other schedules are omitted because the required information is not
+applicable or is not present in amounts sufficient to require submission of the
+schedule or because the information required is included in the Consolidated
+Financial Statements and Notes thereto.
+(b) Reports on Form 8-K.
+St. Mary Land & Exploration Company filed the following current
+reports on Form 8-K during the quarter ended December 31, 2003:
+On October 8, 2003, we filed a current report on Form 8-K reporting
+under Item 12 that we issued a press release providing an update on our
+operations for the third quarter 2003.
+On October 23, 2003, we filed a current report on Form 8-K reporting
+under Item 9 that we issued a press release announcing a regular semi-annual
+cash dividend of five cents per share to be paid on November 17, 2003.
+On November 6, 2003, we filed a current report on Form 8-K reporting
+under Item 12 that we issued a press release announcing the results of
+operations for the quarterly period ended September 30, 2003.
+On November 6, 2003, we filed a current report on Form 8-K/A amending
+the financial highlights attachment filed with the Form 8-K on November 6, 2003.
+On December 5, 2003, we filed a current report on Form 8-K reporting
+under Item 5 that we will proceed with the development of coalbed methane
+reserves in the Hanging Woman Basin and that we sold certain oil and gas
+properties for approximately $22 million with an aggregate gain of approximately
+$7 million.
+59
+(c) Exhibits. The following exhibits are filed with or incorporated by
+reference into this report on Form 10-K:
+Exhibit
+Number Description
+------ -----------
+3.1 Restated Certificate of Incorporation of St. Mary Land &
+Exploration Company as amended in May 2001 (filed as Exhibit 3.1
+to the registrant's Quarterly Report on Form 10-Q for the quarter
+ended September 30, 2001 and incorporated herein by reference)
+3.2 Restated By-Laws of St. Mary Land & Exploration Company as
+amended on March 27, 2003 (filed as Exhibit 3.2 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended March 31, 2003 and incorporated herein by reference)
+4.1 St. Mary Land & Exploration Company Shareholder Rights
+Plan adopted on July 15, 1999 (filed as Exhibit 4.1 to the
+registrant's Quarterly Report on Form 10-Q/A for the quarter
+ended June 30, 1999 and incorporated herein by reference)
+4.2 First Amendment to Shareholders Rights Plan dated March 15,
+2002 as adopted by the Board of Directors on July 19, 2001
+(filed as Exhibit 4.2 to the registrant's Annual Report on
+Form 10-K for the year ended December 31, 2001 and
+incorporated herein by reference)
+10.1 St. Mary Land & Exploration Company Stock Option Plan, As
+Amended on May 22, 2003 (filed as Exhibit 99.1 to the
+registrant's Registration Statement on Form S-8 (Registration
+No. 333-106438) and incorporated herein by reference)
+10.2 St. Mary Land & Exploration Company Incentive Stock Option
+Plan, As Amended on March 25, 1999, January 27, 2000, March
+29, 2001, March 27, 2003 and May 22, 2003 (filed as Exhibit
+99.2 to registrant's Registration Statement on Form S-8
+(Registration No. 333-106438) and incorporated herein by
+reference)
+10.3 Cash Bonus Plan (filed as Exhibit 10.5 to the registrant's
+Registration Statement on Form S-1 (Registration No.
+33-53512) and incorporated herein by reference)
+10.4 Summary Plan Description/Pension Plan dated December 30, 1994
+(filed as Exhibit 10.35 to the registrant's Annual Report on
+Form 10-K for the year ended December 31, 1994 and
+incorporated herein by reference)
+10.5 Non-qualified Unfunded Supplemental Retirement Plan, as
+amended (filed as Exhibit 10.8 to the registrant's
+Registration Statement on Form S-1 (Registration No. 33-53512)
+and incorporated herein by reference)
+10.6 St. Mary Land & Exploration Company Employee Stock
+Purchase Plan (filed as Exhibit 10.48 filed to the
+registrant's Annual Report on Form 10-K (for the year ended
+December 31, 1997 and incorporated herein by reference)
+10.7 First Amendment to St. Mary Land & Exploration Company
+Employee Stock Purchase Plan dated February 27, 2001 (filed as
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
+for the quarter ended June 30, 2001 and incorporated herein by
+reference)
+10.8 Form of Change of Control Severance Agreements (filed as
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
+for the quarter ended September 30, 2001 and incorporated
+herein by reference)
+10.9 Employment Agreement between Registrant and Mark A.
+Hellerstein (filed as Exhibit 10.15 to the registrant's
+Registration Statement on Form S-1 (Registration No. 33-53512)
+and incorporated herein by reference)
+10.10 Registration Rights Agreement between St. Mary Land &
+Exploration Company and Bear, Stearns & Co. Inc., et al dated
+March 13, 2002 (filed as Exhibit 10.25 to the registrant's Annual
+Report on Form 10-K for the year ended December 31, 2001 and
+incorporated herein by reference)
+60
+Exhibit
+Number Description
+------ -----------
+10.11 St. Mary Land & Exploration Company 5.75% Senior Convertible
+Notes Due 2002 Indenture dated March 13, 2002 (filed as
+Exhibit 10.26 to the registrant's Annual Report on Form 10-K
+for the year ended December 31, 2001 and incorporated herein
+by reference)
+10.12 Purchase and Sale Agreement dated October 1, 2002, effective
+as of July 1, 2002, between Burlington Resources Oil & Gas
+Company LP and The Louisiana Land and Exploration Company and
+Nance Petroleum Corporation (filed as Exhibit to the
+registrant's Current Report on Form 8-K filed on December 12,
+2002 and incorporated herein by reference)
+10.13 Purchase and Sale Agreement dated as of December 13, 2002
+among Flying J Oil & Gas Inc., Big West Oil & Gas Inc.,
+NPC Inc. and St. Mary Land & Exploration Company (filed as
+Exhibit 10.1 to the registrant's Current Report on Form 8-K filed
+on February 13, 2003 and incorporated herein by reference)
+10.14 Addendum dated January 29, 2003 to Purchase and Sale Agreement
+dated December 13, 2002 (filed as Exhibit 10.2 to the
+registrant's Current Report on Form 8-K filed on February 13,
+2003 and incorporated herein by reference)
+10.15 Nonrecourse Secured Promissory Note dated January 29, 2003 by
+Flying J Oil & Gas Inc. and Big West Oil & Gas Inc.
+(filed as Exhibit 10.3 to the registrant's Current Report on Form
+8-K filed on February 13, 2003 and incorporated herein by
+reference)
+10.16 Stock Pledge Agreement from Flying J Oil & Gas Inc. and Big
+West Oil & Gas Inc. to St. Mary Land & Exploration
+Company executed as of January 29, 2003 (filed as Exhibit 10.4 to
+the registrant's Current Report on Form 8-K filed on February 13,
+2003 and incorporated herein by reference)
+10.17 Registration Rights Agreement dated as of January 29, 2003 among
+St. Mary Land & Exploration Company, Flying J Oil & Gas
+Inc. and Big West Oil & Gas Inc. (filed as Exhibit 10.5 to
+the registrant's Current Report on Form 8-K filed on February 13,
+2003 and incorporated herein by reference)
+10.18 Put and Call Option Agreement dated as of January 29, 2003 among
+St. Mary Land & Exploration Company, Flying J Oil & Gas
+Inc. and Big West Oil & Gas Inc. (filed as Exhibit 10.6 to
+the registrant's Current Report on Form 8-K filed on February 13,
+2003 and incorporated herein by reference)
+10.19 Standstill Agreement dated as of January 29, 2003 among St. Mary
+Land & Exploration Company, Flying J Oil & Gas Inc. and
+Big West Oil & Gas Inc. (filed as Exhibit 10.7 to the
+registrant's Current Report on Form 8-K filed on February 13,
+2003 and incorporated herein by reference)
+10.20 Share Transfer Restriction Agreement dated as of January 29, 2003
+among St. Mary Land & Exploration Company, Flying J Oil &
+Gas Inc. and Big West Oil & Gas Inc. (filed as Exhibit 10.8
+to the registrant's Current Report on Form 8-K filed on February
+13, 2003 and incorporated herein by reference)
+10.21 Indemnity Guarantee Agreement dated January 29, 2003 between NPC
+Inc. and Flying J Inc. (filed as Exhibit 10.9 to the registrant's
+Current Report on Form 8-K filed on February 13, 2003 and
+incorporated herein by reference)
+10.22 Security Agreement made as of May 1, 2002 by St. Mary Land &
+Exploration Company, St. Mary Operating Company, St. Mary
+Energy Company, Nance Petroleum Corporation, St. Mary Minerals
+Inc., Parish Corporation, Four Winds Marketing LLC, and
+Roswell LLC, in favor of Bank of America, N.A. (filed as
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
+for the quarter ended June 30, 2002 and incorporated herein by
+reference)
+61
+Exhibit
+Number Description
+------ -----------
+10.23 Stock Pledge Agreement made as of May 1, 2002 by St. Mary Land
+& Exploration Company in favor of Bank of America, N.A.
+(filed as Exhibit 10.2 to the registrant's Quarterly Report on
+Form 10-Q for the quarter ended June 30, 2002 and incorporated
+herein by reference)
+10.24 LLC Pledge Agreement made as of May 1, 2002 by St. Mary Land
+& Exploration Company in favor of Bank of America, N.A.
+(filed as Exhibit 10.3 to the registrant's Quarterly Report on
+Form 10-Q for the quarter ended June 30, 2002 and incorporated
+herein by reference)
+10.25 Guaranty made as of May 1, 2002 by St. Mary Operating Company,
+St. Mary Energy Company, Nance Petroleum Corporation, St. Mary
+Minerals, Inc., Parish Corporation, Four Winds Marketing LLC
+and Roswell LLC in favor of Bank of America, N.A. (filed as
+Exhibit 10.4 to the registrant's Quarterly Report on Form 10-Q
+for the quarter ended June 30, 2002 and incorporated herein by
+reference)
+10.26 Credit Agreement dated as of January 27, 2003 among St. Mary
+Land & Exploration Company, Wachovia Bank, National
+Association of Administrative Agent, and the Lenders party
+thereto (filed as Exhibit 10.44 to the registrant's Annual
+Report on Form 10-K for the year ended December 31, 2003 and
+incorporated herein by reference)
+10.27 Amendment to and Extension of Office Lease dated as of
+December 14, 2001 (filed as Exhibit 10.45 to the registrant's
+Annual Report on Form 10-K for the year ended December 31,
+2003 and incorporated herein by reference)
+10.28 St. Mary Land & Exploration Company Non-Employee Director
+Stock Compensation Plan as adopted on March 27, 2003 (filed as
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
+for the quarter ended June 30, 2003 and incorporated herein by
+reference)
+10.29 Guaranty Agreement by St. Mary Energy Company in favor of
+Wachovia Bank, National Association, as Administrative Agent,
+dated January 27, 2003 (filed as Exhibit 10.4 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+10.30 Guaranty Agreement by St. Mary Operating Company in favor of
+Wachovia Bank, National Association, as Administrative Agent,
+dated January 27, 2003 (filed as Exhibit 10.5 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+10.31 Guaranty Agreement by Nance Petroleum Corporation in favor of
+Wachovia Bank, National Association, as Administrative Agent,
+dated January 27, 2003 (filed as Exhibit 10.6 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+10.32 Guaranty Agreement by NPC Inc. in favor of Wachovia Bank,
+National Association, as Administrative Agent, dated January
+27, 2003 (filed as Exhibit 10.7 to the registrant's Quarterly
+Report on Form 10-Q for the quarter ended June 30, 2003 and
+incorporated herein by reference)
+10.33 Pledge and Security Agreement between St. Mary Land &
+Exploration Company and Wachovia Bank, National Association,
+as Administrative Agent, dated January 27, 2003 (filed as
+Exhibit 10.8 to the registrant's Quarterly Report on Form 10-Q
+for the quarter ended June 30, 2003 and incorporated herein by
+reference)
+62
+Exhibit
+Number Description
+------ -----------
+10.34 Pledge and Security Agreement between Nance Petroleum
+Corporation and Wachovia Bank, National Association, as
+Administrative Agent, dated January 27, 2003 (filed as Exhibit
+10.9 to the registrant's Quarterly Report on Form 10-Q for the
+quarter ended June 30, 2003 and incorporated herein by
+reference)
+10.35 First Supplement and Amendment to Deed of Trust, Mortgage,
+Line of Credit Mortgage, Assignment, Security Agreement,
+Fixture Filing and Financing Statement for the benefit of
+Wachovia Bank, National Association, as Administrative Agent,
+dated effective as of January 27, 2003 (filed as Exhibit 10.10
+to the registrant's Quarterly Report on Form 10-Q for the
+quarter ended June 30, 2003 and incorporated herein by
+reference)
+10.36 Deed of Trust - St. Mary Land & Exploration to Wachovia Bank,
+National Association, as Administrative Agent, dated effective
+as of January 27, 2003 (filed as Exhibit 10.11 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+10.37 Deed of Trust (CO, NV, SD) to Wachovia Bank, National
+Association, as Administrative Agent, dated effective as of
+April 2003 (filed as Exhibit 10.12 to the registrant's
+Quarterly Report on Form 10-Q for the quarter ended June 30,
+2003 and incorporated herein by reference)
+10.38 Deed of Trust (LA, MT, ND, NM, OK, TX, UT, WY) to Wachovia
+Bank, National Association, as Administrative Agent, dated
+effective as of April 2003 (filed as Exhibit 10.13 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+10.39 First Supplement and Amendment to Deed of Trust, Mortgage,
+Line of Credit Mortgage, Assignment, Security Agreement,
+Fixture Filing and Financing Statement for the benefit of
+Wachovia Bank, National Association, as Administrative Agent,
+dated effective as of April 2003 (filed as Exhibit 10.14 to
+the registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+10.40 Second Supplement and Amendment to Deed of Trust, Mortgage,
+Line of Credit Mortgage, Assignment, Security Agreement,
+Fixture Filing and Financing Statement for the benefit of
+Wachovia Bank, National Association, as Administrative Agent,
+dated effective as of April 2003 (filed as Exhibit 10.15 to
+the registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+63
+Exhibit
+Number Description
+------ -----------
+10.41* First Amendment to Credit Agreement dated January 27, 2003 among
+St. Mary Land & Exploration Company, Wachovia Bank,
+National Association as Issuing Bank and Administrative Agent,
+and the Lenders party thereto
+10.42* Net Profits Interest Bonus Plan, As Amended on February 3, 2004
+12.1* Computation of Ratios of Earnings to Fixed Charges
+14.1* Code of Business Conduct and Ethics
+16.1 Letter by Arthur Andersen LLP to the Securities and Exchange
+Commission dated May 28, 2002 (filed as Exhibit 16.1 to the
+registrant's Current Report on Form 8-K filed on May 30, 2002
+and incorporated herein by reference)
+21.1* Subsidiaries of Registrant
+23.1* Consent of Deloitte & Touche LLP
+23.2* Information About Lack of Consent of Arthur Andersen LLP
+23.3* Consent of Ryder Scott Company, L.P.
+24.1* Power of Attorney (included in signature page hereof)
+31.1* Certification of Chief Executive Officer pursuant to Section 302
+of the Sarbanes - Oxley Act of 2002
+31.2* Certification of Vice President - Finance pursuant to Section 302
+of the Sarbanes - Oxley Act of 2002
+32.1* Certification pursuant to U.S.C. Section 1350 as adopted pursuant
+to Section 906 of the Sarbanes - Oxley Act of 2002
+------------------------------
+* Filed with this Form 10-K.
+(d) Financial Statement Schedules. See Item 15(a) above.
+64
+INDEPENDENT AUDITORS' REPORT
+To the Board of Directors and Stockholders of
+St. Mary Land & Exploration Company and Subsidiaries
+We have audited the accompanying consolidated balance sheets of St. Mary Land
+& Exploration Company and subsidiaries as of December 31, 2003 and 2002, and
+the related consolidated statements of operations, stockholders' equity and
+comprehensive income, and cash flows for the years then ended. These financial
+statements are the responsibility of the Company's management. Our
+responsibility is to express an opinion on these financial statements based on
+our audits. The Company's consolidated financial statements for the year ended
+December 31, 2001, were audited by other auditors who have ceased operations.
+Those auditors expressed an unqualified opinion on those consolidated financial
+statements in their report dated February 18, 2002, which report included an
+explanatory paragraph for the change in method of accounting for derivative
+instruments and hedging activities on January 1, 2001.
+We conducted our audits in accordance with auditing standards generally accepted
+in the United States of America. Those standards require that we plan and
+perform the audit to obtain reasonable assurance about whether the financial
+statements are free of material misstatement. An audit includes examining, on a
+test basis, evidence supporting the amounts and disclosures in the financial
+statements. An audit also includes assessing the accounting principles used and
+significant estimates made by management, as well as evaluating the overall
+financial statement presentation. We believe that our audits provide a
+reasonable basis for our opinion.
+In our opinion, such consolidated financial statements present fairly, in all
+material respects, the financial position of the Company as of December 31, 2003
+and 2002, and the results of its operations and its cash flows for the years
+then ended in conformity with accounting principles generally accepted in the
+United States of America.
+As discussed in Note 9 to the consolidated financial statements, the Company
+changed its method of accounting for asset retirement obligations in 2003 with
+the implementation of Statement of Financial Standards No. 143 "Accounting for
+Asset Retirement Obligations."
+/s/ DELOITTE & TOUCHE LLP
+Denver, Colorado
+February 26, 2004
+F-1
+REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
+To the Board of Directors and Stockholders of
+St. Mary Land & Exploration Company and Subsidiaries:
+We have audited the accompanying consolidated balance sheets of St. Mary Land
+& Exploration Company (a Delaware corporation) and subsidiaries as of
+December 31, 2001 and 2000, and the related consolidated statements of
+operations, stockholders' equity and comprehensive income, and cash flows for
+each of the three years in the period ended December 31, 2001. These financial
+statements are the responsibility of the Company's management. Our
+responsibility is to express an opinion on these financial statements based on
+our audits.
+We conducted our audits in accordance with auditing standards generally accepted
+in the United States. Those standards require that we plan and perform the audit
+to obtain reasonable assurance about whether the financial statements are free
+of material misstatement. An audit includes examining, on a test basis, evidence
+supporting the amounts and disclosures in the financial statements. An audit
+also includes assessing the accounting principles used and significant estimates
+made by management, as well as evaluating the overall financial statement
+presentation. We believe that our audits provide a reasonable basis for our
+opinion.
+In our opinion, the consolidated financial statements referred to above present
+fairly, in all material respects, the financial position of St. Mary Land &
+Exploration Company and subsidiaries as of December 31, 2001 and 2000, and the
+results of their operations and their cash flows for each of the three years in
+the period ended December 31, 2001, in conformity with accounting principles
+generally accepted in the United States.
+As explained in Notes 1 and 10 to the consolidated financial statements, the
+Company changed its method of accounting for derivative instruments and hedging
+activities on January 1, 2001.
+/s/ ARTHUR ANDERSEN LLP
+Denver, Colorado,
+February 18, 2002.
+NOTE: This Report of Independent Public Accountants dated February 18, 2002 by
+Arthur Andersen LLP is a copy of the report previously issued by Arthur Andersen
+LLP and included with Arthur Andersen LLP's consent in the Annual Report on Form
+10-K for the year ended December 31, 2001 filed with the SEC on March 19, 2002
+and the Annual Report on Form 10-K/A for the year ended December 31, 2001 filed
+with the SEC on March 25, 2002. Such report has not been reissued by Arthur
+Andersen LLP for inclusion with this Annual Report on Form 10-K for the year
+ended December 31, 2002. After reasonable efforts, St. Mary Land &
+Exploration Company has been unable to obtain a reissued report of Arthur
+Andersen LLP for inclusion with this Form 10-K, and in reliance on Rule 2-02(e)
+of Regulation S-X promulgated by the SEC is including a copy of the previously
+issued report with this Form 10-K.
+F-2
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED BALANCE SHEETS
+(In thousands, except share amounts)
+December 31,
+-------------------------------
+ASSETS 2003 2002
+------------- -------------
+Current assets:
+Cash and cash equivalents $ 14,827 $ 11,154
+Short-term investments 12,509 1,933
+Accounts receivable 65,084 35,399
+Prepaid expenses and other 6,020 6,510
+Deferred income taxes 8,872 3,520
+Other 611 1,031
+------------- -------------
+Total current assets 107,923 59,547
+------------- -------------
+Property and equipment (successful efforts method), at cost:
+Proved oil and gas properties 858,246 683,752
+Less - accumulated depletion, depreciation and amortization (312,719) (263,436)
+Unproved oil and gas properties, net of impairment allowance
+of $10,776 in 2003 and $8,865 in 2002 61,484 47,984
+Other property and equipment, net of accumulated depreciation
+of $4,656 in 2003 and $3,586 in 2002 4,276 3,639
+------------- -------------
+611,287 471,939
+------------- -------------
+Noncurrent assets:
+Restricted cash subject to Section 1031 Exchange 10,353 -
+Other noncurrent assets 6,291 5,653
+------------- -------------
+Total noncurrent assets 16,644 5,653
+------------- -------------
+Total Assets $ 735,854 $ 537,139
+============= =============
+LIABILITIES AND STOCKHOLDERS' EQUITY
+Current liabilities:
+Accounts payable and accrued expenses $ 81,217 $ 48,790
+Accrued derivative liability 23,605 8,707
+------------- -------------
+Total current liabilities 104,822 57,497
+------------- -------------
+Noncurrent liabilities:
+Long-term credit facility 11,000 14,000
+Convertible notes 99,696 99,601
+Deferred income taxes 90,947 60,156
+Asset retirement obligation 25,485 -
+Other noncurrent liabilities and minority interest 13,251 6,372
+------------- -------------
+Total noncurrent liabilities 240,379 180,129
+------------- -------------
+Commitments and contingencies (Note 6)
+Temporary equity (Note 3):
+Common stock subject to put and call options, $0.01 par value; issued
+and outstanding - 3,380,818 shares in 2003 and -0- shares in 2002 71,594 -
+Note receivable from Flying J (71,594) -
+------------- -------------
+Total temporary equity - -
+------------- -------------
+Stockholders' equity:
+Common stock, $0.01 par value: authorized - 100,000,000 shares;
+issued - 29,245,123 shares in 2003 and 28,983,110 shares in 2002;
+outstanding, net of treasury shares - 28,242,423 shares in 2003
+and 27,973,210 shares in 2002 292 290
+Additional paid-in capital 146,362 140,688
+Treasury stock - at cost: 1,002,700 shares in 2003 and 1,009,900 shares in 2002 (16,057) (16,210)
+Retained earnings 274,937 182,512
+Accumulated other comprehensive loss (14,881) (7,767)
+------------- -------------
+Total stockholders' equity 390,653 299,513
+------------- -------------
+Total Liabilities and Stockholders' Equity $ 735,854 $ 537,139
+============= =============
+The accompanying notes are an integral part
+of these concolidated financial statements.
+F-3
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED STATEMENTS OF OPERATIONS
+(In thousands, except per share amounts)
+For the Years Ended December 31,
+-------------------------------------------------
+2003 2002 2001
+-------------- -------------- --------------
+Operating revenues:
+Oil and gas production $ 365,114 $ 185,670 $ 203,973
+Gain (loss) on sale of proved properties 7,278 (2,633) 367
+Marketed gas revenue 13,438 8,399 420
+Other oil and gas revenue 3,538 682 2,166
+Derivative gain - 3,188 -
+Other revenues 4,566 1,088 543
+-------------- -------------- --------------
+Total operating revenues 393,934 196,394 207,469
+-------------- -------------- --------------
+Operating expenses:
+Oil and gas production 88,509 50,839 55,000
+Depletion, depreciation, amortization
+and abandonment liability accretion 81,960 54,432 51,346
+Exploration 26,653 19,501 19,518
+Impairment of proved properties 185 - 820
+Abandonment and impairment of unproved properties 3,796 2,446 3,865
+General and administrative 25,179 14,299 11,762
+Derivative loss 310 - 1,573
+Marketed gas system operating expense 12,229 7,982 420
+Minority interest and other 1,802 1,206 1,253
+-------------- -------------- --------------
+Total operating expenses 240,623 150,705 145,557
+-------------- -------------- --------------
+Income from operations 153,311 45,689 61,912
+Interest income 717 758 466
+Interest expense (7,958) (3,868) (90)
+Income before income taxes and cumulative
+effect of change in accounting principle 146,070 42,579 62,288
+Income tax expense (55,930) (15,019) (21,829)
+-------------- -------------- --------------
+Income before cumulative effect of change in accounting principle 90,140 27,560 40,459
+Cumulative effect of change in accounting principal, net of income tax 5,435 - -
+-------------- -------------- --------------
+Net income $ 95,575 $ 27,560 $ 40,459
+============== ============== ==============
+Basic weighted average common shares outstanding 31,233 27,856 27,973
+Diluted weighted average common shares outstanding 35,534 28,391 28,555
+Basic earnings per common share:
+--------------------------------
+Income before cumulative effect
+of change in accounting principle $ 2.89 $ 0.99 $ 1.45
+Cumulative effect of change in accounting principle 0.17 - -
+-------------- -------------- --------------
+Basic net income per common share $ 3.06 $ 0.99 $ 1.45
+============== ============== ==============
+Diluted earnings per common share:
+----------------------------------
+Income before cumulative effect
+of change in accounting principle $ 2.65 $ 0.97 $ 1.42
+Cumulative effect of change in accounting principle 0.15 - -
+-------------- -------------- --------------
+Diluted net income per common share $ 2.80 $ 0.97 $ 1.42
+============== ============== ==============
+Cash dividends declared and paid per common share $ 0.10 $ 0.10 $ 0.10
+============== ============== ==============
+The accompanying notes are an integral part
+of these concolidated financial statements.
+F-4
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
+(In thousands, except share amounts)
+Accumulated
+Additional Other Total
+Common Stock Paid-in Treasury Stock Retained Comprehensive Stockholders'
+--------------------- --------------------
+Shares Amount Capital Shares Amount Earnings Income (Loss) Equity
+------------ --------------------- ---------- --------- ----------- -------------------------
+Balances, December 31, 2000 28,553,826 $ 286 $ 132,973 (395,600) $ (3,339) $ 120,075 $ 141 $ 250,136
+Comprehensive income:
+Net income - - - - - 40,459 - 40,459
+Unrealized net loss on marketable
+equity securities
+available-for-sale - - - - - - (132) (132)
+Adoption of SFAS No. 133 (28,587) (28,587)
+Change in derivative instrument
+fair value - - - - - - 21,102 21,102
+Reclass to earnings - - - - - - 14,392 14,392
+------------
+Total comprehensive income 47,234
+------------
+Cash dividends, $ 0.10 per share - - - - - (2,795) - (2,795)
+Treasury stock purchases - - - (614,300) (12,871) - - (12,871)
+Issuance for Employee Stock Purchase
+Plan 29,772 - 575 - - - - 575
+Sale of common stock, including income
+tax benefit of stock option
+exercises 187,810 2 3,598 - - - - 3,600
+Directors' stock compensation 8,400 - 238 - - - - 238
+------------ --------------------- ---------- --------- ----------- ------------ ------------
+Balances, December 31, 2001 28,779,808 $ 288 $ 137,384 (1,009,900)$(16,210) $ 157,739 $ 6,916 $ 286,117
+------------ --------------------- ---------- --------- ----------- ------------ ------------
+Comprehensive income:
+Net income - - - - - 27,560 - 27,560
+Unrealized net loss on marketable
+equity securities
+available-for-sale - - - - - - (725) (725)
+Change in derivative instrument
+fair value - - - - - - (14,644) (14,644)
+Reclass to earnings - - - - - - 1,447 1,447
+Minimum pension liability adjustment - - - - - - (761) (761)
+------------
+Total comprehensive income 12,877
+------------
+Cash dividends, $ 0.10 per share - - - - - (2,787) - (2,787)
+Issuance for Employee Stock Purchase
+Plan 18,217 - 344 - - - - 344
+ESPP disqualified distribution - - 21 - - - - 21
+Sale of common stock, including income
+tax benefit of stock option
+exercises 177,085 2 2,743 - - - - 2,745
+Accelerated vesing of retiring
+director option - - 52 - - - - 52
+Directors' stock compensation 8,000 - 144 - - - - 144
+------------ --------------------- ---------- --------- ----------- ------------ ------------
+Balances, December 31, 2002 28,983,110 $ 290 $ 140,688 (1,009,900)$(16,210) $ 182,512 $(7,767) $ 299,513
+------------ --------------------- ---------- --------- ----------- ------------ ------------
+Comprehensive income:
+Net income - - - - - 95,575 - 95,575
+Unrealized net gain on marketable
+equity securities
+available-for-sale - - - - - - 716 716
+Change in derivative instrument
+fair value - - - - - - (21,873) (21,873)
+Reclass to earnings - - - - - - 13,846 13,846
+Minimum pension liability adjustment - - - - - - 197 197
+------------
+Total comprehensive income 88,461
+------------
+Cash dividends, $ 0.10 per share - - - - - (3,150) - (3,150)
+Issuance for Employee Stock Purchase
+Plan 16,994 - 375 - - - - 375
+Value of option rights granted to
+Flying J - - 995 - - - - 995
+Sale of common st ck, including income
+tax benefit of stock option
+exercises 245,019 2 4,304 - - - - 4,306
+Directors' stock compensation - - - 7,200 153 - - 153
+------------ --------------------- ---------- --------- ----------- ------------ ------------
+Balances, December 31, 2003 29,245,123 $ 292 $ 146,362 (1,002,700)$(16,057) $ 274,937 $(14,881) $ 390,653
+============ ===================== ========== ========= =========== ============ ============
+The accompanying notes are an integral part
+of these concolidated financial statements.
+F-5
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED STATEMENTS OF CASH FLOWS
+(In thousands)
+For the Years Ended December 31,
+--------------------------------------------
+2003 2002 2001
+--------- --------- ---------
+Reconciliation of net income to net cash provided
+by operating activities:
+Net income $ 95,575 $ 27,560 $ 40,459
+Adjustments to reconcile net income to net
+cash provided by operating activities:
+(Gain) loss on sale of proved properties (7,278) 2,633 (367)
+Depletion, depreciation, amortization and abandonment liability accretion 81,960 54,432 51,346
+Impairment of proved properties 185 - 820
+Abandonment and impairment of unproved properties 3,796 2,446 3,865
+Unrealized derivative loss 310 373 1,573
+Mark to market of long-term net profit plans 5,317 846 -
+Deferred income taxes 21,687 14,633 23,726
+Exploratory dry hole expense 8,482 7,677 9,028
+Minority interest and other 2,088 (1,642) (1,327)
+Cumulative effect of change in accounting principle (5,435) - -
+--------- --------- ---------
+206,687 108,958 129,123
+Changes in current assets and liabilities:
+Accounts receivable (29,685) 11,085 (629)
+Prepaid expenses and other 490 (4,173) (664)
+Income taxes 6,785 10,030 (11,061)
+Accounts payable and accrued expenses 19,666 15,992 10,752
+Current deferred income taxes 376 (183) (29)
+--------- --------- ---------
+Net cash provided by operating activities 204,319 141,709 127,492
+--------- --------- ---------
+Cash flows from investing activities:
+Proceeds from sale of oil and gas properties 23,497 1,624 4,771
+Capital expenditures (123,823) (97,257) (131,680)
+Acquisition of oil and gas properties (76,413) (87,466) (39,124)
+Deposits to short-term investments available-for-sale (12,529) (13,523) -
+Receipts from short-term investments available-for-sale 2,450 12,538 -
+Receipts from restricted cash 11,500 - -
+Deposits to restricted cash (21,853) - -
+Other 232 3,153 6,958
+--------- --------- ---------
+Net cash used in investing activities (196,939) (180,931) (159,075)
+--------- --------- ---------
+Cash flows from financing activities:
+Proceeds from credit facility 140,933 37,400 147,050
+Repayment of credit facility (145,020) (87,400) (105,050)
+Proceeds from convertible debt - 96,657 -
+Proceeds from sale of common stock 3,530 2,390 2,746
+Repurchase of common stock - - (12,871)
+Dividends paid (3,150) (2,787) (2,795)
+--------- --------- ---------
+Net cash provided by (used in) financing activities (3,707) 46,260 29,080
+Net change in cash and cash equivalents 3,673 7,038 (2,503)
+Cash and cash equivalents at beginning of period 11,154 4,116 6,619
+--------- --------- ---------
+Cash and cash equivalents at end of period $ 14,827 $ 11,154 $ 4,116
+========= ========= =========
+The accompanying notes are an integral part
+of these concolidated financial statements.
+F-6
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
+Supplemental schedule of additional cash flow information and noncash
+activities:
+For the Years Ended December 31,
+----------------------------------------
+2003 2002 2001
+---------- ------------ ----------
+(in thousands)
+Cash paid for interest, including amounts capitalized $ 7,555 $ 2,498 $ 764
+Cash paid (refunded) for income taxes 28,858 (550) 11,205
+In January 2003 the Company issued 7,200 shares of common stock from
+treasury to its non-employee directors and recorded compensation expense of
+$153,000.
+In January 2003 the Company issued 3,380,818 restricted shares of
+common stock to Flying J Oil & Gas Inc. and Big West Oil & Gas Inc.
+(collectively, "Flying J") and entered into a put and call option agreement,
+valued at $995,000 for financial reporting purposes, with Flying J with respect
+to those shares in connection with the acquisition of oil and gas properties and
+related assets and liabilities.
+In June 2002 the Company issued 800 shares of common stock to a
+non-employee director and recorded compensation expense of $14,763.
+In April 2002 the Company accepted 9,472,562 shares of common stock in
+Constellation Copper Corporation ("Constellation", formerly known as Summo
+Minerals Corporation) in lieu of cash payment for the relief of a $1,400,000
+loan and $15,311 in interest due to the Company.
+In January 2002 the Company issued 7,200 shares of common stock to its
+non-employee directors and recorded compensation expense of $129,683.
+In January 2001 the Company issued 8,400 shares of common stock to its
+directors and recorded compensation expense of $237,852.
+The accompanying notes are an integral part
+of these concolidated financial statements.
+F-7
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+DECEMBER 31, 2003
+1. Summary of Significant Accounting Policies
+Description of Operations
+St. Mary Land & Exploration Company ("St. Mary" or the "Company")
+is an independent energy company engaged in the exploration, development,
+acquisition and production of natural gas and crude oil. The Company's
+operations are conducted entirely in the continental United States.
+Basis of Presentation
+The consolidated financial statements include the accounts of the
+Company and its wholly-owned subsidiaries. Subsidiaries that are not
+wholly-owned are accounted for using full consolidation with minority interest
+or by the equity or cost method as appropriate. All significant intercompany
+accounts and transactions have been eliminated.
+Cash and Cash Equivalents
+The Company considers all liquid investments purchased with an initial
+maturity of three months or less to be cash equivalents. The carrying value of
+cash and cash equivalents approximates fair value due to the short-term nature
+of these instruments.
+Short-term Investments
+The Company's short-term investments consist primarily of equity
+securities and investment-grade marketable debt, which are classified as
+available-for-sale or held-to-maturity. Securities that have been categorized as
+available-for-sale are stated at fair value based on quoted market prices. Debt
+securities that are categorized as held-to-maturity are carried at amortized
+cost when the Company has the ability and intent to hold the securities until
+maturity.
+Concentration of Credit Risk
+Substantially all of the Company's receivables are within the oil and
+gas industry, primarily from purchasers of oil and gas and from joint interest
+owners. Although diversified within many companies, collectability is dependent
+upon the general economic conditions of the industry. The receivables are not
+collateralized. However, to date the Company has had minimal bad debts.
+The Company has accounts with separate banks in Denver, Colorado;
+Shreveport, Louisiana; Tulsa, Oklahoma; Lafayette, Louisiana; and Billings,
+Montana. At December 31, 2003, 2002 and 2001, the Company had $23.5 million,
+$4.9 million and $6.6 million respectively, invested in money market funds
+(including margin accounts) consisting of corporate commercial paper, repurchase
+agreements and U.S. Treasury obligations. The difference between the investment
+amount and the cash and cash equivalents amount on the consolidated balance
+sheet as of December 31, 2003, represents uncleared disbursements. The Company's
+policy is to invest in highly rated instruments and to limit the amount of
+credit exposure at each individual institution.
+Oil and Gas Producing Activities
+The Company follows the successful efforts method of accounting for its
+oil and gas properties. Under this method of accounting, all property
+acquisition costs and costs of exploratory and development wells are capitalized
+when incurred, pending determination of whether the well has found proved
+reserves. If an exploratory well does not find proved reserves, the costs of
+drilling the well are charged to expense. Exploratory dry hole costs are
+F-8
+included in cash flows from investing activities within the consolidated
+statements of cash flows. The costs of development wells are capitalized whether
+productive or nonproductive.
+Geological and geophysical costs and the costs of carrying and
+retaining unproved properties are expensed as incurred. An impairment allowance
+is provided on a property-by-property basis when the Company determines that the
+unproved property will not be developed. Depletion, depreciation and
+amortization ("DD&A") of capitalized costs of proved oil and gas properties
+is provided on a field-by-field basis using the units of production method based
+upon proved reserves. The computation of DD&A takes into consideration
+restoration, dismantlement and abandonment costs and the anticipated proceeds
+from equipment salvage. On January 1, 2003, the Company adopted the provisions
+of Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for
+Asset Retirement Obligations," which provides guidance on accounting for
+dismantlement and abandonment costs (see Note 9 - Asset Retirement Obligations).
+The Company reviews its long-lived assets for impairments when events
+or changes in circumstances indicate that an impairment may have occurred. The
+impairment test compares the expected undiscounted future net revenues on a
+field-by-field basis with the related net capitalized costs at the end of each
+period. Expected future cash flows are calculated on all proved reserves using a
+15% discount rate and escalated prices. When the net capitalized costs exceed
+the undiscounted future net revenue of a property, the cost of the property is
+written down to fair value, which is determined using discounted future net
+revenues. During 2003, 2002 and 2001 the Company recorded impairment charges for
+proved properties of $185,000, $-0- and $820,000, respectively.
+A reporting issue has arisen regarding the application of certain
+provisions of SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill
+and Other Intangible Assets", to companies in the extractive industries,
+including oil and gas companies. The issue is whether the Financial Accounting
+Standards Board ("FASB") intended to require companies to classify the costs of
+mineral rights held under lease or other contractual arrangements associated
+with extracting oil and gas as intangible assets in the balance sheet, apart
+from other capitalized oil and gas property costs, and provide specific footnote
+disclosures. Historically, St. Mary has included the costs of such mineral
+rights associated with extracting oil and gas as a component of oil and gas
+properties. If it is ultimately determined by the FASB that SFAS No. 142 was
+intended to require oil and gas companies to classify costs of mineral rights
+held under lease or other contractual arrangements associated with extracting
+oil and gas as a separate intangible assets line item on the balance sheet, the
+balance sheet would display the following items based on the unaudited pro forma
+presentation:
+Unaudited Pro Forma Presentation December 31,
+---------------------------------------------
+2003 2002
+------------- --------------
+(In thousands)
+Total current assets $ 107,923 $ 59,547
+Property and equipment
+Proved oil and gas properties 514,919 389,777
+Less-accumulated depletion, depreciation
+and amortization (198,717) (174,691)
+Unproved oil and gas properties, net of
+Impairment allowance 24,691 18,998
+Other property and equipment, net of
+accumulated depreciation 4,276 3,639
+------------- --------------
+345,169 237,723
+Restricted cash subject to Section 1031 Exchange 10,353 -
+Intangible leasehold, net 266,117 234,216
+Other noncurrent assets 6,292 5,653
+------------- --------------
+Total Assets $ 735,854 $ 537,139
+============= ==============
+F-9
+St. Mary's cash flows and results of operations would not be affected
+by the classification of leasehold costs as intangible since these items would
+continue to be depleted and assessed for impairment on the same basis as
+currently required by SFAS No. 19, "Financial Accounting and Reporting by Oil
+and Gas Producing Companies." Further, St. Mary does not believe the
+classification of the costs of mineral rights associated with extracting oil and
+gas as intangible assets would have any impact on compliance with covenants
+under its debt agreements.
+Impairment of Nonproducing Properties
+An impairment allowance is provided on unproved property when the
+Company determines that the property will not be developed.
+Sales of Producing and Nonproducing Properties
+The sale of a partial interest in a proved property is accounted for as
+normal retirement, and no gain or loss is recognized as long as this treatment
+does not significantly affect the unit-of-production depletion rate. A gain or
+loss is recognized for all other sales of producing properties and is included
+in the results of operations.
+The sale of a partial interest in an unproved property is accounted for
+as a recovery of cost when substantial uncertainty exists as to recovery of the
+cost applicable to the interest retained. A gain on the sale is recognized to
+the extent that the sales price exceeds the carrying amount of the unproved
+property. A gain or loss is recognized for all other sales of nonproducing
+properties and is included in the results of operations.
+Other Property and Equipment
+Other property and equipment such as office furniture and equipment,
+automobiles and computer hardware and software is recorded at cost. Costs of
+renewals and improvements that substantially extend the useful lives of the
+assets are capitalized. Maintenance and repairs are expensed when incurred.
+Depreciation is provided using the straight-line method over the estimated
+useful lives of the assets from three to 15 years. Gains and losses on
+dispositions of other property and equipment are included in the results of
+operations.
+Restricted Cash
+Proceeds from certain sales of oil and gas producing properties are
+held in escrow and restricted for future acquisitions under a tax-free exchange
+agreement. These funds are invested in money market funds consisting of
+corporate commercial paper, repurchase agreements and U.S. Treasury obligations
+and are carried at cost, which approximates market.
+Gas Balancing
+The Company uses the sales method to account for gas imbalances. Under
+this method, revenue is recorded based on gas actually sold by the Company. The
+Company records revenue for its share of gas sold by other owners that cannot be
+volumetrically balanced in the future due to insufficient remaining reserves.
+Related receivables totaling $1.2 million at December 31, 2003, and $898,000 at
+December 31, 2002, are included in other noncurrent assets in the accompanying
+consolidated balance sheets. The Company also reduces revenue for gas sold by
+the Company that cannot be volumetrically balanced in the future due to
+insufficient remaining reserves. Related payables totaling $500,000 at December
+31, 2003, and $531,000 at December 31, 2002, are included in other noncurrent
+liabilities in the accompanying consolidated balance sheets. The Company's
+remaining overproduced and underproduced gas balancing positions are considered
+in the Company's proved oil and gas reserves (see Note 11 - Disclosures about
+Oil and Gas Producing Activities).
+Derivative Financial Instruments
+The Company seeks to protect its rate of return on acquisitions of
+producing properties, drilling prospects and other production by hedging cash
+flows when the economic criteria from its evaluation and pricing model indicate
+it would be appropriate. The Company intends for these derivative instruments
+used for this purpose to be designated as and qualify as cash flow hedging
+F-10
+instruments under SFAS No. 133, "Accounting for Derivative Instruments and
+Hedging Activities," and related pronouncements. Management reviews these
+hedging parameters on a quarterly basis. The Company generally limits its
+aggregate hedge position to no more than 50% of its total production but will
+hedge larger percentages of total production in certain circumstances. The
+Company seeks to minimize basis risk and indexes the majority of its oil hedges
+to NYMEX prices and the majority of its gas hedges to various regional index
+prices associated with pipelines in proximity to the Company's areas of gas
+production.
+The Company's hedge positions are diversified with various
+counterparties, and the Company requires that such counterparties have clear
+indications of current financial strength (See Note 10 - Derivative Financial
+Instruments for additional discussion of derivatives).
+Fair Value of Financial Instruments
+The Company's financial instruments including cash and cash
+equivalents, restricted cash, accounts receivable and accounts payable are
+carried at cost, which approximates fair value due to the short-term maturity of
+these instruments. The revolving credit facility's recorded value approximates
+its fair value as it bears interest at a floating rate. The Company's interest
+rate swaps are recorded at fair value as discussed in Note 5 - Long-Term Debt
+and Revolving Credit Facility. The Company's 5.75% Senior Convertible Notes Due
+2022 are recorded at cost, and the fair value is disclosed in Note 5. The
+Company's other financial instruments and investments in available-for-sale
+securities are marked to market with changes in fair value being recorded in
+accumulated other comprehensive income. Since considerable judgment is required
+to develop estimates of fair value, the estimates provided are not necessarily
+indicative of the amounts the Company could realize upon the sale or refinancing
+of such instruments.
+Income Taxes
+Deferred income taxes are provided on the difference between the tax
+basis of an asset or liability and its carrying amount in the financial
+statements. This difference will result in taxable income or deductions in
+future years when the reported amount of the asset or liability is recovered or
+settled, respectively.
+Earnings Per Share
+Basic net income per common share of stock is calculated by dividing
+net income by the weighted average number of common shares outstanding during
+each period. During the first quarter of 2003, the Company issued 3,380,818
+shares of common stock as part of an acquisition (see Note 3 - Acquisitions and
+Divestitures). These shares are considered outstanding for purposes of
+calculating basic and diluted net income per common share and are weighted
+accordingly in the calculation of common shares outstanding. However, the shares
+are included in the temporary equity section of the accompanying consolidated
+balance sheets as of December 31, 2003. Following is a reconciliation of total
+shares outstanding as of December 31, 2003.
+Common shares outstanding in Stockholders'
+equity, net of treasury shares 28,242,423
+Restricted common shares outstanding in Temporary equity 3,380,818
+-------------
+Total common shares outstanding 31,623,241
+=============
+Subsequent to December 31, 2003, St. Mary repurchased and canceled the
+3,380,818 shares described above (see Note 13 - Subsequent Events).
+F-11
+The following table sets forth the calculation of basic and diluted
+earnings per share:
+Years Ended December31,
+------------------------------------------------
+2003 2002 2001
+-------------- ------------- --------------
+(In thousands, except per share amounts)
+Income before cumulative effect of change in accounting
+principle $ 90,140 $ 27,560 $ 40,459
+Cumulative effect of change in accounting principle, net
+of income tax 5,435 - -
+-------------- ------------- --------------
+Net income 95,575 27,560 40,459
+-------------- ------------- --------------
+Adjustments to net income for dilution:
+Add: interest expense avoided if Convertible Notes
+converted 6,337 - -
+Less: charitable contributions of 1% of net income (63) - -
+Less: tax effect of dilution items (2,403) - -
+-------------- ------------- --------------
+Net income adjusted for the effect of dilution $ 99,446 $ 27,560 $ 40,459
+============== ============= ==============
+Basic weighted average common shares outstanding
+in period 31,233 27,856 27,973
+Add: dilutive effects of stock option 455 535 582
+Add: dilutive effect of Convertible Notes using if-
+converted method 3,846 - -
+-------------- ------------- --------------
+Diluted weighted average common shares outstanding
+in period 35,534 28,391 28,555
+============== ============= ==============
+Basic earnings per common share:
+Income before cumulative effect of change in
+accounting principle $ 2.89 $ 0.99 $ 1.45
+Gain from change in accounting principle 0.17 - -
+-------------- ------------- --------------
+Total $ 3.06 $ 0.99 $ 1.45
+============== ============= ==============
+Diluted earnings per common share:
+Income before cumulative effect of change in
+accounting principle $ 2.65 $ 0.97 $ 1.42
+Gain from change in accounting principle 0.15 - -
+-------------- ------------- --------------
+Total $ 2.80 $ 0.97 $ 1.42
+============== ============= ==============
+Diluted net income per common share of stock is calculated by dividing
+adjusted net income by the weighted average of common shares outstanding and
+other dilutive securities. Adjusted net income is used for the if-converted
+method discussed below and is derived by adding interest expense paid on the
+Company's 5.75% Senior Convertible Notes due 2022 (the "Convertible Notes") back
+to net income and then adjusting for nondiscretionary items including the
+related income tax effect. Potentially dilutive securities of the Company
+consist of in-the-money outstanding options to purchase the Company's common
+stock and shares into which the Convertible Notes may be converted.
+F-12
+The treasury stock method is used to measure the dilutive impact of
+stock options. The following table details the weighted-average dilutive and
+anti-dilutive securities related to stock options for the periods presented.
+For the Years Ended December 31,
+----------------------------------------------------
+2003 2002 2001
+---------------- --------------- ---------------
+Dilutive 455,055 534,610 582,313
+Anti-dilutive 713,382 1,539,227 625,492
+Shares associated with the conversion feature of the Convertible Notes
+are accounted for using the if-converted method. Under the if-converted method,
+income used to calculate diluted earnings per share is adjusted for the interest
+charges and nondiscretionary adjustments based on income that would have changed
+had the Convertible Notes been converted at the beginning of the period.
+Potentially dilutive shares of 3,846,153 related to the Convertible Notes were
+included in the 2003 calculation of diluted net income per share. Potentially
+dilutive shares of 3,076,922 related to the Convertible Notes were excluded from
+the 2002 calculation of diluted net income per share because they were
+anti-dilutive. The Convertible Notes were issued in March 2002.
+Stock-Based Compensation
+At December 31, 2003, the Company had stock-based employee compensation
+plans that include stock options issued to employees and non-employee directors
+as more fully described in Note 7 - Compensation Plans. The Company accounts for
+stock-based compensation using the intrinsic value recognition and measurement
+principles prescribed in Accounting Principles Board Opinion No. 25, "Accounting
+for Stock Issued to Employees" ("APB No. 25") and related interpretations. No
+stock-based employee compensation expense is reflected in net income as all
+options granted under those plans had an exercise price equal to the market
+value of the underlying common stock on the date of grant. The following table
+illustrates the effect on net income and earnings per share if the Company had
+applied the fair value recognition provisions of SFAS No. 123, "Accounting for
+Stock-Based Compensation," to stock-based employee compensation.
+F-13
+For The Years Ended December 31,
+----------------------------------------------------
+2003 2002 2001
+--------------- -------------- ---------------
+(In thousands, except per share amounts)
+Net income -
+As reported: $ 95,575 $ 27,560 $ 40,459
+Add: Stock-based employee compensation
+expense included in reported net income,
+net of related tax effects - - -
+Less: Stock-based employee compensation
+expense determined under fair value
+based method for all awards, net of
+related income tax effects 5,853 4,666 2,890
+--------------- -------------- ---------------
+Pro forma $ 89,722 $ 22,894 $ 37,569
+=============== ============== ===============
+Basic earnings per share -
+As reported:
+Income before cumulative effect of change in
+accounting principle $ 2.89 $ 0.99 $ 1.45
+Gain from change in accounting principle 0.17 - -
+--------------- -------------- ---------------
+Total $ 3.06 $ 0.99 $ 1.45
+=============== ============== ===============
+Pro forma:
+Income before cumulative effect of change in
+accounting principle $ 2.70 $ 0.82 $ 1.34
+Gain from change in accounting principle 0.17 - -
+--------------- -------------- ---------------
+Total $ 2.87 $ 0.82 $ 1.34
+=============== ============== ===============
+Diluted earnings per share -
+As reported:
+Income before cumulative effect of change in
+accounting principle $ 2.65 $ 0.97 $ 1.42
+Gain from change in accounting principle 0.15 - -
+--------------- -------------- ---------------
+Total $ 2.80 $ 0.97 $ 1.42
+=============== ============== ===============
+Pro forma:
+Income before cumulative effect of change in
+accounting principle $ 2.48 $ 0.81 $ 1.32
+Gain from change in accounting principle 0.15 - -
+--------------- -------------- ---------------
+Total $ 2.63 $ 0.81 $ 1.32
+=============== ============== ===============
+For purposes of pro forma disclosures, the estimated fair values of the
+options are amortized to expense over the options' vesting periods. The effects
+of applying SFAS No. 123 in the pro forma disclosure are not necessarily
+indicative of actual future amounts. The Company is considering alternatives
+other than stock option grants for the equity portion of its compensation
+program.
+Comprehensive Income
+Comprehensive income consists of net income, and unrealized gains and
+losses on marketable equity securities held for sale, the effective component of
+derivative instruments classified as cash flow hedges, and accrued pension
+benefit obligation in excess of plan assets. Comprehensive income is presented
+net of income taxes in the consolidated statements of stockholders' equity and
+comprehensive income.
+F-14
+The balances of after-tax components comprising other comprehensive
+income (loss) are presented in the following table:
+As of December 31,
+------------------------------------------------
+2003 2002 2001
+------------- -------------- -------------
+(In thousands)
+Minimum pension liability $ (564) $ (761) $ -
+Unrealized gain (loss) on marketable equity securities - (716) 9
+Unrealized hedge loss (14,317) (6,290) 6,907
+------------- -------------- -------------
+Total accumulated other comprehensive income (loss) $ (14,881) $ (7,767) $ 6,916
+============= ============== =============
+Major Customers
+During 2003 three customers individually accounted for 13.6%, 13.1% and
+11.4% of the Company's total oil and gas production revenue. During 2002 no
+customer individually accounted for more than 10% of the Company's total oil and
+gas production revenue. During 2001 two customers individually accounted for
+12.0% and 11.3% of the Company's total oil and gas production revenue.
+Industry Segment and Geographic Information
+The Company operates in one industry segment, which is the exploration,
+development and production of natural gas and crude oil, and all of the
+Company's operations are conducted in the continental United States.
+Consequently, the Company currently reports as a single industry segment.
+Use of Estimates in the Preparation of Financial Statements
+The preparation of financial statements in conformity with accounting
+principles generally accepted in the United States requires management to make
+estimates and assumptions that affect the reported amounts of oil and gas
+reserves, assets and liabilities and disclosure of contingent assets and
+liabilities at the date of the financial statements and the reported amounts of
+revenues and expenses during the reporting period. Actual results could differ
+from those estimates.
+Recently Issued Accounting Standards
+In May 2003 FASB issued SFAS No. 150, "Accounting for Certain Financial
+Instruments with Characteristics of both Liabilities and Equity." This Statement
+establishes standards for how an issuer classifies and measures certain
+financial instruments with characteristics of both liabilities and equity and
+requires that such financial instruments be classified as a liability (or as an
+asset in certain circumstances). SFAS No. 150 is effective for all freestanding
+instruments entered into or modified after May 31, 2003. Otherwise, it became
+effective for us as of July 1, 2003. The Company has no financial instruments
+that fall within the scope of this statement.
+F-15
+2. Accounts Receivable and Accounts Payable
+Accounts receivable are composed of the following:
+December 31,
+-------------------------------------------
+2003 2002
+------------------ -----------------
+(In thousands)
+Accrued oil and gas sales $ 48,925 $ 25,962
+Due from joint interest owners 12,554 8,920
+Other 3,605 517
+------------------ -----------------
+Total accounts receivable $ 65,084 $ 35,399
+================== =================
+Accounts payable and accrued expenses are composed of the following:
+December 31,
+-------------------------------------------
+2003 2002
+------------------ -----------------
+(In thousands)
+Accrued drilling costs $ 22,201 $ 11,188
+Revenue payable 16,215 7,187
+Accrued lease operating expense 12,195 6,409
+Accrued cash bonus and net profit payments 8,026 3,522
+Trade payables 6,247 6,369
+Other 16,333 14,115
+------------------ -----------------
+Total account payable and accrued expenses $ 81,217 $ 48,790
+================== =================
+3. Acquisitions and Divestitures
+Flying J Acquisition
+On January 29, 2003, the Company acquired oil and gas properties and
+other assets and liabilities from Flying J Oil & Gas Inc. and Big West Oil
+& Gas Inc. (collectively, "Flying J"). As consideration for the properties
+St. Mary issued 3,380,818 restricted shares of its common stock to Flying J. In
+addition, St. Mary made a non-recourse loan to Flying J of $71.6 million at the
+one-year LIBOR plus 2% for up to a 39-month period. The loan was funded using
+cash on hand and borrowing under the credit facility in place at the time of the
+transaction. This loan was secured by a pledge of the shares of common stock
+issued to Flying J, with the final nine months of interest on that loan to be
+with recourse to Flying J. St. Mary also entered into a put and call option
+agreement with Flying J whereby during the 39-month loan period Flying J could
+elect to put their shares of St. Mary common stock to the Company for $71.6
+million plus accrued interest on the loan during the first thirty months of the
+loan period, and St. Mary could elect to call the shares for $97.4 million, with
+the proceeds from the exercise of either the put option or the call option to be
+applied to the repayment of the loan plus accrued and unpaid interest. The
+shares issued were restricted for a period of two years, and Flying J was
+prohibited from selling the shares during that period. If neither Flying J nor
+St. Mary exercised their respective option rights, the loan plus accrued
+interest was to be repaid prior to the release of the security interest in the
+shares.
+For financial reporting purposes, the effect of the above arrangements
+is that the Company acquired oil and gas properties and other assets and
+liabilities in exchange for $71.6 million of cash plus a net option to Flying J
+valued at $995,000 resulting in a total valuation of $72.4 million. The
+allocation of the purchase price for the net assets acquired was $72.3 million
+of proved reserves and unproved acreage, $445,000 of other assets, a $1.9
+million asset retirement liability, a $2.0 million hedge liability, and $3.7
+million in net cash received for purchase price adjustments. The acquisition was
+accounted for using the purchase method of accounting. Operating results from
+the acquired properties have been included in the consolidated statements of
+operations only from the date of closing.
+F-16
+The shares of common stock that were issued in this transaction were
+recorded as temporary equity since they are subject to the put option whereby
+the Company may be required to repurchase these shares. The shares of common
+stock are considered outstanding for basic and diluted earnings per share
+calculations. The loan arising from this transaction is considered a
+contra-temporary equity item on the consolidated balance sheets, as opposed to
+an asset, since the loan is non-recourse to Flying J except with respect to
+interest accrued after the first thirty months and is secured by the restricted
+common stock issued as part of this transaction. Interest has not accrued for
+financial reporting purposes because of the non-recourse nature of the note.
+Subsequent to year end, the Company entered into a separately
+negotiated transaction with Flying J to repurchase the 3,380,818 restricted
+shares issued in the acquisition. See Note 13 - Subsequent Events for a more
+detailed discussion of this transaction.
+Burlington Resources Acquisition
+On December 3, 2002, the Company completed the acquisition of oil and
+gas properties located in Montana, North Dakota and Wyoming from Burlington
+Resources Oil & Gas Company LP. The Company paid $69.2 million in cash after
+normal price adjustments. The Company utilized a portion of its existing credit
+facility to fund the acquisition, and the transaction was accounted for as a
+purchase.
+Sales of Properties
+Throughout 2003, the Company sold interests in certain non-core
+properties primarily in Texas and Wyoming. The Company received $23.5 million in
+net proceeds and recognized a gain of approximately $7.3 million from these
+sales. For property sales that occurred in the fourth quarter of 2003, the final
+proceeds and gain amounts are subject to the resolution of final post-closing
+adjustments and settlements. These sold properties were neither individually nor
+collectively material with respect to their future production, reserves or
+impact on an individual consolidated financial statement line item.
+Additionally, the production, reserves, revenues and operating costs associated
+with these sales in prior periods were immaterial individually and in total.
+4. Income Taxes
+The provision for income taxes consists of the following:
+For the Years Ended December 31,
+-----------------------------------------
+2003 2002 2001
+------------- ------------- -------------
+(In thousands)
+Current Taxes:
+Federal $ 29,582 $ 719 $ 1,114
+State 2,656 569 620
+Deferred taxes 23,692 13,731 20,095
+------------- ------------- -------------
+Total income tax expense $ 55,930 $ 15,019 $ 21,829
+============= ============= =============
+The above taxes on income before income taxes and cumulative effect of
+change in accounting principle are net of alternative fuels credits (Internal
+Revenue Code Section 29) of $-0- in 2003, $167,000 in 2002 and $185,000 in 2001.
+Current federal tax does not reflect the tax benefit for deductions from stock
+option exercises of $1.2 million in 2003, $719,000 in 2002 and $930,000 in 2001
+because the benefit is included in additional paid-in capital in the
+consolidated balance sheets.
+F-17
+The components of the net deferred tax liability are as follows:
+December 31,
+-------------------------------------
+2003 2002
+------------------- -----------------
+(In thousands)
+Deferred Tax Liabilities
+Oil and gas properties $ 100,103 $ 71,448
+Derivative instruments and other 41 62
+------------------- -----------------
+Total deferred tax liabilities 100,144 71,510
+------------------- -----------------
+Deferred Tax Assets
+Amounts included in accumulated other comprehensive income 9,222 4,181
+State tax net operating loss carryforward 2,094 4,042
+Federal net operating loss carryforward 2,900 3,142
+Deferred capital loss 1,840 1,703
+Employee benefits and other 1,853 1,325
+State and federal income tax benefit 1,002 775
+Charitable contributions carryforward - 218
+Alternative minimum tax credit carryforward - 215
+------------------- -----------------
+Total deferred tax assets 18,911 15,601
+Valuation allowance (842) (727)
+------------------- -----------------
+Net deferred tax assets 18,069 14,874
+------------------- -----------------
+Total net deferred tax liabilities 82,075 56,636
+Current deferred income tax assets 8,872 3,520
+------------------- -----------------
+Non-current net deferred tax liabilities $ 90,947 $ 60,156
+=================== =================
+Current federal refundable income tax $ 454 $ 890
+=================== =================
+Current state refundable income tax $ - $ 141
+=================== =================
+Current state income tax payable $ 1,334 $ -
+=================== =================
+At December 31, 2003, the Company had state net operating loss
+carryforwards of approximately $28.5 million and state tax credits of $97,000,
+which expire between 2004 and 2022. The Company's valuation allowance relates to
+those state net operating loss carryforwards that the Company anticipates will
+expire before they can be utilized. The net change in valuation allowance in
+2003 results from an evaluation of state net operating loss carryforwards that
+led to a conclusion by the Company that more of the carryforwards will be offset
+by reversing state temporary differences, projections of future taxable income
+and individual state tax planning strategies before they expire than was
+anticipated in prior years.
+F-18
+Federal income tax expense differs from the amount that would be
+provided by applying the statutory U.S. Federal income tax rate to income before
+income taxes for the following reasons:
+For the Years Ended December 31,
+-------------------------------------------------
+2003 2002 2001
+--------------- ---------------- ----------------
+(In thousands)
+Federal statutory taxes $ 49,668 $ 14,477 $ 20,420
+Increase (reduction) in taxes resulting from:
+State taxes (net of Federal benefit) 5,812 2,092 2,017
+Statutory depletion (224) (218) (238)
+Alternative fuel credits (Section 29) - (167) (185)
+Change in valuation allowance 115 (1,202) 34
+Other 559 37 (219)
+--------------- ---------------- ----------------
+Income tax expense $ 55,930 $ 15,019 $ 21,829
+=============== ================ ================
+5. Long-term Debt and Revolving Credit Facility
+Revolving Credit Facility
+In January 2003 the Company replaced its revolving credit facility with
+a new long-term revolving credit agreement with a group of banks. The new credit
+agreement specifies a maximum loan amount of $300.0 million and has a maturity
+date of January 27, 2006. Borrowings under the facility are secured by a pledge
+in favor of the lenders of collateral that includes certain oil and gas
+properties and the common stock of the material subsidiaries of the Company. A
+borrowing base of $275.0 million was determined by the bank group at the end of
+October 2003 under a normal semi-annual determination. The borrowing base
+determination process considers the value of St. Mary's oil and gas properties
+and other assets, as determined by the bank syndicate. We have elected an
+aggregate commitment amount of $150.0 million. The Company must comply with
+certain financial and non-financial covenants. Interest and commitment fees are
+accrued based on the borrowing base utilization percentage table below.
+LIBOR-based borrowings accrue interest at LIBOR plus the applicable margin from
+the utilization table, and Alternative Base Rate ("ABR") borrowings accrue
+interest at Prime plus the applicable margin from the utilization table.
+Commitment fees are accrued on the unused portion of the aggregate commitment
+amount and are included in interest expense in the consolidated statements of
+operations.
+Borrowing base
+utilization percentage <50% =>50%<75% =>75%<90% >90%
+--------------------------------------------------------------------------------
+Eurodollar Loans 1.25% 1.50% 1.75% 2.00%
+ABR Loans 0.00% 0.25% 0.50% 0.75%
+Commitment Fee Rate 0.30% 0.38% 0.38% 0.50%
+At December 31, 2003, the Company's borrowing base utilization
+percentage as defined under the credit agreement was 7.3%. The Company had $11.0
+million in ABR borrowings outstanding under its revolving credit agreement as of
+December 31, 2003. As of February 20, 2004, the Company has repaid the ABR
+borrowings and has an outstanding balance of $10.0 million under its LIBOR
+alternative.
+5.75% Senior Convertible Notes Due 2022
+As of December 31, 2003, the Company also had $100.0 million in
+outstanding borrowings under the 5.75% Senior Convertible Notes Due 2002 (the
+"Convertible Notes"). The Convertible Notes provide for the payment of
+contingent interest of up to an additional 0.5% during six-month interest
+periods based on the Convertible Note market price before the beginning of the
+particular six-month period. Under that provision, interest was accrued at a
+F-19
+total rate of 6.25% for 2003. Based on the trading price of the Convertible
+Notes over the determination period, the Company will be subject to the
+contingent interest payments for the period from September 16, 2003, to March
+15, 2004.
+The Convertible Notes are general unsecured obligations and rank on
+parity in right of payment with all existing and future unsecured senior
+indebtedness and other general unsecured obligations. They are senior in right
+of payment to all future subordinated indebtedness. The Convertible Notes are
+convertible into the Company's common stock at a conversion price of $26.00 per
+share, subject to adjustment. The Company can redeem the Convertible Notes with
+cash in whole or in part at a repurchase price of 100% of the principal amount
+plus accrued and unpaid interest (including contingent interest) beginning on
+March 20, 2007. The note holders have the option of requiring the Company to
+repurchase the Convertible Notes for cash at 100% of the principal amount plus
+accrued and unpaid interest (including contingent interest) upon (1) a change in
+control of St. Mary or (2) on March 20, 2007, March 15, 2012, and March 15,
+2017. If the note holders require repurchase on March 20, 2007, the Company may
+elect to pay the repurchase price with cash, shares of its common stock valued
+at a discount at the time of repurchase, or any combination of cash and its
+discounted common stock. The shares of common stock used in any repurchase will
+be discounted at 95% of market price if 33% or less of the repurchase price is
+in shares of our common stock; otherwise, the stock will be discounted at 93% of
+market value. St. Mary is not restricted from paying dividends, incurring debt,
+or issuing or repurchasing its securities under the indenture for the
+Convertible Notes. There are no financial covenants in the indenture. Based on
+the market price of the Convertible Notes, the estimated fair value of the
+Convertible Notes was approximately $135.3 million as of December 31, 2003, and
+approximatly $131.9 million as of December 31, 2002.
+On October 3, 2003, the Company entered into fixed-to-floating interest
+rate swaps for a total notional amount of $50.0 million through March 20, 2007.
+Under the swaps St. Mary will be paid a fixed interest rate of 5.75% and will
+pay a variable interest rate of 235 basis points above the six-month LIBOR rate
+as determined on the semi-annual settlement date. The six-month LIBOR rate on
+December 31, 2003 was 1.16%. The payment dates of the swaps match exactly with
+the interest payment dates of the Convertible Notes. The fair value of the swaps
+was a liability of $104,000 as of December 31, 2003. Changes in the fair value
+of the swaps are recorded to interest expense.
+Weighted Average Interest Rate Paid
+The weighted average interest rate paid in 2003 was 6.3% including
+commitment fees paid on the unused portion of the credit facility aggregate
+commitment, amortization of deferred financing costs, and amortization of the
+contingent interest embedded derivative. The impact of the commitment fees over
+a lower average outstanding balance results in a higher weighted average
+interest rate despite lower LIBOR interest rates than in previous periods.
+6. Commitments and Contingencies
+The Company leases office space under various operating leases with
+terms extending as far as May 31, 2012. Rent expense, net of sublease income,
+was $1.3 million, $1.1 million and $839,000 in 2003, 2002 and 2001,
+respectively. The Company also leases office equipment under various operating
+leases. The Company has a non-cancelable sublease of approximately $1.5 million
+through 2012. The annual minimum lease payments for the next five years are
+presented below:
+Years Ending December 31, (In thousands)
+---------------------------- -------------------
+2004 $ 2,205
+2005 1,540
+2006 1,452
+2007 1,153
+2008 1,032
+Thereafter 3,158
+------------------
+Total $ 10,540
+==================
+F-20
+The Company is subject to litigation and claims that have arisen in the
+ordinary course of business. The Company accrues for such items when a liability
+is both probable and the amount can be reasonably estimated. In the opinion of
+management, the results of such litigation and claims will not have a material
+effect on the results of operations or the financial position of the Company.
+Management believes it has sufficiently provided for such items in the
+consolidated balance sheets.
+7. Compensation Plans
+Cash Bonus Plan
+The Company has a cash bonus plan that allows participants to receive
+up to 100% of their aggregate base salary. Any awards under the cash bonus plans
+are based on a combination of Company and individual performance. The Company
+accrued $5.4 million for cash bonuses in 2003 that will be paid in 2004, $2.1
+million for cash bonuses in 2002 that were paid in 2003, and $170,000 for cash
+bonuses in 2001 that were paid in 2002.
+Net Profits Interest Bonus Plans
+Under the Company's net profits interest bonus plan, oil and gas wells
+that are completed or acquired during a year are designated as a pool. Key
+employees designated as participants by the Company's Compensation Committee of
+the Board of Directors and employed by the Company on the last day of that year
+vest and become entitled to bonus payments after the Company recovers net
+revenues generated by the pool equal to 100% of its investment in that pool.
+Thereafter, an amount generally equal to 10% of net profits generated by the
+pool will be allocated among the participants and paid at least annually. The
+percentage of net profits from the pool to be split among the participants
+increases to 20% after the Company recovers net revenues equal to 200% of its
+investment including payments made under the plan.
+In calculating the mark-to-market long-term liability, the Company
+records changes in the estimated fair value of future payment under the plan as
+compensation expense based on a number of assumptions including estimates of oil
+and gas production, oil and gas prices, recurring and workover lease operating
+expense and present value discount factors. The estimates the Company uses will
+change from year-to-year based on new information and any change in estimated
+compensation will be recorded in the period that information becomes available.
+The Company recorded total estimated compensation expense of $14.2
+million in 2003, $5.6 million in 2002 and $5.3 million in 2001 relating to the
+net profits interest bonus plan.
+401(k) Plan
+The Company has a defined contribution pension plan (the "401(k) Plan")
+that is subject to the Employee Retirement Income Security Act of 1974. The
+401(k) Plan allows eligible employees to contribute up to 60% of their base
+salaries. The Company matches each employee's contributions up to 6% of the
+employee's base salary and may also make additional contributions at its
+discretion. The Company's contributions to the 401(k) Plan were $746,000,
+$621,000, and $559,000 for the years ended December 31, 2003, 2002 and 2001,
+respectively. No discretionary contributions were made by the Company to the
+401(k) Plan in any of these three years.
+Employee Stock Purchase Plan
+Under the St. Mary Land & Exploration Company Employee Stock
+Purchase Plan ("the ESPP"), eligible employees may purchase shares of the
+Company's common stock through payroll deductions of up to 15% of eligible
+compensation. The purchase price of the stock is 85% of the lower of the fair
+market value of the stock on the first or last day of the purchase period, and
+shares issued under the ESPP are restricted for a period of 18 months. The ESPP
+is intended to qualify under Section 423 of the Internal Revenue Code. The
+Company has set aside 1,000,000 shares of its common stock to be available for
+issuance under the ESPP. In 2003, 2002 and 2001 shares issued under the ESPP
+totaled 16,994, 18,217, and 29,772, respectively. Total proceeds to the Company
+F-21
+for the issuance of these shares were $375,000, $344,000, and $575,000 in 2003,
+2002 and 2001, respectively. The Company recorded compensation expense of $-0-,
+$21,000, and $20,000 in 2003, 2002 and 2001, respectively, due to nonqualified
+dispositions of stock acquired by employees under the ESPP.
+Stock Option Plans
+The Company established a Stock Option Plan and an Incentive Stock
+Option Plan (collectively, the "Option Plans"). The Option Plans grant options
+to purchase shares of the Company's common stock to eligible employees,
+contractors, and current and former members of the Board of Directors. In 2003
+the stockholders approved an increase in the number of shares of the Company's
+common stock reserved for issuance under the Option Plans from 4,300,000 shares
+to 5,600,000 shares. All options granted to date under the Option Plans have
+been granted at exercise prices equal to the respective market prices of the
+Company's common stock on the grant dates. There were 839,934 shares available
+for grant under the Option Plans as of December 31, 2003.
+F-22
+A summary of activity associated with the Company's Option Plans,
+during the last three years follows:
+For the Years Ended December 31,
+--------------------------------------------------------------------------------
+2003 2002 2001
+------------------------- ------------------------- ---------------------------
+Weighted Weighted Weighted
+Average Average Average
+Exercise Exercise Exercise
+Shares Price Shares Price Shares Price
+------------- ----------- ------------ ------------ ------------- ------------
+Outstanding, start of year 3,061,566 $ 21.34 2,151,675 $ 19.42 1,986,124 $ 18.95
+Granted 858,431 26.70 1,109,541 23.55 397,009 18.86
+Exercised (245,019) 12.88 (177,085) 11.44 (187,810) 11.57
+Forfeited (149,850) 24.00 (22,565) 25.08 (43,648) 26.00
+------------- ------------ -------------
+Outstanding, end of year 3,525,128 23.12 3,061,566 21.34 2,151,675 19.42
+============= ============ =============
+Exercisable, end of year 2,441,246 22.36 1,944,382 19.79 1,418,404 17.09
+============= ============ =============
+Weighted average fair
+value of options granted
+during the year $ 12.28 $ 10.77 $ 8.36
+============= ============ =============
+A summary of additional information related to the options outstanding
+as of December 31, 2003 follows:
+Options Outstanding Options Exercisable
+----------------------------------------------- ----------------------------
+Weighted
+Average Weighted Weighted
+Remaining Average Average
+Range of Number Contractual Exercise Number Exercise
+Exercise Prices Outstanding Life Price Exercisable Price
+------------------------ --------------- -------------- -------------- ------------- -------------
+$ 9.25 - $ 9.99 170,439 5.0 years $ 9.25 170,439 $ 9.25
+10.00 - 13.33 454,256 5.0 years 12.03 454,256 12.03
+13.34 - 16.66 185,759 6.9 years 15.69 147,301 15.63
+16.67 - 19.99 87,689 4.0 years 17.50 87,689 17.50
+20.00 - 23.33 640,258 8.2 years 22.16 354,111 21.76
+23.34 - 26.66 911,292 9.1 years 24.73 452,938 24.57
+26.67 - 29.99 463,963 9.8 years 27.83 163,040 27.66
+30.00 - 33.31 611,472 6.9 years 33.31 611,472 33.31
+--------------- -------------
+Total 3,525,128 7.7 years 23.12 2,441,246 22.36
+=============== =============
+SFAS No. 123 establishes a fair value method of accounting for
+stock-based compensation plans through either recognition or disclosure. The
+Company accounts for stock-based compensation under APB No. 25 and has elected
+to adopt SFAS No. 123 through compliance with the disclosure requirements set
+forth in the Statement. Because the exercise price of the Company's employee
+stock options equals the market price of the underlying stock on the date of
+grant, no compensation expense is recognized under APB No. 25. Pro forma
+information regarding net income and earnings per share is required by SFAS No.
+123 and has been determined as if the Company had accounted for its employee
+stock options under the fair value method of that Statement. This information is
+prominently disclosed in Note 1-Summary of Significant Accounting Policies.
+F-23
+The fair value of options is measured at the date of grant using the
+Black-Scholes option-pricing model. The fair values of options granted in 2003,
+2002 and 2001 were estimated using the following weighted-average assumptions:
+2003 2002 2001
+--------------- -------------- --------------
+Risk free interest rate 3.6% 3.8% 4.4%
+Dividend yield 0.4% 0.4% 0.5%
+Volatility factor of the expected
+market price of the Company's
+common stock 39.9% 47.5% 49.8%
+Expected life of the options (in years) 7.0 5.9 4.8
+The Black-Scholes option valuation model was developed for use in
+estimating the fair value of traded options that have no vesting restrictions
+and are fully transferable. In addition, option valuation models require the
+input of highly subjective assumptions including the expected stock price
+volatility. As the Company's employee stock options have characteristics
+significantly different from those of traded options, and because changes in the
+subjective input assumptions can materially affect the fair value estimate, it
+is management's opinion that the existing models do not necessarily provide a
+reliable single measure of the fair value of St Mary's employee stock options.
+In December 2002 the FASB issued SFAS No. 148, "Accounting for
+Stock-Based Compensation - Transition and Disclosure: an amendment of FASB
+Statement No. 123." This statement provided for transition methods for adopting
+the fair value model of accounting for the issuance of stock options. The
+statement provides for three alternative adoption methods: (1) the retroactive
+method - where all prior periods are restated to reflect the expensing of all
+options granted on a retroactive basis, (2) the modified-prospective
+method-where a company begins expensing all prior and current option grants in
+the current year, and (3) the prospective method-where a company begins
+expensing all current period option grants in the current year. St. Mary is
+continuing to evaluate these adoption alternatives and ongoing FASB discussions.
+Non-Employee Director Stock Compensation Plan
+In May 2003, stockholders approved a Non-Employee Director Stock
+Compensation Plan to authorize the issuance of up to 30,000 shares of St. Mary
+common stock to non-employee directors as part of their compensation over an
+anticipated period of up to five years. The purpose of the plan is to attract,
+retain, and motivate non-employee directors. As of December 31, 2003, no shares
+have been issued under this plan.
+8. Pension Benefits
+The Company's employees participate in a non-contributory pension plan
+covering substantially all employees who meet age and service requirements (the
+"Qualified Pension Plan"). The Company also has a supplemental non-contributory
+pension plan covering certain management employees (the "Nonqualified Pension
+Plan").
+F-24
+Obligations and Funded Status
+For the Years Ended December 31,
+-------------------------------------------------
+2003 2002 2001
+------------- -------------- -------------
+(In thousands)
+Change in benefit obligations:
+Projected benefit obligation at beginning of year $ 6,330 $ 5,098 $ 3,054
+Service cost 963 442 323
+Interest cost 428 358 317
+Amendments - (46) -
+Actuarial loss 620 503 1,485
+Benefits paid (293) (25) (81)
+------------- -------------- -------------
+Projected benefit obligation at end of year $ 8,048 $ 6,330 $ 5,098
+============= ============== =============
+Change in plan assets:
+Fair value of plan assets at beginning of year $ 2,478 $ 2,042 $ 1,775
+Actual return on plan assets 608 (255) (13)
+Employer contribution 901 716 361
+Benefits paid (293) (25) (81)
+------------- -------------- -------------
+Fair value of plan assets at end of year $ 3,694 $ 2,478 $ 2,042
+============= ============== =============
+Funded status: $ (4,354) $ (3,758) $ (3,056)
+Unrecognized net actuarial loss 2,874 2,925 2,326
+Unrecognized prior service cost (15) (41) (20)
+------------- -------------- -------------
+Accrued benefit cost $ (1,495) $ (874) $ (750)
+============= ============== =============
+Amounts recognized in the consolidated balance sheet
+As of December 31,
+----------------------------------------------
+2003 2002
+--------------------- ---------------------
+(In thousands)
+Prepaid benefit cost $ - $ 140
+Accrued benefit cost (1,495) (1,015)
+Accumulated other comprehensive income (914) (1,188)
+--------------------- ---------------------
+Net amount recognized $ (2,409) $ (2,063)
+===================== =====================
+Information for pension plans with an accumulated benefit obligation in
+excess of plan assets
+As of December 31,
+-----------------------------------------
+2003 2002
+------------------- -----------------
+(In thousands)
+Projected benefit obligation $ 8,048 $ 6,330
+Accumulated benefit obligation $ 6,058 $ 4,436
+Fair value of plan assets $ 3,694 $ 2,478
+The Company's accumulated benefit obligation for the Qualified Pension
+Plan was $4.8 million at December 31, 2003 and $3.6 million at December 31,
+2002. The accumulated benefit obligation exceeds plan assets by $1.2 million.
+The tax-adjusted liability of $564,000 was recorded in other comprehensive
+income at December 31, 2003.
+F-25
+The Company's accumulated benefit obligation for the Nonqualified
+Pension Plan was $1.2 million at December 31, 2003, and $853,000 at December 31,
+2002. There are no plan assets in the Nonqualified Pension Plan due to the
+nature of the plan.
+Components of Net Periodic Benefit Cost
+For the Years Ended December 31,
+---------------------------------------------------------
+2003 2002 2001
+--------------- ------------------ --------------
+(In thousands)
+Components of net periodic benefit cost:
+Service cost $ 963 $ 442 $ 323
+Interest cost 428 358 317
+Expected return on plan assets (172) (146) (129)
+Amortization of prior service cost (25) (25) (8)
+Amortization of net actuarial loss 329 211 188
+--------------- ------------------ --------------
+Net periodic benefit cost $ 1,523 $ 840 $ 691
+=============== ================== ==============
+Prior service costs are amortized on a straight-line basis over the average
+remaining service period of active participants. Gains and losses in excess of
+10% of the greater of the benefit obligation and the market-related value of
+assets are amortized over the average remaining service period of active
+participants.
+Additional Information
+For the Years Ended December 31,
+----------------------------------------------
+2003 2002
+--------------------- ---------------------
+(In thousands)
+Increase (decrease) in minimum liability included
+in other comprehensive income, net of taxes $ (197) $ 761
+Assumptions
+Weighted average assumptions used in the measurement of the Company's
+projected benefit obligation and net periodic benefit cost are as follows:
+As of December 31,
+--------------------------------------
+2003 2002
+---------------- ----------------
+Projected benefit obligation
+Discount rate 6.3% 6.5%
+Expected return on plan assets 8.0% 8.0%
+Rate of compensation increase 3.5% 4.8%
+Net periodic benefit cost
+Discount rate 6.5% 7.3%
+Expected return on plan assets 8.0% 8.0%
+Rate of compensation increase 3.8% 4.8%
+F-26
+Plan Assets
+The Company's weighted-average asset allocation for the Qualified Plan
+is as follows:
+Target As of December 31,
+-----------------------------------
+Asset Category 2004 2003 2002
+------------------------- ---------------- ---------------- ---------------
+Equity securities 60% 61.4% 51.3%
+Debt securities 40% 38.0% 48.7%
+Other 0% 0.6% 0.0%
+---------------- ---------------
+Total 100.0% 100.0%
+================ ===============
+Equity securities do not include any shares of the Company's common
+stock for any period presented. There is no asset allocation for the
+Nonqualified Pension Plan since that plan does not have its own assets.
+Contributions
+The Company contributed $901,000, $716,000 and $361,000 to the pension
+plans in the years ended December 31, 2003, 2002 and 2001, respectively. St.
+Mary expects to contribute approximately $987,000 to the pension plans in 2004.
+Benefit Payments
+The Company made actual benefit payments of $293,000, $25,000 and
+$81,000 in the years ended December 31, 2003, 2002 and 2001, respectively.
+9. Asset Retirement Obligations
+Effective January 1, 2003, the Company adopted the provisions of SFAS
+No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally
+applies to legal obligations associated with the retirement of long-lived assets
+that result from the acquisition, construction, development and/or the normal
+operation of a long-lived asset. SFAS No. 143 requires the Company to recognize
+an estimated liability for costs associated with the abandonment of its oil and
+gas properties.
+As of January 1, 2003, the Company recognized the future cost to
+abandon oil and gas properties over the estimated economic life of the oil and
+gas properties in accordance with the provisions of SFAS No. 143. A liability
+for the fair value of an asset retirement obligation with a corresponding
+increase to the carrying value of the related long-lived asset is recorded at
+the time a well is completed or acquired. The increase in carrying value is
+included in proved oil and gas properties on the consolidated balance sheets.
+The Company depletes the amount added to proved oil & gas property costs and
+recognizes accretion expense in connection with the discounted liability over
+the remaining life of the respective oil and gas properties. Prior to the
+adoption of SFAS No. 143, the Company had recognized an abandonment liability
+for its offshore wells. These offshore liabilities were reversed upon adoption
+of SFAS No. 143, and the methodology described above was used to determine the
+liability associated with abandoning all wells, including those offshore.
+The estimated liability is based on historical experience in abandoning
+wells, estimated economic lives, external estimates as to the cost to abandon
+the wells in the future and federal, and state regulatory requirements. The
+liability is discounted using a credit-adjusted risk-free rate of approximately
+7.25%. Revisions to the liability could occur due to changes in estimated
+abandonment costs or well economic lives, or if federal or state regulators
+enact new requirements regarding the abandonment of wells.
+Upon adoption of SFAS No. 143, the Company recorded a discounted
+liability of $21.4 million, reversed the existing offshore abandonment liability
+of $9.1 million, increased property and equipment by $12.8 million, decreased
+F-27
+accumulated DD&A by $8.3 million and recognized a one-time cumulative effect
+gain of $5.4 million (net of deferred tax benefit of $3.4 million). The Company
+depletes the amount added to property costs and recognizes accretion expense in
+connection with the discounted liability over the remaining estimated economic
+lives of the respective oil and gas properties.
+As of December 31, 2003, the Company's capitalized proved oil and gas
+properties included $41.1 million of estimated salvage value, which is excluded
+from the Company's DD&A calculation.
+A reconciliation of the Company's liability for the year ended December
+31, 2003, is as follows (in thousands).
+Year Ended December 31, 2003
+-------------------------------------
+Beginning asset retirement obligation $ -
+Liability from SFAS 143 adoption 21,403
+Liabilities incurred 4,395
+Liabilities settled (3,169)
+Accretion expense 1,719
+Revision to estimated cash flows 1,137
+-------------------------------------
+Ending asset retirement obligation $ 25,485
+=====================================
+The following tables illustrate the effect on the asset retirement
+obligation liability, net income and earnings per share if the Company had
+adopted the provisions of SFAS No. 143 on January 1, 2002 and 2001,
+respectively. The pro forma amounts are calculated using current information,
+assumptions and interest rates as of January 1, 2003 (in thousands, except per
+share amounts).
+As of December 31,
+-----------------------------------------------------------------
+2002 2001
+------------------------------- -------------------------------
+Asset retirement obligation liability $ 21,829 $ 20,761
+Years Ended December 31,
+-----------------------------------------------------------------
+2002 2001
+----------------------------- -------------------------------
+Net Income
+As reported $ 27,560 $ 40,459
+Pro forma $ 26,622 $ 39,563
+Basic EPS
+As reported $ 0.99 $ 1.45
+Pro forma $ 0.96 $ 1.41
+Diluted EPS
+As reported $ 0.97 $ 1.42
+Pro forma $ 0.94 $ 1.39
+10.Derivative Financial Instruments
+The Company realized a net loss of $22.8 million from its derivative
+contracts for the year ended December 31, 2003, a net gain of $878,000 for the
+year ended December 31, 2002, and a net loss of $22.7 million for the year ended
+December 31, 2001.
+F-28
+Oil and Gas Commodity Hedges
+As of December 31, 2003, the Company has the following commodity swap
+contracts in place to hedge cash flow and reduce the impact of oil and gas price
+fluctuations:
+Gas (per MMBtu) Oil (per Bbl)
+---------------------------------------- ---------------------------------------------
+Weighted Weighted
+Contract Average Average
+Month Volumes Contract Price Volumes Contract Price
+-----
+----------------- ------------------- ----------------- -----------------------
+2004
+----------------- ------------------- ----------------- -----------------------
+January 1,544,500 $ 4.61 157,500 $ 23.71
+February 1,298,300 4.56 153,500 23.71
+March 1,293,000 4.57 174,800 24.48
+April 738,900 3.72 178,000 24.66
+May 731,600 3.72 174,800 24.67
+June 725,500 3.73 173,000 24.67
+July 722,700 3.73 172,500 24.65
+August 716,600 3.74 170,900 24.65
+September 712,400 3.74 169,300 24.64
+October 710,300 3.74 167,700 24.64
+November 620,000 3.83 165,200 24.64
+December 617,000 3.83 163,100 24.64
+----------------- ------------------- ----------------- -----------------------
+Total 2004 10,430,800 4.08 2,020,300 24.49
+----------------- ------------------- ----------------- -----------------------
+2005
+January - - 27,000 29.20
+February - - 27,000 29.20
+March - - 5,900 29.20
+----------------- ------------------- ----------------- -----------------------
+Total 2005 - - 59,900 29.20
+----------------- ------------------- ----------------- -----------------------
+----------------- ------------------- ----------------- -----------------------
+All Contracts 10,430,800 $ 4.08 2,080,200 $ 24.63
+================= =================== ================= =======================
+Oil and gas production operating revenue in the consolidated statements
+of operations for the year ended December 31, 2002, includes a non-cash gain of
+$1.7 million related to amortization of other comprehensive income from
+derivative contracts that lost effectiveness due to counterparty default.
+Derivative loss in the consolidated statements of operations for the
+year ended December 31, 2003, includes a loss of $246,000 from ineffectiveness
+related to these hedge contracts. On December 31, 2003, the estimated fair value
+of contracts designated and qualifying as cash flow hedges under SFAS No. 133
+was a net liability of $23.3 million. The Company will reclassify this amount to
+gains or losses included in oil and gas production operating revenues as the
+hedged production quantity is produced. Based on December 31, 2003, prices the
+net amount of existing unrealized after-tax loss as of December 31, 2003, to be
+reclassified from accumulated other comprehensive income to oil and gas
+production operating revenues in the next twelve months would be $14.7 million,
+net of deferred income taxes. The Company anticipates that all original
+forecasted transactions will occur by the end of the originally specified
+periods.
+Interest Rate Swaps
+In March 2002 the Company entered into a fixed-to-floating interest
+rate swap on $50.0 million of the Convertible Notes. This swap did not qualify
+for fair value hedge treatment under SFAS No. 133 and related pronouncements.
+This contract was closed out on December 3, 2002, resulting in a net realized
+gain of $3.6 million included in derivative gain in the consolidated statements
+of operations for the year ended December 31, 2002.
+In October 2003 the Company entered into fixed-to-floating interest
+rate swaps for a total notional amount of $50.0 million through March 20, 2007.
+Under the swaps St. Mary will be paid a fixed interest rate of 5.75% and will
+pay a variable interest rate of 235 basis points above the six-month LIBOR rate
+F-29
+as determined on the semi-annual settlement date. The six-month LIBOR rate on
+October 3, 2003 was 1.16%. The payment dates of the swaps match with the
+interest payment dates of the Convertible Notes.
+Convertible Note Derivative Instrument
+The Company's Convertible Notes contain a provision for payment of
+contingent interest if certain conditions are met. Under SFAS No. 133 this
+provision is considered an embedded equity-related derivative that is not
+clearly and closely related to the fair value of an equity interest and
+therefore must be treated as a separate derivative instrument. The value of the
+derivative at issuance of the Convertible Notes in March 2002 was $474,000. This
+amount was recorded as a decrease to the convertible notes payable in the
+consolidated balance sheets. Of this amount, $95,000 and $75,000 have been
+amortized through interest expense for the years ended December 31, 2003 and
+2002, respectively. Derivative loss in the consolidated statements of operations
+for the year ended December 31, 2003, and derivative gain for the year ended
+December 31, 2002, include a $40,000 net gain and a $341,000 net loss,
+respectively, from mark-to-market adjustments for this derivative.
+Summary
+The following table summarizes derivative instrument gain (loss)
+activity.
+Years Ended December 31,
+------------------------------------------------------------
+2003 2002 2001
+-------------------- ------------------ -------------------
+Derivative contract settlements included
+in oil and gas production revenues $ (22,439,000) $ (2,235,000) $ (21,102,000)
+Ineffective portion of hedges qualifying
+for hedge accounting included in
+derivative gain(loss) (246,000) (32,000) 45,000
+Non-qualified derivative contracts included
+in derivative gain (loss) (64,000) 3,220,000 (1,618,000)
+Amortization of contingent interest derivative
+through interest expense (95,000) (75,000) -
+-------------------- ------------------ -------------------
+Total $ (22,844,000) $ 878,000 $ (22,675,000)
+==================== ================== ===================
+See also Derivative Financial Instruments in Note 1 - Summary of
+Significant Accounting Policies.
+11.Disclosures about Oil and Gas Producing Activities
+Costs Incurred in Oil and Gas Producing Activities:
+Costs incurred in oil and gas property acquisition, exploration and
+development activities, whether capitalized or expensed, are summarized as
+follows:
+For the Years Ended December 31,
+-----------------------------------------------------
+2003 2002 2001
+--------------- --------------- ---------------
+(In thousands)
+Development costs $ 111,908 $ 74,376 $ 98,617
+Exploration 34,631 22,778 24,506
+Acquisitions:
+Proved 77,398 87,706 41,188
+Unproved 7,480 8,128 18,552
+--------------- --------------- ---------------
+Total before asset retirement obligation $ 231,417 $ 192,988 $ 182,863
+=============== =============== ===============
+Total including asset retirement obligation $ 236,949 $ 192,988 $ 182,863
+=============== =============== ===============
+F-30
+Oil and Gas Reserve Quantities (Unaudited):
+The reserve information as of December 31, 2003, 2002, and 2001 was
+prepared by Ryder Scott Company and St. Mary. For all years presented the
+reserve information for greater than 80 percent of the PV-10 value was prepared
+by Ryder Scott Company and St. Mary prepared the remainder. The Company
+emphasizes that reserve estimates are inherently imprecise and that estimates of
+new discoveries and undeveloped locations are more imprecise than estimates of
+established proved producing oil and gas properties. Accordingly, these
+estimates are expected to change as future information becomes available.
+Proved oil and gas reserves are the estimated quantities of crude oil,
+natural gas and natural gas liquids that geological and engineering data
+demonstrate with reasonable certainty to be recoverable in future years from
+known reservoirs under existing economic and operating conditions. Proved
+developed oil and gas reserves are those expected to be recovered through
+existing wells with existing equipment and operating methods.
+Presented below is a summary of the changes in estimated reserves of
+the Company:
+For the Years Ended December 31,
+---------------------------------------------------------------------------------------
+2003 2002 2001
+--------------------------- -------------------------- --------------------------
+Oil or Oil or Oil or
+Condensate Gas Condensate Gas Condensate Gas
+------------ ----------- ----------- ----------- ------------ ----------
+(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
+Developed and undeveloped:
+Beginning of year 36,119 274,172 23,669 241,231 20,950 225,975
+Revisions of previous
+estimate 2,856 3,904 3,611 4,696 (1,334) (16,421)
+Discoveries and extensions 3,681 69,189 1,250 32,813 3,131 59,830
+Purchases of minerals in
+place 11,952 41,335 10,578 38,118 3,774 13,086
+Sales of reserves (2,280) (31,913) (174) (4,522) (418) (1,748)
+Production (4,541) (49,663) (2,815) (38,164) (2,434) (39,491)
+------------ ----------- ----------- ----------- ------------ ----------
+End of year (a) 47,787 307,024 36,119 274,172 23,669 241,231
+============ =========== =========== =========== ============ ==========
+Proved developed reserves:
+Beginning of year 33,580 228,973 20,679 205,637 19,006 192,472
+============ =========== =========== =========== ============ ==========
+End of year 43,693 264,140 33,580 228,973 20,679 205,637
+============ =========== =========== =========== ============ ==========
+(a) At December 31, 2003, 2002, and 2001, includes approximately
+1,119, 1,151 and 869 MMcf, respectively, representing the
+Company's net underproduced gas balancing position.
+Standardized Measure of Discounted Future Net Cash Flows (Unaudited):
+SFAS No. 69, "Disclosures about Oil and Gas Producing Activities,"
+prescribes guidelines for computing a standardized measure of future net cash
+flows and changes therein relating to estimated proved reserves. The Company has
+followed these guidelines, which are briefly discussed below.
+Future cash inflows and future production and development costs are
+determined by applying benchmark prices and costs, including transportation,
+quality and basis differential, in effect at year-end to the year-end estimated
+quantities of oil and gas to be produced in the future. Each property we operate
+is also charged with field-level overhead in the estimated reserve calculation.
+Estimated future income taxes are computed using current statutory income tax
+rates, including consideration for estimated future statutory depletion. The
+resulting future net cash flows are reduced to present value amounts by applying
+a 10% annual discount factor.
+Future operating costs are determined based on estimates of
+expenditures to be incurred in developing and producing the proved oil and gas
+reserves in place at the end of the period, using year-end costs and assuming
+continuation of existing economic conditions, plus Company overhead incurred by
+the central administrative office attributable to operating activities.
+F-31
+The assumptions used to compute the standardized measure are those
+prescribed by the FASB and the Securities and Exchange Commission. These
+assumptions do not necessarily reflect the Company's expectations of actual
+revenues to be derived from those reserves, nor their present worth. The
+limitations inherent in the reserve quantity estimation process, as discussed
+previously, are equally applicable to the standardized measure computations
+since these estimates are the basis for the valuation process. The following
+prices, adjusted for transportation, quality and basis differentials, were used
+in the calculation of the standardized measure:
+2003 2002 2001
+----------- ---------- ----------
+Gas (per Mcf) $ 5.70 $ 4.21 $ 2.50
+Oil (per Bbl) $ 31.01 $ 29.31 $ 18.11
+The following summary sets forth the Company's future net cash flows
+relating to proved oil and gas reserves based on the standardized measure
+prescribed in SFAS No. 69:
+December 31,
+------------------------------------------------------
+2003 2002 2001
+--------------- ---------------- ----------------
+(In thousands)
+Future cash inflows $ 3,232,605 $ 2,238,513 $ 1,020,948
+Future production and development costs (1,065,161) (783,991) (444,608)
+Future income taxes (735,947) (429,618) (140,271)
+--------------- ---------------- ----------------
+Future net cash flows 1,431,497 1,024,904 436,069
+10% annual discount (571,541) (443,042) (154,192)
+--------------- ---------------- ----------------
+Standardized measure of discounted
+future net cash flows $ 859,956 $ 581,862 $ 281,877
+=============== ================ ================
+The principle sources of change in the standardized measure of
+discounted future net cash flows are:
+For the Years Ended December 31,
+-----------------------------------------------------
+2003 2002 2001
+----------------- -------------- --------------
+(In thousands)
+Standard measure, beginning of year $ 581,862 $ 281,877 $ 718,484
+Sales of oil and gas produced, net of
+production costs and hedging (299,044) (137,066) (170,074)
+Net changes in prices and production costs 168,661 298,079 (820,253)
+Extensions, discoveries and other, net of
+production costs 226,181 92,227 71,265
+Purchase of minerals in place 178,264 160,089 29,267
+Development costs incurred during the year 22,763 23,802 35,736
+Changes in estimated future development costs 11,175 4,265 (8,370)
+Revisions of previous quantity estimates 45,551 49,892 (17,593)
+Accretion of discount 78,869 34,749 109,912
+Sales of reserves in place (47,270) (708) (10,548)
+Net change in income taxes (211,381) (177,335) 298,717
+Changes in timing and other 104,325 (48,009) 45,334
+----------------- -------------- --------------
+Standardized measure, end of year $ 859,956 $ 581,862 $ 281,877
+================= ============== ==============
+F-32
+12.Quarterly Financial Information (Unaudited)
+The Company's quarterly financial information for fiscal 2003 and 2002
+is as follows (in thousands, except per share amounts):
+First Second Third Fourth
+Quarter Quarter Quarter Quarter
+------------- -------------- -------------- -------------
+Year Ended December 31, 2003
+Total revenue $ 101,204 $ 103,704 $ 90,999 $ 98,027
+Less: costs and expenses 54,785 61,695 66,688 57,455
+------------- -------------- -------------- -------------
+Income from operations $ 46,419 $ 42,009 $ 24,311 $ 40,572
+Income before income taxes and cumulative
+effect of change in accounting principle $ 44,433 $ 39,986 $ 22,551 $ 39,100
+------------- -------------- -------------- -------------
+Net income $ 32,797 $ 24,317 $ 13,786 $ 24,675
+============= ============== ============== =============
+Basic earnings per common share:
+Income before cumulative effect of
+change in accounting principle $ 0.90 $ 0.77 $ 0.44 $ 0.78
+Cumulative effect of change in
+accounting principle 0.17 - - -
+------------- -------------- -------------- -------------
+Basic net income per common share $ 1.07 $ 0.77 $ 0.44 $ 0.78
+============= ============== ============== =============
+Diluted earnings per common share:
+Income before cumulative effect of
+change in accounting principle $ 0.81 $ 0.71 $ 0.41 $ 0.72
+Cumulative effect of change in
+accounting principle 0.15 - - -
+------------- -------------- -------------- -------------
+Diluted net income per common share $ 0.96 $ 0.71 $ 0.41 $ 0.72
+============= ============== ============== =============
+Dividends declared and paid per common
+share $ - $ 0.05 $ - $ 0.05
+============= ============== ============== =============
+Year Ended December 31, 2002
+Total revenue $ 42,773 $ 50,028 $ 48,335 $ 55,258
+Less: costs and expenses 38,991 33,322 35,634 42,758
+------------- -------------- -------------- -------------
+Income from operations $ 3,782 $ 16,706 $ 12,701 $ 12,500
+Income before income taxes $ 3,440 $ 15,858 $ 11,879 $ 11,402
+Net income $ 2,318 $ 10,589 $ 7,674 $ 6,979
+Basic earnings per common share:
+Income before cumulative effect of
+change in accounting principle $ 0.08 $ 0.38 $ 0.28 $ 0.25
+Cumulative effect of change in
+accounting principle - - - -
+------------- -------------- -------------- -------------
+Basic net income per common share $ 0.08 $ 0.38 $ 0.28 $ 0.25
+============= ============== ============== =============
+Diluted earnings per common share:
+Income before cumulative effect of
+change in accounting principle $ 0.08 $ 0.37 $ 0.27 $ 0.25
+Cumulative effect of change in
+accounting principle - - - -
+------------- -------------- -------------- -------------
+Diluted net income per common share $ 0.08 $ 0.37 $ 0.27 $ 0.25
+============= ============== ============== =============
+Dividends declared and paid per common
+share $ - $ 0.05 $ - $ 0.05
+============= ============== ============== =============
+F-33
+13.Subsequent Events
+On February 9, 2004, the Company repurchased from Flying J 3,380,818
+restricted shares of common stock for a total of $91.0 million. These shares
+were originally issued by St. Mary to Flying J on January 29, 2003, in
+connection with St. Mary's acquisition of oil and gas properties. In addition to
+issuing the shares in the acquisition, St. Mary loaned Flying J $71.6 million.
+Flying J used the proceeds to repay their outstanding loan balance of $71.6
+million. Accrued interest, which has not been recorded by the Company for
+financial reporting purposes due to the non-recourse nature of the loan, was
+forgiven. The net $19.4 million cash outlay was funded from the Company's
+existing cash balances and borrowings under its bank credit facility.
+The following table shows the unaudited pro forma effects on the
+summarized consolidated balance sheet if the transactions had occurred on
+December 31, 2003. The table assumes that the Company would have borrowed the
+necessary cash payment from its existing credit facility.
+Unaudited
+pro forma
+December 31, Pro forma December 31,
+2003 adjustments 2003
+------------- --------------- --------------
+(In thousands)
+Condensed Balance Sheet:
+Current assets $ 107,923 $ 107,923
+Property and equipment, net 611,287 611,287
+Other noncurrent assets 16,644 16,644
+------------- --------------
+Total Assets $ 735,854 $ 735,854
+============= ==============
+Current liabilities $ 104,822 $ 104,822
+Debt, including senior debt 110,696 $ 19,406 130,102
+Other noncurrent liabilities,
+including minority interest 129,683 129,683
+------------- --------------
+Total Liabilities 345,201 364,607
+Restricted common stock held by Flying J 71,594 (71,594) -
+Note receivable from Flying J (71,594) 71,594 -
+------------- --------------
+Total Temporary Equity - -
+------------- --------------
+Total Equity 390,653 (19,406) 371,247
+------------- --------------
+Total Liabilities and Stockholders' Equity $ 735,854 $ 735,854
+============= ==============
+Selected Share Information:
+Total common shares outstanding, net of
+treasury shares 31,623 (3,381) 28,242
+============= ==============
+F-34
+SIGNATURES
+Pursuant to the requirements of Section 13 or 15(d) of the Securities
+Exchange Act of 1934, the registrant has duly caused this report to be signed on
+its behalf by the undersigned, thereunto duly authorized.
+ST MARY LAND & EXPLORATION COMPANY
+--------------------------------------
+(Registrant)
+Date: February 27, 2004 By: /s/ MARK A HELLERSTEIN
+---------------------------------
+Mark A. Hellerstein
+Chairman of the Board of Directors,
+President and Chief Executive Officer
+POWER OF ATTORNEY
+KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature
+appears below constitutes and appoints each of Mark A. Hellerstein and David W.
+Honeyfield his or her true and lawful attorney-in-fact and agent with full power
+of substitution and resubstitution, and each with full power to act alone, for
+the undersigned and in his or her name, place and stead, in any and all
+capacities, to sign any amendments to this Annual Report on Form 10-K for the
+fiscal year ended December 31, 2003, and to file the same, with exhibits thereto
+and other documents in connection therewith, with the Securities and Exchange
+Commission, hereby ratifying and confirming all that each of said
+attorney-in-fact, or his substitute or substitutes, may do or cause to be done
+by virtue hereof.
+Pursuant to the requirements of the Securities Exchange Act of 1934,
+this report has been signed below by the following persons on behalf of the
+registrant and in the capacities and on the dates indicated.
+Signature Title Date
+--------- ----- ----
+/s/ MARK A. HELLERSTEIN Chairman of the Board
+------------------------ of Directors, President February 27, 2004
+Mark A. Hellerstein and Chief Executive Officer
+/s/ DAVID W. HONEYFIELD Vice President-Finance, February 27, 2004
+------------------------ Secretary and Treasurer
+David W. Honeyfield
+/s/ GARRY A. WILKENING Vice President-Administration February 26, 2004
+------------------------ and Controller
+Garry A. Wilkening
+Signature Title Date
+----- ----
+/s/BARBARA M. BAUMANN Director February 26, 2004
+------------------------
+Barbara M. Baumann
+/s/ LARRY W. BICKLE Director February 26, 2004
+------------------------
+Larry W. Bickle
+/s/ RONALD D. BOONE Director February 26, 2004
+------------------------
+Ronald D. Boone
+/s/ THOMAS E. CONGDON Director February 26, 2004
+------------------------
+Thomas E. Congdon
+/s/ WILLIAM J. GARDINER Director February 26, 2004
+------------------------
+William J. Gardiner
+/s/ AREND J. SANDBULTE Director February 26, 2004
+------------------------
+Arend J. Sandbulte
+/s/ JOHN M. SEIDL Director February 26, 2004
+------------------------
+John M. Seidl
\ No newline at end of file
diff --git a/raw/filings/0000893538/2003/0000893538-04-000044/filing_metadata.csv b/raw/filings/0000893538/2003/0000893538-04-000044/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..d10776fc7e6d2abd9fe04e8209db5c0fb8c3f9fe
--- /dev/null
+++ b/raw/filings/0000893538/2003/0000893538-04-000044/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000893538,SM,SM Energy Co,10-K,2004-02-27,2003-12-31,2004-02-27T20:48:01.000Z,0000893538-04-000044,asci1203_10k.htm,12/31/03 FORM 10-K,468920,0,0,https://www.sec.gov/Archives/edgar/data/893538/000089353804000044/asci1203_10k.htm,https://www.sec.gov/Archives/edgar/data/893538/000089353804000044/,2003,2003,1
diff --git a/raw/filings/0000893538/2003/0000893538-04-000044/item1.txt b/raw/filings/0000893538/2003/0000893538-04-000044/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..8c4a3b68b81b2facb3a7b230829547d7c7b4eb79
--- /dev/null
+++ b/raw/filings/0000893538/2003/0000893538-04-000044/item1.txt
@@ -0,0 +1,1077 @@
+ITEM 1. BUSINESS
+Background
+We are an independent oil and gas company engaged in the exploration,
+exploitation, development, acquisition and production of natural gas and crude
+oil. We were founded in 1908 and incorporated in Delaware in 1915. Our primary
+objective is to invest in oil and gas producing assets that result in a superior
+return on equity while preserving underlying capital, resulting in a return on
+equity to stockholders that reflects capital appreciation as well as the payment
+of cash dividends. Our operations are focused in the following five core
+operating areas in the United States:
+o the Mid-Continent region in Oklahoma and northern Texas, primarily
+in the Anadarko and Arkoma basins, with significant activity in the
+Northeast Mayfield field in Beckham County, Oklahoma;
+o the ArkLaTex region that spans northern Louisiana and portions of
+Arkansas, Mississippi and eastern Texas, with the most recent
+activity in the James Lime Horizontal trend;
+o the Gulf Coast region, including the Judge Digby field and our
+fee property in St. Mary Parish, Louisiana;
+o the Rocky Mountain region consisting of the Williston Basin in
+eastern Montana and western North Dakota and the Powder River,
+Green River and Wind River basins in Wyoming. The most recent
+activity in the Rockies includes the dolomite formations under
+the Bakken Shale; continued exploration in the Red River
+formation, most recently in the Ridgelawn field; and our
+initiation of the development of coalbed methane reserves in the
+Hanging Woman Basin; and
+o the Permian Basin in eastern New Mexico and western Texas.
+As of December 31, 2003, we had estimated proved reserves of
+approximately 47.8 MMBbl of oil and 307.0 Bcf of natural gas, or a total of
+593.7 BCFE, 89 percent of which were proved developed and 52 percent of which
+were natural gas, with a PV-10 value of $1.3 billion. This represents a 21
+percent increase in reserve volumes and a 55 percent increase in PV-10 value
+from a year earlier. For the year ended December 31, 2003, we produced 76.9 BCFE
+representing average daily production of 210.7 MMCFE per day, a 40 percent
+increase over 2002.
+We focus our resources in selected domestic basins where we believe our
+expertise in geology, geophysics and drilling and completion techniques provides
+us with competitive advantages. We have assembled a balanced program of
+low-to-medium-risk development and exploitation projects to provide the
+foundation for steady growth, including a non-conventional gas play in the Rocky
+Mountain region. In 2003, we spent $146.5 million in capital expenditures
+related to drilling activities, $77.4 million on acquisition of oil and gas
+1
+properties and $7.5 million on acquisition of leasehold.
+We measure and rank our investment decisions based on their
+risk-adjusted estimated internal rate of return and return on investment. When
+we issue stock for the acquisition of properties or a corporate entity we base
+our investment decision on the transaction's impact on net asset value per
+share.
+In the past, we have sold selected assets when we believed attractive
+prices were available, and we will continue to evaluate such opportunities in
+the future. For example, in 2003 we sold certain oil and gas properties for
+total proceeds of approximately $23.5 million, resulting in a gain for financial
+reporting purposes of $7.3 million.
+We seek to develop our existing property base and acquire acreage with
+additional potential in our core areas. From January 1, 2001, through December
+31, 2003, we participated in the drilling or recompletion of 691 gross wells
+with an average success rate of 83 percent. During that same period we added
+estimated proved reserves of 483.5 BCFE at an average finding cost of $1.27 per
+MCFE. Our average annual production replacement was 260 percent during this
+three-year period, and our production has grown from an average daily rate of
+148.2 MMCFE per day in 2001 to 210.7 MMCFE per day in 2003.
+As of December 31, 2003, we had an acreage position of 2,004,749 gross
+(1,086,367 net) acres of which 1,284,367 gross (806,326 net) acres were
+undeveloped. Our current leasehold position represents a 75 percent increase on
+a gross acre basis and a 100 percent increase on a net acre basis over 2002. In
+addition to this acreage position, we have 24,914 net acres of fee properties in
+the highly prolific St. Mary Parish of Louisiana and mineral servitudes
+representing 14,296 gross (9,534 net) acres in Louisiana.
+For 2004 we have budgeted capital expenditures of $173.4 million for
+ongoing development, exploitation and exploration programs in our core operating
+areas and $100.0 million for the acquisition of oil and gas properties.
+Our principal offices are located at 1776 Lincoln Street, Suite 700,
+Denver, Colorado 80203, and our telephone number is (303) 861-8140.
+Business Strategy
+Our objective is to build stockholder value through consistent economic
+growth in reserves and production that increase net asset value and earnings per
+share. The principal elements of our strategy are as follows:
+o Maintain Focused Geographic Operations. We focus on exploration,
+development and acquisition activities in five core operating areas
+where we have built a balanced portfolio of proved reserves,
+development drilling opportunities, leasehold and non-conventional
+gas prospects. We believe that our increased leasehold position is a
+strategic asset. Our senior technical managers, each possessing over
+20 years of experience, head up regional technical offices supported
+by centralized administration from our Denver office. We believe
+that our long-standing presence, our established networks of local
+industry relationships and our acreage holdings in our core
+operating areas provide us with a competitive advantage. We believe
+these strengths and our organizational structure will allow us to
+continue to expand our operations without the need to
+proportionately increase the number of our employees.
+2
+o Continue Exploitation and Development of Existing Properties. We use
+our comprehensive base of geological, geophysical, engineering and
+production experience in each of our core operating areas to source
+prospects for our ongoing low-to-medium-risk development and
+exploitation programs. We conduct detailed geologic studies and use
+an array of technologies and tools including 2-D and 3-D seismic
+imaging, hydraulic fracturing and reservoir stimulation techniques,
+secondary recovery and specialized logging tools to enhance the
+potential of our existing properties. In 2003 we participated in the
+drilling or recompletion of 254 gross wells with an 83 percent
+success rate.
+o Make Selective Acquisitions. We seek to make selective niche
+acquisitions of oil and gas properties that complement our existing
+operations, offer economies of scale and provide further
+development, exploitation and exploration opportunities based on
+proprietary geologic concepts. We believe that the focus on
+relatively smaller negotiated transactions where we have specialized
+geologic knowledge or operating experience has enabled us to acquire
+attractively priced and under-exploited properties. In addition, we
+will pursue corporate acquisitions that we believe will be accretive
+and are capable of being integrated into the Company. Examples of
+this type of acquisition include our 1999 Nance Petroleum
+Corporation and King Ranch Energy, Inc. acquisitions, both of which
+were accomplished with the issuance of our common stock. A more
+recent example is the January 2003 acquisition of oil and gas
+properties from Flying J. Although this transaction was not a
+corporate acquisition, we used a combination of restricted stock, a
+loan to Flying J and options on our stock. We have budgeted $100
+million for acquisitions in 2004.
+o Control Operations. We believe it is important to control geologic
+and operational decisions as well as the timing of those decisions.
+As of December 31, 2003, we operated 70 percent of our properties on
+a reserve volume basis and 66 percent on a PV-10 value basis. We are
+the operator of properties representing approximately 75 percent of
+our 2004 capital budget.
+o Maintain Financial Flexibility. Conservative use of financial
+leverage has long been a critical element of our strategy. We
+believe that maintaining a strong balance sheet is a significant
+competitive advantage that enables us to pursue acquisition and
+other opportunities, especially in weaker price environments. It
+also provides us with the financial resources to weather periods of
+volatile commodity prices or escalating costs. Our debt to total
+capitalization ratio was less than 20 percent at the end of December
+2003.
+Significant Developments Since December 31, 2002
+o 2003 Acquisition of Oil and Gas Properties from Flying J. In January
+2003 St. Mary acquired oil and gas properties in our Rocky Mountain
+region from Flying J Oil & Gas Inc. and Big West Oil & Gas
+Inc. (collectively "Flying J"). This acquisition included properties
+located in the Williston, Powder River, Wind River and Green River
+basins with 91.4 BCFE of proved reserves as of the acquisition date
+and significant undeveloped leasehold acreage. During 2003 we
+produced 2,631 MMcf of gas and 778 MBbl of oil from the properties
+acquired from Flying J. As part of the transaction, we issued
+3,380,818 shares of restricted common stock, subject to a put and
+call option agreement. In addition, we made a nonrecourse loan to
+Flying J of $71.6 million, which was secured by a pledge of the
+shares issued. This transaction was valued for financial reporting
+purposes as an acquisition of oil and gas properties in exchange for
+$71.6 million in cash and a net option valued at $1.0 million. As
+discussed below, in February 2004 we repurchased the shares and
+Flying J repaid the loan.
+3
+o Increase in 2003 Year-End Reserves. Proved reserves increased 21
+percent to 593.7 BCFE at December 31, 2003, from 490.8 BCFE at
+December 31, 2002. We added 113.0 BCFE through acquisitions,
+primarily in the Rocky Mountain region, and 91.3 BCFE from drilling
+activities. There were net upward revisions of previous reserves
+totaling 21.0 BCFE. This upward revision was the result of a 6.7
+BCFE increase from price and a 14.3 BCFE increase from performance.
+The 21 percent increase in reserves over last year is net of current
+year sales of oil and gas properties with 45.6 BCFE of reserves.
+o Mid-Continent Drilling Results. The majority of the reserve
+additions from drilling came from our Mid-Continent region and were
+primarily attributable to activity in the Northeast Mayfield area.
+This drilling activity is in the Atoka and Upper Morrow / Springer
+formations.
+o Revolving Credit Agreement. In January 2003 we entered into a new
+long-term revolving credit agreement with nine banks. The facility
+has a maximum loan amount of $300 million and is subject to periodic
+borrowing base calculations. As of the end of 2003, our borrowing
+base is $275 million and we have elected a loan commitment amount of
+$150 million. The maturity date of the facility is January 27, 2006.
+Borrowings under the facility were $11.0 million as of December 31,
+2003.
+o Coal Bed Methane Project. In December 2003, we announced that we are
+proceeding with the development of coalbed methane reserves in the
+Hanging Woman Basin located in the northern part of the Powder River
+Basin along the border between Montana and Wyoming. We have
+approximately 139,000 net lease acres in total. Our development will
+initially concentrate on approximately 65,000 net acres in Wyoming.
+We have estimated probable reserves associated with this
+development, but we have not recorded any proved reserves through
+December 31, 2003.
+o Repurchase of Shares from Flying J. In February 2004, we repurchased
+the 3,380,818 restricted shares of our common stock held by Flying J
+for $91.0 million. In connection with this transaction, Flying J
+completely repaid our $71.6 million loan to them. The $19.4 million
+net cash outlay for the share repurchase was funded from our
+existing cash balances and borrowings under our bank credit
+facility.
+Major Customers
+During 2003 sales to BP America Production Company accounted for 13.6
+percent, sales to Midcoast Energy accounted for 13.1 percent and sales to Tesoro
+Refining and Marketing accounted for 11.4 percent of our total oil and gas
+production revenue. During 2002 there were no sales to individual customers that
+accounted for more than 10 percent of our total oil and gas production revenue.
+During 2001 sales to Transok Gas Company accounted for 12.0 percent and sales to
+BP Amoco accounted for 11.3 percent of our total oil and gas production revenue.
+Employees and Office Space
+As of December 31, 2003, we had 226 full-time employees. None of our
+employees are subject to a collective bargaining agreement, and we consider our
+relations with our employees to be good. We lease approximately 47,395 square
+feet of office space in Denver, Colorado for our executive and administrative
+offices, of which 9,479 square feet is subleased. We also lease approximately
+17,318 square feet of office space in Tulsa, Oklahoma; approximately 11,740
+square feet in Shreveport, Louisiana; approximately 7,500 square feet in
+Lafayette, Louisiana; and approximately 22,160 square feet in Billings, Montana.
+4
+As of March 1, 2004, our Lafayette, Louisiana office will relocate to
+Houston, Texas. The Lafayette lease expires on November 30, 2004, and we plan to
+continue making lease payments through the term of the lease. We will lease
+approximately 11,015 square feet in Houston.
+Title to Properties
+Substantially all of our working interests are held pursuant to leases
+from third parties. A title opinion is usually obtained prior to the
+commencement of drilling operations on properties. We have obtained title
+opinions or conducted a thorough title review on substantially all of our
+producing properties and believe that we have satisfactory title to such
+properties in accordance with standards generally accepted in the oil and gas
+industry. The majority of the value of our properties is subject to a mortgage
+under our credit facility, customary royalty interests, liens for current taxes,
+and other burdens that we believe do not materially interfere with the use of or
+affect the value of such properties. We perform only a minimal title
+investigation before acquiring undeveloped properties.
+Seasonality
+Generally, but not always, the demand and price levels for natural gas
+increase during the colder winter months and decrease during the warmer summer
+months. Seasonal anomalies such as mild winters sometimes lessen this
+fluctuation. In addition, pipelines, utilities, local distribution companies and
+industrial users utilize natural gas storage facilities and purchase some of
+their anticipated winter requirements during the summer, which can lessen
+seasonal demand fluctuations.
+Competition
+The oil and gas industry is intensely competitive. This is particularly
+so in the acquisition of prospective oil and natural gas properties and oil and
+gas reserves. The foundation for a strong drilling program is our leasehold
+position. Our competitive position depends on our geological, geophysical and
+engineering expertise, our financial resources, and our ability to select,
+acquire and develop proved reserves. We believe that the locations of our
+leasehold acreage, our exploration, drilling and production capabilities and the
+experience of our management and that of our industry partners generally enable
+us to compete effectively in our core operating areas. However, we compete with
+a substantial number of major and independent oil and gas companies that have
+larger technical staffs and greater financial and operational resources than we
+do. Many of these companies not only engage in the acquisition, exploration,
+development and production of oil and natural gas reserves, but also have
+refining operations, market refined products and generate electricity. We also
+compete with other oil and natural gas companies in attempting to secure
+drilling rigs and other equipment necessary for drilling and completion of
+wells. Consequently, drilling equipment may be in short supply from time to
+time.
+Government Regulations
+Our business is subject to various federal, state and local laws and
+governmental regulations that may be changed from time to time in response to
+economic or political conditions. Matters subject to regulation include
+discharge permits for drilling operations, drilling bonds, reports concerning
+operations, the spacing of wells, unitization and pooling of properties,
+taxation and environmental protection. From time to time, regulatory agencies
+have imposed price controls and limitations on production by restricting the
+rate of flow of oil and gas wells below actual production capacity in order to
+conserve supplies of oil and gas.
+Energy Regulations. Our sales of natural gas are affected by the
+availability, terms and cost of transportation. The price and terms of access to
+pipeline transportation are subject to extensive federal and state regulation.
+5
+From 1985 to the present, several major regulatory changes have been implemented
+by Congress and the Federal Energy Regulatory Commission that affect the
+economics of natural gas production, transportation and sales. In addition, the
+FERC is continually proposing and implementing new rules and regulations
+affecting those segments of the natural gas industry that remain subject to the
+FERC's jurisdiction, most notably interstate natural gas transmission companies.
+These initiatives may also affect the intrastate transportation of gas under
+certain circumstances. The stated purpose of many of these regulatory changes is
+to promote competition among the various sectors of the natural gas industry.
+The ultimate impact of the complex rules and regulations issued by the
+FERC since 1985 cannot be predicted. In addition, many aspects of these
+regulatory developments have not become final but are still pending judicial and
+final FERC decisions. Regulations implemented by the FERC in recent years could
+result in an increase in the cost of transportation service on certain petroleum
+product pipelines. In addition, some of the FERC's more recent proposals may,
+however, adversely affect the availability and reliability of interruptible
+transportation service on interstate pipelines. Additional proposals and
+proceedings that might affect the natural gas industry are pending before
+Congress and the courts. The natural gas industry historically has been very
+heavily regulated, and there is no assurance that the less stringent regulatory
+approach recently pursued by the FERC and Congress will continue. We do not
+believe that we will be affected by any action taken that differs materially
+from other natural gas producers and marketers with whom we compete.
+Certain operations we conduct involve federal minerals that the
+Minerals Management Service administers. The MMS issues leases covering such
+lands through competitive bidding. These leases contain relatively standardized
+terms and require compliance with federal laws and detailed MMS regulations. For
+offshore operations, lessees must obtain MMS approval for exploration plans and
+development and production plans prior to the commencement of such operations.
+In addition to permits required from other agencies such as the Coast Guard, the
+Army Corps of Engineers and the Environmental Protection Agency, lessees must
+obtain a permit from the MMS prior to the commencement of drilling. Lessees must
+also comply with detailed MMS regulations governing, among other things:
+o engineering and construction specifications for offshore production
+facilities;
+o safety procedures;
+o flaring of production;
+o plugging and abandonment of Outer Continental Shelf wells;
+o calculation of royalty payments and the valuation of production for
+this purpose; and
+o removal of facilities.
+To cover the various obligations of lessees on the OCS, the MMS
+generally requires that lessees post substantial bonds or other acceptable
+assurances that such obligations will be met. The cost of such bonds or other
+surety can be substantial, and we may not be able to continue to obtain bonds or
+other surety in all cases. Under certain circumstances the MMS may require our
+operations on federal leases to be suspended or terminated.
+Many of the states in which we conduct our oil and gas drilling and
+production activities regulate such activities by requiring, among other things,
+drilling permits and bonds and reports concerning operations. The laws of these
+states also govern a number of environmental and conservation matters, including
+6
+the handling and disposing of waste material, plugging and abandonment of wells,
+restoration requirements, unitization and pooling of natural gas and oil
+properties and establishment of maximum rates of production from natural gas and
+oil wells. Some states prorate production to the market demand for oil and
+natural gas.
+Our anticipated coalbed methane gas production from the Hanging Woman
+Basin will be similar to our traditional natural gas production as to the
+physical producing facilities and the product produced. However, the subsurface
+mechanisms that allow the gas to move to the wellbore and the producing
+characteristics of coalbed methane wells are very different from traditional
+natural gas production. Unlike conventional gas wells, which require a porous
+and permeable reservoir, hydrocarbon migration and a natural structural and/or
+stratigraphic trap, the coalbed methane gas is trapped in the molecular
+structure of the coal itself until released by pressure changes resulting from
+the removal of in situ water. Frequently, coalbeds are partly or completely
+saturated with water. As the water is removed, internal pressures on the coal
+are decreased, allowing the gas to desorb from the coal and flow to the
+wellbore. Unlike traditional gas wells, new coalbed methane wells often produce
+water for several months and then, as the water production decreases, natural
+gas production increases as the coal seams de-water.
+Coalbed methane gas production in the Hanging Woman Basin requires
+state permits for the use of well-site pits and evaporation ponds for the
+disposal of produced water. Groundwater produced from the coal seams can
+generally be discharged into arroyos, surface waters, well-site pits and
+evaporation ponds without a permit if it does not exceed surface discharge
+permit levels, and meets state and federal primary drinking water standards. All
+of these disposal options require an extensive third-party water sampling and
+laboratory analysis program to ensure compliance with state permit standards.
+Where water of lesser quality is involved or the wells produce water in excess
+of the applicable volumetric permit limits, additional disposal wells would have
+to be drilled to re-inject the produced water back into deep underground rock
+formations.
+Environmental Regulations. Our operations are subject to numerous
+existing federal, state and local laws and regulations governing environmental
+quality and pollution control. These laws and regulations may require that
+permits be obtained before drilling commences, restrict the types, quantities
+and concentration of various substances that can be released into the
+environment in connection with drilling and production activities, and limit or
+prohibit drilling activities on certain lands lying within wilderness, wetlands
+and other protected areas. As a result, these laws and regulations may
+substantially increase the costs of exploring, developing or producing oil and
+gas and may prevent or delay the commencement or continuation of a project. In
+addition, these laws and regulations may impose substantial clean-up,
+remediation and other obligations in the event of any discharges or emissions in
+violation of such laws and regulations.
+To date we have not experienced any material adverse effect on our
+financial condition or results of operations from obligations under
+environmental laws and regulations. We believe that we are in substantial
+compliance with currently applicable environmental laws and regulations and that
+continued compliance with existing requirements would not have a material
+adverse impact on us.
+Risk Factors
+Risks Related to Our Business
+In addition to the other information set forth elsewhere in this Form
+10-K, the following factors should be carefully considered when evaluating St.
+Mary.
+7
+Oil and natural gas prices are volatile, and an extended decline in prices would
+hurt our profitability and financial condition.
+Our revenues, operating results, profitability, future rate of growth
+and the carrying value of our oil and gas properties depend heavily on
+prevailing market prices for oil and gas. We expect the markets for oil and gas
+to continue to be volatile. Any substantial or extended decline in the price of
+oil or gas would have a material adverse effect on our financial condition and
+results of operations. It could reduce our cash flow and borrowing capacity, as
+well as the value and the amount of our oil and gas reserves. Lower prices may
+also reduce the amount of oil and gas that we can economically produce.
+Historically, the markets for oil and gas have been volatile, and they
+are likely to continue to be volatile. Wide fluctuations in oil and gas prices
+may result from relatively minor changes in the supply of and demand for oil and
+gas, market uncertainty and other factors that are beyond our control,
+including:
+o worldwide and domestic supplies of oil and natural gas;
+o the ability of the members of the Organization of Petroleum
+Exporting Countries to agree to and maintain oil price and
+production controls;
+o political instability or armed conflict in oil or gas producing
+regions;
+o the price and level of foreign imports;
+o worldwide economic conditions;
+o marketability of production;
+o the level of consumer demand;
+o the price, availability and acceptance of alternative fuels;
+o the availability of pipeline capacity;
+o weather conditions; and
+o actions of federal, state, local and foreign authorities.
+These external factors and the volatile nature of the energy markets
+make it difficult to estimate future prices of oil and natural gas. Declines in
+oil and gas prices would reduce our revenue and could also reduce the amount of
+oil and gas that we can produce economically and, as a result, could have a
+material adverse effect on our financial condition, results of operations and
+reserves. Further, oil and gas prices do not necessarily move in tandem. Since
+approximately 52 percent of our proved reserves were natural gas reserves as of
+December 31, 2003, our financial results are slightly more affected by changes
+in natural gas prices.
+Our future success depends on our ability to replace reserves.
+Our future success depends on our ability to find, develop and acquire
+oil and gas reserves that are economically recoverable. As of December 31, 2003,
+our proved reserves would last approximately 7.7 years if produced constantly at
+the 2003 rate of production. However, our properties do not produce at a
+8
+constant rate but rather at a declining rate over time. In order to maintain
+current production rates we must locate and develop or acquire new oil and gas
+reserves to replace those being depleted by production. We may do this even
+during periods of low oil and gas prices. Without successful exploration or
+acquisition activities, our reserves, production and revenues will decline
+rapidly. In addition, approximately 11 percent of our total estimated proved
+reserves as of December 31, 2003 were undeveloped. By their nature, undeveloped
+reserves are less certain. Recovery of such reserves requires significant
+capital expenditures and successful drilling operations. We may not be able to
+find and develop or acquire sufficient additional reserves at an acceptable
+cost.
+Our producing property acquisitions carry significant risks.
+Our recent growth is due in part to, and our growth strategy relies in
+part on, the economic acquisition of producing properties. Successful
+acquisitions require an assessment of a number of factors beyond our control.
+These factors include recoverable reserves, future oil and gas prices, operating
+costs and potential environmental and other liabilities. These assessments are
+inexact and their accuracy is inherently uncertain. In connection with these
+assessments, we perform a review of the subject properties that we believe is
+generally consistent with industry practices. However, such a review will not
+reveal all existing or potential problems. In addition, our review may not
+permit us to become sufficiently familiar with the properties to fully assess
+their deficiencies and capabilities. We do not inspect every well. Even when we
+do inspect a well, we may not always discover structural, subsurface or
+environmental problems that may exist or arise.
+In connection with our acquisitions, we may not be entitled to
+contractual indemnification for preclosing liabilities, including environmental
+liabilities. Normally, we acquire interests in properties on an "as is" basis
+with limited remedies for breaches of representations and warranties. In
+addition, competition for producing oil and gas properties is intense and many
+of our competitors have financial and other resources substantially greater than
+those available to us. Therefore, we may not be able to acquire oil and gas
+properties that contain economically recoverable reserves or we may not be able
+to acquire such properties at acceptable prices.
+Additionally, significant acquisitions can change the nature of our
+operations and business depending upon the character of the acquired properties,
+which may have substantially different operating and geological characteristics
+or be in different geographic locations than our existing properties. While it
+is our current intention to continue to concentrate on acquiring properties with
+development, exploitation and exploration potential located in our five core
+operating areas, we may in the future decide to pursue acquisitions of
+properties located in other geographic regions. To the extent that such acquired
+properties are substantially different than our existing properties, our ability
+to efficiently realize the expected economic benefits of such transactions may
+be limited.
+We may not be able to successfully integrate future property or corporate
+acquisitions.
+We seek to make selective niche acquisitions of oil and gas properties,
+and we will pursue corporate acquisitions that we believe will be accretive.
+However, integrating acquired properties and businesses involves a number of
+special risks. These risks include the possibility that management may be
+distracted from normal business concerns by the need to integrate operations and
+systems and in retaining and assimilating additional employees. Any of these or
+other similar risks could lead to potentially adverse short-term or long-term
+effects on our operating results. We may not be able to obtain adequate funds
+for future property or corporate acquisitions, successfully integrate our future
+property or corporate acquisitions or we may not realize any of the anticipated
+benefits of the acquisitions.
+9
+Substantial capital is required to replace and grow reserves.
+We make, and will continue to make, substantial expenditures to find,
+acquire, develop and produce oil and natural gas reserves. Our capital
+expenditures for oil and gas properties were $231.4 million for 2003 and $193.0
+million during 2002. We have budgeted total capital expenditures of $273.4
+million in 2004. With the cash provided by operating activities and borrowings
+under our credit facility, we believe we will have sufficient cash to fund
+budgeted capital expenditures in 2004. If additional development or attractive
+acquisition opportunities arise, we may consider other forms of financing,
+including the public offering or private placement of equity or debt securities.
+However, if oil and gas prices decrease or we encounter operating difficulties
+that result in our cash flow from operations being less than expected, we may
+have to reduce the capital we can spend in future years unless we raise
+additional funds through debt or equity financing. Debt or equity financing,
+cash generated by operations or borrowing capacity may not be available to us in
+sufficient amounts or on acceptable terms to meet these requirements.
+o Future cash flows and the availability of financing will be
+subject to a number of variables, such as:
+o our success in locating and producing new reserves;
+o the level of production from existing wells;
+o prices of oil and natural gas;
+o lease operating expense, including workovers and taxes; and
+o administrative expense.
+Issuing equity securities to satisfy our financing requirements could
+cause substantial dilution to existing stockholders. Debt financing could lead
+to:
+o a substantial portion of our operating cash flow being dedicated to
+the payment of principal and interest;
+o us being more vulnerable to competitive pressures and economic
+downturns; and
+o restrictions on our operations.
+If our revenues were to decrease due to lower oil and natural gas
+prices, decreased production or other reasons, and if we could not obtain
+capital through our credit facility or otherwise, our ability to execute our
+development plans, replace our reserves or maintain production levels could be
+greatly limited.
+We could incur substantial additional loans, which could negatively impact our
+financial condition, results of operations and business prospects.
+As of December 31, 2003, we had approximately $111.0 million in
+outstanding loans, including $100.0 million outstanding under our 5.75% Senior
+Convertible Notes due 2022. Our level of debt could have important consequences
+on our operations, including:
+10
+o making it more difficult for us to satisfy our debt obligations
+and, if we fail to comply with the requirements of any of our debt
+obligations, possibly resulting in an event of default;
+o requiring us to dedicate a substantial portion of our cash flow
+from operations to required payments on debt, thereby reducing the
+availability of cash flow for working capital, capital
+expenditures and other general business activities;
+o limiting our ability to obtain additional financing in the future
+for working capital, capital expenditures and other general
+business activities;
+o limiting our flexibility in planning for, or reacting to, changes in
+our business and the industry in which we operate;
+o detracting from our ability to withstand successfully a downturn in
+our business or the economy generally; and
+o placing us at a competitive disadvantage against other less
+leveraged competitors.
+The occurrence of any one of these events could have a material adverse effect
+on our business, financial condition, results of operations and business
+prospects.
+The indenture for our Convertible Notes does not limit our ability to
+incur additional debt. We may therefore incur additional debt, including secured
+debt under our bank credit facility or otherwise, in order to make future
+acquisitions or to develop our properties. A higher level of debt increases the
+risk that we may default on our debt obligations. We may not be able to generate
+sufficient cash flow to pay the interest on our debt, and future working
+capital, borrowings or equity financing may not be available to pay or refinance
+such debt.
+In addition, our credit facility borrowing base is subject to periodic
+borrowing base redeterminations. We could be forced to repay a portion of our
+bank borrowings due to redeterminations of our borrowing base. We may not have
+sufficient funds to make such repayments. If we do not have sufficient funds and
+are otherwise unable to negotiate renewals of our borrowing or arrange new
+financing, we may have to sell significant assets. Any such sale could have a
+material adverse effect on our business and financial results.
+We may not be able to obtain bank credit facility borrowing base
+redeterminations that adequately meet our anticipated financing needs.
+Our long-term revolving credit facility with a group of banks has a
+maximum loan amount of $300 million. The amount actually available from time to
+time depends on a borrowing base that the lenders periodically redetermine based
+on the value of our oil and gas properties and other assets. In October 2003 the
+banks conducted their normal semi-annual borrowing base redetermination that
+resulted in a borrowing base of $275 million. Since we pay commitment fees based
+on the unused portion of the borrowing base, we elected to retain a total loan
+commitment amount under the facility of $150 million to correspond with our
+projected funding requirements.
+Our next borrowing base redetermination is scheduled to occur by the
+end of April 2004. The banks may not agree to a borrowing base redetermination
+that is adequate for our financing needs at that time.
+11
+If oil and gas prices decrease or exploration efforts are unsuccessful, we may
+be required to take additional writedowns.
+There is a risk that we will be required to write down the carrying
+value of our oil and gas properties. This could occur when oil and gas prices
+are low or if we have substantial downward adjustments to our estimated proved
+reserves, increases in our estimates of development costs or deterioration in
+our exploration results.
+We follow the successful efforts accounting method. All property
+acquisition costs and costs of exploratory and development wells are capitalized
+when incurred, pending the determination of whether proved reserves have been
+discovered. If proved reserves are not discovered with an exploratory well, the
+costs of drilling the well are expensed. All geological and geophysical costs on
+exploratory prospects are expensed as incurred. The capitalized costs of our oil
+and gas properties, on a field-by-field basis, may not exceed the estimated
+future net cash flows of that field. If capitalized costs exceed future net
+revenues we write down the costs of each such field to our estimate of fair
+market value. Unproved properties are evaluated at the lower of cost or fair
+market value. This type of charge will not affect our cash flow from operating
+activities, but it will reduce the book value of our stockholders' equity. We
+review the carrying value of our properties quarterly, based on prices in effect
+as of the end of each quarter or as of the time of reporting our results. Once
+incurred, a writedown of oil and gas properties is not reversible at a later
+date even if oil or gas prices increase. St. Mary incurred impairment and
+abandonment charges on proved and unproved properties of $4.0 million, $2.4
+million and $4.7 million in 2003, 2002 and 2001, respectively.
+Estimates of oil and gas reserves are not precise.
+This report and other SEC filings by us contain estimates of our proved
+oil and gas reserves and the estimated future net revenues from those reserves.
+Actual results will likely vary from amounts estimated, and any significant
+negative variance could have a material adverse effect on our future results of
+operations.
+Reserve estimates are based on various assumptions, including
+assumptions required by the SEC relating to oil and gas prices, drilling and
+operating expenses, capital expenditures, taxes and availability of funds. The
+process of estimating reserves is complex. This process requires significant
+decisions and assumptions in the evaluation of available geological,
+geophysical, engineering and economic data for each reservoir. Therefore, these
+estimates are not precise. However, the likelihood of recovery of these reserves
+is considered more likely than not.
+Actual future production, oil and gas prices, revenues, taxes,
+development expenditures, operating expenses and quantities of recoverable oil
+and gas reserves will most likely vary from those estimated. Any significant
+variance could materially affect the estimated quantities and present value of
+reserves disclosed by us. In addition, we may adjust estimates of proved
+reserves to reflect production history, results of exploration and development,
+prevailing oil and gas prices and other factors, many of which are beyond our
+control.
+As of December 31, 2003, approximately 11 percent of our estimated
+proved reserves were proved undeveloped. Estimation of proved undeveloped
+reserves and proved developed non-producing reserves is nearly always based on
+volumetric calculations rather than the performance data used to estimate
+producing reserves. Recovery of proved undeveloped reserves requires significant
+capital expenditures and successful drilling operations. Production revenues
+from proved non-producing reserves will not be realized until some time in the
+future. The reserve data assumes that we will make significant capital
+expenditures to develop our reserves. Although we have prepared estimates of our
+reserves and the costs associated with these reserves in accordance with
+12
+industry standards, these estimated costs may not be accurate, development may
+not occur as scheduled and actual results may not be as estimated.
+You should not construe the present value of future net reserves, or
+PV-10, as the current market value of the estimated oil and natural gas reserves
+attributable to our properties. Management has based the estimated discounted
+future net cash flows from proved reserves on prices and costs as of the date of
+the estimate, in accordance with applicable regulations, whereas actual future
+prices and costs may be materially higher or lower. For example, values of our
+reserves as of December 31, 2003, were estimated using a calculated weighted
+average sales price of $31.01 per barrel of oil (NYMEX) and $5.70 per Mcf of gas
+(Gulf Coast spot price), after adjustment for transportation, quality and basis
+differentials. During 2003 our monthly average realized gas prices were as high
+as $9.28 per Mcf and as low as $4.49 per Mcf. For the same period our monthly
+average realized oil prices were as high as $35.73 per Bbl and as low as $28.07
+per Bbl. Many factors will affect actual future net cash flows, including:
+o the amount and timing of actual production,
+o supply and demand for oil and natural gas,
+o curtailments or increases in consumption by oil and natural gas
+purchasers, and
+o changes in governmental regulations or taxation.
+The timing of the production of oil and natural gas properties and of
+the related expenses affects the timing of actual future net cash flows from
+proved reserves and thus their actual present value. In addition, the 10 percent
+discount factor, which we are required to use to calculate PV-10 for reporting
+purposes, is not necessarily the most appropriate discount factor given actual
+interest rates and risks to which our business or the oil and natural gas
+industry in general are subject. As a result, our actual future net cash flows
+could be materially different from the estimates included in this report.
+Our industry is highly competitive.
+Major oil companies, independent producers, and institutional and
+individual investors are actively seeking oil and gas properties throughout the
+world, along with the equipment, labor and materials required to operate
+properties. Shortages for equipment, labor or materials may result in increased
+costs or the inability to obtain such resources as needed. Many of our
+competitors have financial and technological resources vastly exceeding those
+available to us. Many oil and gas properties are sold in a competitive bidding
+process in which we may lack technological information or expertise available to
+other bidders. We may not be successful in acquiring and developing profitable
+properties in the face of this competition.
+Exploration and development drilling may not result in commercially productive
+reserves.
+Oil and gas drilling and production activities are subject to numerous
+risks, including the risk that no commercially productive oil or natural gas
+will be found. The cost of drilling and completing wells is often uncertain, and
+oil and gas drilling and production activities may be shortened, delayed or
+canceled as a result of a variety of factors, many of which are beyond our
+control. These factors include:
+o unexpected drilling conditions;
+13
+o pressure or irregularities in formations;
+o equipment failures or accidents;
+o adverse weather conditions;
+o shortages in experienced labor;
+o compliance with governmental requirements; and
+o shortages or delays in the availability of drilling rigs and the
+delivery of equipment.
+The prevailing prices of oil and gas also affect the cost of and the
+demand for drilling rigs, production equipment and related services.
+The wells we drill may not be productive and we may not recover all or
+any portion of our investment in such wells. The seismic data and other
+technologies we use do not allow us to know conclusively prior to drilling a
+well that oil or gas is present or may be produced economically. The cost of
+drilling, completing and operating a well is often uncertain, and cost factors
+can adversely affect the economics of a project. Drilling activities can result
+in dry wells or wells that are productive but do not produce sufficient net
+revenues after operating and other costs to cover initial drilling costs.
+Our future drilling activities may not be successful, nor can we be
+sure that our overall drilling success rate or our drilling success rate for
+activity within a particular area will not decline. Unsuccessful drilling
+activities could have a material adverse effect on our results of operations and
+financial condition. Also, we may not be able to obtain any options or lease
+rights in potential drilling locations that we identify. Although we have
+identified numerous potential drilling locations, we may not be able to
+economically produce oil or natural gas from all of them.
+Our business is subject to operating and environmental risks and hazards that
+could result in substantial losses.
+Oil and gas operations are subject to many risks, including well
+blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
+well fluids, fires, formations with abnormal pressures, pipeline ruptures or
+spills, pollution, releases of toxic gas and other environmental risks and
+hazards. If any of these types of events occurs, we could sustain substantial
+losses as a result of:
+o personal injuries or loss of life;
+o severe damage to or destruction of property, natural resources and
+equipment;
+o pollution or other environmental damage due to spills or other
+discharges of hazardous materials;
+o clean-up and remediation responsibilities and costs;
+o regulatory investigations and penalties; and/or
+o suspension of operations.
+14
+Under certain limited circumstances we may be liable for environmental
+damage caused by previous owners or operators of properties that we own, lease
+or operate. As a result, we may incur substantial liabilities to third parties
+or governmental entities, which could reduce or eliminate funds available for
+exploration, development or acquisitions or cause us to incur losses.
+We maintain insurance against some, but not all, of these potential
+risks and losses. We have limited coverage for sudden environmental damages. We
+do not believe that insurance coverage for the full potential liability that
+could be caused by sudden environmental damages or insurance coverage for
+environmental damage that occurs over time is available at a reasonable cost. In
+addition, pollution and environmental risks generally are not fully insurable.
+Further, we may elect not to obtain other insurance coverage under circumstances
+where we believe that the cost of available insurance is excessive relative to
+the risks presented. Accordingly, we may be subject to liability or may lose
+substantial portions of our properties in the event of environmental or other
+damages. If a significant accident or other event occurs and is not fully
+covered by insurance, it could have a material adverse effect on our financial
+condition and results of operations.
+Other independent oil and gas companies' limited access to capital may change
+our exploration and development plans.
+Many independent oil and gas companies have limited access to the
+capital necessary to finance their activities. As a result, some of the other
+working interest owners of our wells may be unwilling or unable to pay their
+share of the costs of projects as they become due. These problems could cause us
+to change, suspend or terminate our drilling and development plans with respect
+to the affected project.
+Hedging transactions may limit our potential gains and involve other risks.
+To manage our exposure to price risks in the marketing of our oil and
+natural gas, we enter into commodity price risk management arrangements from
+time to time with respect to a portion of our current or future production.
+While intended to reduce the effects of volatile oil and natural gas prices,
+these transactions may limit our potential gains if oil or natural gas prices
+were to rise substantially over the price established by the hedge. In addition,
+such transactions may expose us to the risk of financial loss in certain
+circumstances, including instances in which:
+o our production is less than expected;
+o the counterparties to our futures contracts fail to perform under
+the contracts; or
+o a sudden, unexpected event materially impacts oil or natural gas
+prices.
+The terms of our hedging agreements may also require that we furnish
+cash collateral, letters of credit or other forms of performance assurance in
+the event that mark-to-market calculations result in settlement obligations by
+us to the counterparties, which would encumber our liquidity and capital
+resources.
+Our industry is heavily regulated.
+Federal, state and local authorities extensively regulate the oil and
+gas industry. Legislation and regulations affecting the industry are under
+constant review for amendment or expansion, raising the possibility of changes
+that may affect, among other things, the pricing or marketing of oil and gas
+production. Noncompliance with statutes and regulations may lead to substantial
+penalties, and the overall regulatory burden on the industry increases the cost
+of doing business and, in turn, decreases profitability. These authorities
+15
+regulate various aspects of oil and gas drilling and production activities,
+including the drilling of wells (through permit and bonding requirements), the
+spacing of wells, the unitization or pooling of oil and gas properties,
+environmental matters, safety standards, the sharing of markets, production
+limitations, plugging and abandonment, and restoration. To cover the various
+obligations of leaseholders in federal waters, federal authorities generally
+require that leaseholders have substantial net worth or post bonds or other
+acceptable assurances that such obligations will be met. The cost of these bonds
+or other surety can be substantial, and we may not be able to obtain bonds or
+other surety in all cases. Under limited circumstances, federal authorities may
+require any of our operations on federal leases to be suspended or terminated.
+Any such suspension or termination could materially adversely affect our
+financial condition and results of operations.
+We must comply with complex environmental regulations.
+Our operations are subject to complex and constantly changing
+environmental laws and regulations adopted by federal, state and local
+governmental authorities where we are engaged in exploration or production
+operations. New laws or regulations, or changes to current requirements, could
+have a material adverse effect on our business. We will continue to be subject
+to uncertainty associated with new regulatory interpretations and inconsistent
+interpretations between state and federal agencies. We could face significant
+liabilities to the government and third parties for discharges of oil, natural
+gas or other pollutants into the air, soil or water, and we could have to spend
+substantial amounts on investigations, litigation and remediation. Existing
+environmental laws or regulations, as currently interpreted or enforced, or as
+they may be interpreted, enforced or altered in the future, may have a material
+adverse effect on our results of operations and financial condition. As a
+result, we may face material claims with respect to properties we own or have
+owned.
+Our business depends on transportation facilities owned by others.
+The marketability of our oil and gas production depends in part on the
+availability, proximity and capacity of pipeline systems owned by third parties.
+The unavailability of or lack of available capacity on these systems and
+facilities could result in the shutting-in of producing wells or the delay or
+discontinuance of development plans for properties. Although we have some
+contractual control over the transportation of our product, material changes in
+these business relationships could materially affect our operations. Federal and
+state regulation of oil and gas production and transportation, tax and energy
+policies, changes in supply and demand, pipeline pressures, damage to or
+destruction of pipelines and general economic conditions could adversely affect
+our ability to produce, gather and transport oil and natural gas.
+We depend on key personnel.
+Our success will continue to depend on the continued services of our
+executive officers and a limited number of other senior management and technical
+personnel with extensive experience and expertise in evaluating and analyzing
+producing oil and gas properties and drilling prospects, maximizing production
+from oil and gas properties and marketing oil and gas production. Loss of the
+services of any of these people could have a material adverse effect on our
+operations. We currently do not have employment agreements with our executive
+officers other than Mark Hellerstein, our Chief Executive Officer. We do not
+carry any key person life insurance policies.
+Ownership of working interests, royalty interests and other interests by a
+director and some of our officers may create conflicts of interest.
+As a result of their prior employment with another company with which
+St. Mary engaged in a number of transactions, Ronald D. Boone, a director of St.
+Mary, and two vice presidents of St. Mary own royalty interests in a number of
+St. Mary's properties, which were earned as part of the prior employer's
+employee benefit programs. Those persons have no royalty participation in any
+16
+St. Mary properties acquired or developed subsequent to the beginning of their
+employment with St. Mary.
+Mr. Boone also owns 25 percent of Princeton Resources LLC, which owns
+the oil and gas working interests that he acquired as a result of his prior
+employment. Although Mr. Boone does not manage this entity, he may participate
+in any investment decisions made by it.
+As a result of these transactions and relationships, conflicts of
+interest may exist between these persons and us. Although these persons owe
+fiduciary duties to our stockholders and to us, conflicts of interest may not
+always be resolved in our favor.
+Risks Related to Our Common Stock
+The price of our common stock may fluctuate significantly, which may result in
+losses for investors.
+The market price of our common stock has been volatile. From January 1,
+2002, to February 20, 2004, the last daily sale price of our common stock
+reported by the New York Stock Exchange or the NASDAQ National Market ranged
+from a low of $18.75 per share to a high of $30.70 per share. We expect our
+stock to continue to be subject to fluctuations as a result of a variety of
+factors, including factors beyond our control. These include:
+o changes in oil and natural gas prices;
+o variations in quarterly drilling, recompletions, acquisitions and operating results;
+o changes in financial estimates by securities analysts;
+o changes in market valuations of comparable companies;
+o additions or departures of key personnel; and
+o future sales of our common stock.
+We may fail to meet expectations of our stockholders or of securities
+analysts at some time in the future, and our stock price could decline as a
+result.
+Our certificate of incorporation and bylaws have provisions that discourage
+corporate takeovers and could prevent shareholders from realizing a premium on
+their investment.
+Our certificate of incorporation and bylaws contain provisions that may
+have the effect of delaying or preventing a change of control. These provisions,
+among other things, provide for noncumulative voting in the election of the
+Board of Directors and impose procedural requirements on stockholders who wish
+to make nominations for the election of Directors or propose other actions at
+stockholders' meetings. These provisions, alone or in combination with each
+other and with the rights plan described below, may discourage transactions
+involving actual or potential changes of control, including transactions that
+otherwise could involve payment of a premium over prevailing market prices to
+shareholders for their common stock
+We have a stockholder rights plan that was adopted by our Board of
+Directors in 1999. The plan is designed to enhance the board's ability to
+prevent an acquirer from depriving stockholders of the long-term value of their
+investment and to protect stockholders against attempts to acquire us by means
+of unfair or abusive takeover tactics. If the Board of Directors decides in
+accordance with its fiduciary obligations that the terms of a potential
+acquisition do not reflect the long-term value of St. Mary, the Board of
+17
+Directors could allow the holder of each outstanding share of our common stock
+other than those held by the potential acquirer to purchase one additional share
+of our common stock with a market value of twice the exercise price. This
+prospective dilution to a potential acquirer would make the acquisition
+impracticable unless the terms were improved to the satisfaction of the Board of
+Directors. The existence of the plan may impede a takeover not supported by our
+board even though such takeover may be desired by a majority of our stockholders
+or may involve a premium over the prevailing stock price.
+Our shares that are eligible for future sale may have an adverse effect on the
+price of our common stock.
+At February 20, 2004, we had 28,339,963 shares of common stock
+outstanding. Of the shares outstanding, approximately 27,156,818 shares were
+freely tradable without substantial restriction or the requirement of future
+registration under the Securities Act. Also as of that date, options to purchase
+3,431,278 shares of our common stock were outstanding, of which 2,347,985 were
+exercisable. These options are exercisable at prices ranging from $9.25 to
+$33.31 per share. Sales of substantial amounts of common stock, or a perception
+that such sales could occur, and the existence of options or warrants to
+purchase shares of commons stock at prices that may be below the then-current
+market price of the common stock could adversely affect the market price of the
+common stock and could impair our ability to raise capital through the sale of
+our equity securities.
+A director and his extended family may be able to control us.
+Thomas E. Congdon, a director and our former Chairman of the Board, and
+members of his extended family owned approximately 14.4 percent of the
+outstanding shares of our common stock as of February 20, 2004. While no formal
+arrangements exist, these extended family members may be inclined to act in
+concert with Mr. Congdon on matters related to control of St. Mary, including
+for example the election of Directors or response to an unsolicited bid to
+acquire St. Mary. Accordingly, Mr. Congdon and his family may be able to control
+or influence matters presented to our Board of Directors and stockholders.
+We may not always pay dividends on our common stock.
+The payment of future dividends remains in the discretion of the Board
+of Directors and will continue to depend on our earnings, capital requirements,
+financial condition and other factors. In addition, the payment of dividends is
+subject to covenants in our bank credit facility, including the requirement that
+we maintain certain levels of stockholder's equity. The Board of Directors may
+determine in the future to reduce the current annual dividend rate of $0.10 per
+share or discontinue the payment of dividends altogether. Our credit facility
+limits the annual per share dividend rate that we may pay to $0.20.
+Cautionary Statement about Forward-Looking Statements
+This Annual Report on Form 10-K includes certain statements that may be
+deemed to be "forward-looking statements" within the meaning of Section 27A of
+the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
+1934. All statements, other than statements of historical facts, included in
+this Form 10-K that address activities, events or developments that St. Mary's
+management expects, believes or anticipates will or may occur in the future are
+forward looking statements. Examples of forward-looking statements may include
+discussion of such matters as:
+o The amount and nature of future capital, development and exploration
+expenditures;
+18
+o The drilling of wells;
+o Reserve estimates and the estimates of both future net revenues and
+the present value of future net revenues that are included in their
+calculation;
+o Future oil and gas production estimates;
+o Repayment of debt;
+o Business strategies;
+o Expansion and growth of operations; and
+o Other similar matters such as those discussed in Management's
+Discussion and Analysis of Financial Condition and Results of
+Operations.
+These statements are based on certain assumptions and analyses made by us in
+light of our experience and our perception of historical trends, current
+conditions, expected future developments and other factors we believe are
+appropriate in the circumstances. Such statements are subject to a number of
+assumptions, risks and uncertainties, including such factors as the volatility
+and level of oil and natural gas prices, uncertainties in cash flow, expected
+acquisition benefits, production rates and reserve replacement, reserve
+estimates, drilling and operating risks, competition, litigation, environmental
+matters, the potential impact of government regulations, and other matters
+discussed under the caption "Risk Factors", many of which are beyond our
+control. Readers are cautioned that forward-looking statements are not
+guarantees of future performance and that actual results or developments may
+differ materially from those expressed or implied in the forward-looking
+statements.
+Available Information
+Our Internet website address is www.stmaryland.com. Through our
+website's financial information section we make available free of charge our
+annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on
+Form 8-K, and amendments to those reports filed with or furnished to the SEC
+under applicable securities laws. These materials are made available as soon as
+reasonably practical after we electronically file such material with, or furnish
+it to, the SEC.
+We also make available through our website's corporate governance
+section our corporate governance guidelines, code of business conduct and
+ethics, and the charters for our Board of Directors' audit committee,
+compensation committee, executive committee and nominating and corporate
+governance committee. These documents are also available in print to any
+stockholder who requests them. Requests for these documents may be submitted to:
+St. Mary Land & Exploration Company
+Investor Relations
+1776 Lincoln Street, Suite 700
+Denver, Colorado 80203
+Telephone: (303) 863-4322
+Information on our website is not incorporated by reference into this
+Annual Report on Form 10-K and should not be considered part of this document.
+19
+Glossary
+The terms defined in this section are used throughout this Annual
+Report on Form 10-K.
+2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a
+two-dimensional cross-section of the subsurface.
+3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a
+three-dimensional picture of the subsurface.
+Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
+reference to oil or other liquid hydrocarbons.
+Bcf. Billion cubic feet, used herein in reference to natural gas.
+BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using
+the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+Behind pipe reserves. Estimated net proved reserves in a formation in which
+production casing has already been set in the wellbore but has not been
+perforated and production tested.
+BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio
+of six Mcf of gas (including gas liquids) to one Bbl of oil.
+Development well. A well drilled within the proved area of an oil or gas
+reservoir to the depth of a stratigraphic horizon known to be productive in an
+attempt to recover proved undeveloped reserves.
+Dry hole. A well found to be incapable of producing either oil or gas in
+sufficient quantities to justify completion as an oil or gas well.
+Estimated net proved reserves. The estimated quantities of oil, gas and gas
+liquids which geological and engineering data demonstrate with reasonable
+certainty to be recoverable in future years from known reservoirs under existing
+economic and operating conditions.
+Exploratory well. A well drilled to find and produce oil or gas in an unproved
+area, to find a new reservoir in a field previously found to be productive of
+oil or gas in another reservoir or to extend a known reservoir.
+Fee land. The most extensive interest that can be owned in land, including
+surface and mineral (including oil and gas) rights.
+Finding cost. Expressed in dollars per BOE or MCFE. Finding costs are calculated
+by dividing the amount of total capital expenditures for oil and gas activities
+by the amount of estimated net proved reserves added during the same period
+(including the effect on proved reserves of reserve revisions).
+Gross acres. An acre in which a working interest is owned.
+Gross well. A well in which a working interest is owned.
+Hydraulic fracturing. A procedure to stimulate production by forcing a mixture
+of fluid and proppant (usually sand) into the formation under high pressure.
+This creates artificial fractures in the reservoir rock, which increases
+permeability and porosity.
+20
+MBbl. One thousand barrels of oil or other liquid hydrocarbons.
+MMBbl. One million barrels of oil or other liquid hydrocarbons.
+MBOE. One thousand barrels of oil equivalent.
+MMBOE. One million barrels of oil equivalent.
+Mcf. One thousand cubic feet.
+MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined
+using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+MMcf. One million cubic feet.
+MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined
+using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+MMBtu. One million British Thermal Units. A British Thermal Unit is the heat
+required to raise the temperature of a one-pound mass of water one degree
+Fahrenheit.
+Net acres or net wells. The sum of our fractional working interests owned in
+gross acres or gross wells.
+Net asset value per share. The result of the fair market value of total assets
+less total liabilities, divided by the total number of outstanding shares of
+common stock.
+PV-10 value. The present value of estimated future gross revenue to be generated
+from the production of estimated net proved reserves, net of estimated
+production and future development costs, using prices and costs in effect as of
+the date indicated (unless such prices or costs are subject to change pursuant
+to contractual provisions), without giving effect to non-property related
+expenses such as general and administrative expenses, debt service and future
+income tax expenses or to depreciation, depletion and amortization, discounted
+using an annual discount rate of 10 percent.
+Productive well. A well that is producing oil or gas or that is capable of
+production.
+Proved developed reserves. Reserves that can be expected to be recovered through
+existing wells with existing equipment and operating methods.
+Proved undeveloped reserves. Reserves that are expected to be recovered from new
+wells on undrilled acreage, or from existing wells where a relatively major
+expenditure is required for recompletion.
+Recompletion. The completion for production from an existing wellbore in another
+formation other than that in which the well has previously been completed.
+Reserve life. Expressed in years, represents the estimated net proved reserves
+at a specified date divided by forecasted production for the preceding 12-month
+period.
+Royalty. The share paid to the owner of mineral rights expressed as a percentage
+of gross income from oil and gas produced and sold unencumbered by expenses
+relating to the drilling, completing and operating of the affected well.
+Royalty interest. An interest in an oil and gas property entitling the owner to
+shares of oil and gas production free of costs of exploration, development and
+production.
+21
+Undeveloped acreage. Lease acreage on which wells have not been drilled or
+completed to a point that would permit the production of commercial quantities
+of oil and gas, regardless of whether such acreage contains estimated net proved
+reserves.
+Working interest. The operating interest that gives the owner the right to
+drill, produce and conduct operating activities on the property and to share in
+the production.
\ No newline at end of file
diff --git a/raw/filings/0000893538/2003/0000893538-04-000044/item13.txt b/raw/filings/0000893538/2003/0000893538-04-000044/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..9cabe0cf5df09c66c9644b401107c0f5252b7dd6
--- /dev/null
+++ b/raw/filings/0000893538/2003/0000893538-04-000044/item13.txt
@@ -0,0 +1,5 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+The information required by this Item is incorporated by reference to
+the information provided under the caption "Certain Relationships and Related
+Transactions" in St. Mary's definitive proxy statement for the 2004 annual
+meeting of stockholders to be filed within 120 days from December 31, 2003.
\ No newline at end of file
diff --git a/raw/filings/0000893538/2003/0000893538-04-000044/item9a.txt b/raw/filings/0000893538/2003/0000893538-04-000044/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..08e71ddb40e6f321e41ba3dff77c3a132c15953a
--- /dev/null
+++ b/raw/filings/0000893538/2003/0000893538-04-000044/item9a.txt
@@ -0,0 +1,21 @@
+ITEM 9A. CONTROLS AND PROCEDURES
+We maintain a system of disclosure controls and procedures that are
+designed for the purposes of ensuring that information required to be disclosed
+in our SEC reports is recorded, processed, summarized and reported within the
+time periods specified in the SEC's rules and forms, and that such information
+is accumulated and communicated to our management, including the Chief Executive
+Officer and the Vice-President - Finance, as appropriate to allow timely
+decisions regarding required disclosure.
+We carried out an evaluation, under the supervision and with the
+participation of our management, including the Chief Executive Officer and the
+Vice-President - Finance, of the effectiveness of the design and operation of
+our disclosure controls and procedures as of the end of the period covered by
+this Annual Report on Form 10-K. Based upon that evaluation, the Chief Executive
+Officer and the Vice-President - Finance concluded that our disclosure controls
+and procedures are effective for the purposes discussed above as of the end of
+the period covered by this Annual Report on Form 10-K. There was no significant
+change in our internal control over financial reporting that occurred during our
+most recent fiscal quarter that has materially affected, or is reasonably likely
+to materially affect, our internal control over financial reporting.
+57
+PART III
\ No newline at end of file
diff --git a/raw/filings/0000893538/2003/0000893538-04-000044/rp_note.txt b/raw/filings/0000893538/2003/0000893538-04-000044/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2003/0000893538-04-000044/rpt_disclosure.txt b/raw/filings/0000893538/2003/0000893538-04-000044/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..a3e66f30db9cccaf935ce454c60a549dad96ecc8
--- /dev/null
+++ b/raw/filings/0000893538/2003/0000893538-04-000044/rpt_disclosure.txt
@@ -0,0 +1,18 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+Set forth below is a description of transactions entered into between St. Mary and certain of its officers and directors during the last fiscal year. Some of
+these transactions will continue in effect and may result in conflicts of interest between St. Mary and these individuals. Although these persons owe fiduciary duties to St. Mary and its stockholders,
+we cannot assure you that conflicts of interest will always be resolved in favor of St. Mary. 
+As
+a result of their prior employment with another company with which St. Mary engaged in a number of transactions, Ronald D. Boone, a director of St. Mary, and two vice presidents of
+St. Mary own royalty interests in certain of St. Mary's properties, which were earned as part of the prior employer's employee benefit programs. One vice president also owns certain working interests
+through participation in acquisitions made by his former employer. Those persons have no royalty participation or working interest in any new St. Mary properties. 
+18 
+Mr. Boone
+also owns 25% of Princeton Energy LLC, which owns the oil and gas working interests that he acquired as a result of his prior employment. Although Mr. Boone does
+not manage this entity, he may participate in any investment decisions made by them. 
+St.
+Mary's by-laws provide that no director, officer or employee may pursue for his or her own account a business or investment opportunity if he or she has obtained
+knowledge of such opportunity through his or her affiliation with the Company. In addition, no officer or employee of St. Mary may pursue for his or her own account an oil and gas opportunity as to
+which his or her knowledge of the opportunity was not obtained through his or her affiliation with the Company unless (a) with respect to an officer of St. Mary, the officer's pursuit of the
+opportunity has been approved by the Board of Directors and (b) with respect to a non-officer of St. Mary, the employee's pursuit of the opportunity has been approved by a senior
+officer of St. Mary with full knowledge of such opportunity. These restrictions do not apply to the acquisition of less than one percent of the publicly traded stock of another company.
\ No newline at end of file
diff --git a/raw/filings/0000893538/2004/0000893538-05-000026/filing.txt b/raw/filings/0000893538/2004/0000893538-05-000026/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..1d3934d628e9f96c638a3f742488f3b7d22e8f13
--- /dev/null
+++ b/raw/filings/0000893538/2004/0000893538-05-000026/filing.txt
@@ -0,0 +1,5627 @@
+10-K
+1
+asci1204_10k.htm
+10-K 12/31/04 ST MARY LAND & EXPLORATION
+12/04 10K 
+================================================================================
+UNITED STATES
+SECURITIES AND EXCHANGE COMMISSION
+Washington, D.C. 20549
+FORM 10-K
+[ x ] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
+Act of 1934
+For the fiscal year ended December 31, 2004
+or
+[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
+Exchange Act of 1934
+Commission file number 001-31539
+ST. MARY LAND & EXPLORATION COMPANY
+(Exact name of registrant as specified in its charter)
+Delaware 41-0518430
+(State or other jurisdiction (I.R.S. Employer Identification No.)
+of incorporation or organization)
+1776 Lincoln Street, Suite 700, Denver, Colorado 80203
+------------------------------------------------------
+(Address of principal executive offices) (Zip Code)
+(303) 861-8140
+(Registrant's telephone number, including area code)
+Securities registered pursuant to Section 12(b) of the Act:
+Title of each class Name of each exchange
+on which registered
+Common Stock, $.01 par value New York Stock Exchange
+---------------------------- -----------------------
+Securities registered pursuant to Section 12(g) of the Act:
+None
+Indicate by check mark whether the registrant (1) has filed all reports required
+to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
+the preceding 12 months (or for such shorter period that the registrant was
+required to file such reports), and (2) has been subject to such filing
+requirements for the past 90 days. Yes [ x ] No [ ]
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
+of Regulation S-K is not contained herein, and will not be contained, to the
+best of registrant's knowledge, in definitive proxy or information statements
+incorporated by reference in Part III of this Form 10-K or any amendment to this
+Form 10-K. [ ]
+Indicate by check mark whether the registrant is an accelerated filer (as
+defined in Rule 12-b-2 of the Act). Yes [ x ] No [ ]
+The aggregate market value of 28,070,421 shares of voting stock held by
+non-affiliates of the registrant, based upon the closing sale price of the
+common stock on June 30, 2004, the last business day of the registrant's most
+recently completed second fiscal quarter, of $35.65 per share as reported on the
+New York Stock Exchange was $1,000,710,509. Shares of common stock held by each
+director and executive officer and by each person who owns 10 percent or more of
+the outstanding common stock or who is otherwise believed by the Company to be
+in a control position have been excluded. This determination of affiliate status
+is not necessarily a conclusive determination for other purposes.
+As of February 15, 2005, the registrant had 28,798,362 shares of common stock
+outstanding.
+DOCUMENTS INCORPORATED BY REFERENCE
+Certain information required by Items 10, 11, 12, 13 and 14 of Part III is
+incorporated by reference from portions of the registrant's definitive proxy
+statement relating to its 2004 annual meeting of stockholders to be filed within
+120 days after December 31, 2004.
+================================================================================
+TABLE OF CONTENTS
+-----------------
+ITEM PAGE
+---- ----
+PART I
+ITEM 1. BUSINESS..............................................................1
+Background........................................................1
+Business Strategy.................................................2
+Significant Developments since December 31, 2003..................3
+Major Customers...................................................5
+Employees and Office Space........................................5
+Title to Properties...............................................5
+Seasonality.......................................................5
+Competition.......................................................5
+Government Regulations............................................6
+Risk Factors......................................................8
+Cautionary Statement about Forward-Looking Statements............18
+Available Information............................................18
+Glossary.........................................................19
+ITEM 2. PROPERTIES...........................................................22
+Operations.......................................................22
+Acquisitions and Divestitures....................................25
+Reserves.........................................................26
+Production.......................................................27
+Productive Wells.................................................27
+Drilling Activity................................................28
+Acreage..........................................................29
+ITEM 3. LEGAL PROCEEDINGS....................................................30
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................30
+ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT.................................31
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
+STOCKHOLDER MATTERS..................................................32
+ITEM 6. SELECTED FINANCIAL DATA..............................................34
+i
+TABLE OF CONTENTS
+-----------------
+(Continued)
+ITEM PAGE
+---- ----
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
+CONDITION AND RESULTS OF OPERATIONS..................................36
+Overview of the Company...........................................36
+Overview of Liquidity and Capital Resources.................41
+Critical Accounting Policies and Estimates..................48
+Additional Comparative Data in Tabular Format...............52
+Comparison of Financial Results and Trends
+Between 2004 and 2003....................................53
+Comparison of Financial Results and Trends
+Between 2003 and 2002.....................................54
+Other Liquidity and Capital Resource Information............56
+Accounting Matters..........................................57
+Environmental...............................................57
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
+MARKET RISK (included with the content of ITEM 7)....................58
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..........................58
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
+ACCOUNTING AND FINANCIAL DISCLOSURE..................................58
+ITEM 9A. CONTROLS AND PROCEDURES..............................................58
+PART III
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT...................61
+ITEM 11. EXECUTIVE COMPENSATION...............................................61
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
+AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.......................61
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.......................61
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES...............................61
+PART IV
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
+REPORTS ON FORM 8-K..................................................62
+ii
+PART I
+When we use the terms "St. Mary," "we," "us" or "our," we are referring
+to St. Mary Land & Exploration Company and its subsidiaries, unless the
+context otherwise requires. We have included technical terms important to an
+understanding of our business under "Glossary". Throughout this document we make
+statements that are classified as "forward-looking". Please refer to the
+"Cautionary Statement about Forward-Looking Statements" section of this document
+for an explanation of these types of statements.
+ITEM 1. BUSINESS
+Background
+We are an independent oil and gas company engaged in the exploration,
+exploitation, development, acquisition and production of natural gas and crude
+oil. We were founded in 1908 and incorporated in Delaware in 1915. Our primary
+objective is to invest in oil and gas producing assets that result in a superior
+return on equity while preserving underlying capital, resulting in a return on
+equity to stockholders that reflects capital appreciation as well as the payment
+of cash dividends. Our operations are focused in the following five core
+operating areas in the United States:
+o the Mid-Continent region in western Arkansas, Oklahoma and
+northern Texas, primarily in the Anadarko and Arkoma basins,
+with significant activity in the Northeast Mayfield field;
+o the Rocky Mountain region consisting of the Williston Basin in
+eastern Montana and western North Dakota and the Powder River,
+Green River, Wind River and Big Horn basins in Wyoming. The
+most recent activity in the Rockies includes drilling in the
+Middle Bakken formations, continued exploration in the Red
+River formation, and the development of coalbed methane
+reserves in the Hanging Woman Basin;
+o the ArkLaTex region that spans northern Louisiana and southern
+Arkansas, Mississippi and eastern Texas, with the most recent
+activity drilling horizontal wells in the James and Pettet
+Limestones;
+o the Gulf Coast region, including the Judge Digby field and our
+fee property in St. Mary Parish, Louisiana;
+o the Permian Basin in eastern New Mexico and western Texas;
+included in this area is the Parkway Delaware Unit and the
+East Shugart Delaware Unit in New Mexico.
+As of December 31, 2004, we had estimated proved reserves of
+approximately 56.6 MMBbl of oil and 319.2 Bcf of natural gas, or a total of
+658.6 BCFE with a PV-10 value of $1.5 billion. Of these reserves, 85 percent
+were proved developed and 52 percent were crude oil. This represents an
+increase in reserve volumes of 11 percent and a 17 percent increase in PV-10
+value from a year earlier. For the year ended December 31, 2004, we produced
+75.4 BCFE representing average daily production of 206.0 MMCFE, a two percent
+decrease from 2003. Our reserve replacement in 2004 was 190 percent of
+production. Included in the proved reserve total at December 31, 2004 is 9.4
+BCFE in our coalbed methane projects in the Hanging Woman Basin and the Atlantic
+Rim field.
+We attempt to focus our resources in selected domestic basins where we
+believe our expertise in geology, geophysics and drilling and completion
+techniques provides us with competitive advantages. We have assembled a balanced
+program of low-to-medium-risk development and exploitation projects to provide
+1
+the foundation for steady growth, including non-conventional gas plays in the
+Rocky Mountain region. In 2004 we spent $228.8 million in capital expenditures
+related to drilling activities, $76.7 million on acquisition of oil and gas
+properties and $7.9 million on leasing activity.
+We measure and rank our investment decisions based on their
+risk-adjusted estimated internal rate of return and return on investment. In
+2004 all acquisitions were funded with available cash and funding from our
+revolving credit facility. When we issue stock for the acquisition of properties
+or a corporate entity, we base our investment decision primarily on the
+transaction's impact on net asset value per share.
+We divest selected non-core assets when market conditions and prices
+are attractive, and we will continue to evaluate such opportunities in the
+future. For example, in 2004 we sold certain oil and gas properties for total
+proceeds of approximately $2.8 million, resulting in a gain of $1.8 million.
+We seek to develop our existing property base and acquire acreage with
+additional potential in our core areas. From January 1, 2002, through December
+31, 2004, we participated in the drilling or recompletion of 777 gross wells
+with a success rate of 84 percent. During that same period we added estimated
+proved reserves of 537.0 BCFE at an average finding cost of $1.38 per MCFE. Our
+average annual production replacement was 259 percent during this three-year
+period, and our production has grown from an average daily rate of 150.8 MMCFE
+per day in 2002 to 206.0 MMCFE per day in 2004. Production in December 2004
+averaged 216.7 MMCFE per day.
+As of December 31, 2004, we had an acreage position of 1,969,808 gross
+(1,037,522 net) acres of which 1,184,086 gross (722,396 net) acres were
+undeveloped. Our current leasehold position represents a 2 percent decrease on a
+gross acre basis and a 5 percent decrease on a net acre basis from 2003. In
+addition to the leased acreage position, we own 24,914 net acres of fee
+properties in St. Mary Parish, Louisiana and mineral servitudes representing
+14,316 gross (9,514 net) acres in other portions of Louisiana.
+For 2005 we have budgeted capital expenditures of $293 million for
+ongoing development, exploitation and exploration programs in our core operating
+areas and $125 million for the acquisition of oil and gas properties.
+Our principal offices are located at 1776 Lincoln Street, Suite 700,
+Denver, Colorado 80203, and our telephone number is (303) 861-8140.
+Business Strategy
+Our objective is to build stockholder value through consistent economic
+growth in reserves and production that increase net asset value and earnings per
+share. The principal elements of our strategy are as follows:
+o Maintain Focused Geographic Operations. We focus on
+exploration, development and acquisition activities in five
+core operating areas where we have built a balanced portfolio
+of proved reserves, development drilling opportunities,
+leasehold, and non-conventional gas prospects. We believe that
+our significant leasehold position is a strategic asset. Our
+senior technical managers, each possessing over 15 years of
+industry experience, head up fully-staffed regional technical
+offices that are supported by centralized administration from
+our Denver office. We believe that our long-standing presence,
+our application of technology, our established networks of
+2
+local industry relationships and our acreage holdings in our
+core operating areas provide us with a competitive advantage.
+o Continue Exploitation and Development of Existing Properties.
+We use our comprehensive base of geological, geophysical,
+engineering and production experience in each of our core
+operating areas to source prospects for our ongoing
+low-to-medium-risk development and exploitation programs. We
+conduct detailed geologic studies and use an array of
+technologies and tools including 2-D and 3-D seismic imaging,
+hydraulic fracturing and reservoir stimulation techniques,
+horizontal drilling, secondary recovery and specialized
+logging tools to enhance the potential of our existing
+properties. In 2004 we participated in the drilling or
+recompletion of 368 gross wells with an 88 percent success
+rate.
+o Make Selective Acquisitions. We make selective acquisitions of
+oil and gas properties that complement our existing
+operations, offer economies of scale and provide further
+development, exploitation and exploration opportunities based
+on proprietary geologic concepts. We focus on relatively small
+transactions where we have specialized geologic knowledge or
+operating experience to enable us to acquire attractively
+priced properties. In addition, we pursue corporate
+acquisitions that we believe are accretive and capable of
+being integrated into the Company. In 2004, we acquired the
+stock of Goldmark Engineering, Inc., and in early 2005 we
+completed the acquisition of Agate Petroleum, Inc. Other
+examples of corporate acquisitions include our 1999 Nance
+Petroleum Corporation and King Ranch Energy, Inc.
+acquisitions, both of which were accomplished with the
+issuance of our common stock. The Flying J Oil & Gas Inc.
+et al. property acquisition transaction completed in 2003 was
+not a corporate acquisition. We used a combination of
+restricted stock, a loan to Flying J and options on our common
+stock to consummate this transaction. We have budgeted $125
+million for acquisitions in 2005.
+o Control Operations. We believe it is important to control
+geologic and operational decisions as well as the timing of
+those decisions. As of December 31, 2004, we operated 69
+percent of our properties on a reserve volume basis and 66
+percent on a PV-10 value basis. We are the operator of
+properties representing approximately 71 percent of our 2005
+capital budget.
+o Maintain Financial Flexibility. Conservative use of financial
+leverage has long been a critical element of our strategy. We
+believe that maintaining a strong balance sheet is a
+significant competitive advantage that enables us to pursue
+acquisition and other opportunities, especially in weaker
+price environments. It also provides us with the financial
+resources to weather periods of volatile commodity prices or
+escalating costs. Our debt to total capitalization ratio was
+22 percent at the end of December 2004.
+Significant Developments since December 31, 2003
+o 2004 Acquisition of Oil and Gas Properties. Our total
+acquisitions of proved and unproved oil and gas properties in
+2004 were $76.7 million. The two most significant acquisitions
+were the Goldmark Engineering, Inc. et al. acquisition that
+closed on November 1, 2004 for $23.3 million and the Border
+Company et al. acquisition that closed on December 15, 2004
+for $37.8 million. The primary asset acquired in the Goldmark
+transaction was the operations and majority ownership in the
+Fourbear Field, located in the Big Horn Basin of Wyoming. We
+anticipate that the development program in this field will be
+quite active in 2005 and will include infill drilling,
+recompletion of additional pay zones, workovers and the
+possible employment of enhanced recovery techniques. The
+3
+Border Company acquisition primarily included a non-operated
+interest in the very active Elm Grove Field, located in
+Northern Louisiana where we expect to participate in numerous
+development locations.
+o Coalbed Methane Development. We realized our first commercial
+production for the Hanging Woman Basin coalbed methane project
+in 2004. Our total proved reserves at Hanging Woman Basin at
+the end of 2004 were 8 BCFE. During 2004 we drilled and
+completed 57 wells. The non-operated pipeline and compression
+station connecting the wells to the main trunk line became
+operational in mid-December 2004. The 2005 capital program for
+the Hanging Woman Basin development is currently budgeted at
+$24 million. We also participated in a coalbed methane
+development project at Atlantic Rim in the Green River Basin
+of Wyoming.
+o Increase in 2004 Year-End Reserves. Proved reserves increased
+11 percent to 658.6 BCFE at December 31, 2004, from 593.7 BCFE
+at December 31, 2003. We added 52 BCFE through acquisitions,
+primarily in the Rocky Mountain and ArkLaTex regions, and 101
+BCFE from drilling activities. There were net downward
+revisions of previous reserves totaling 10 BCFE. These
+downward revisions were the combination of a 16 BCFE increase
+resulting from price adjustments and a 26 BCFE decrease due to
+performance revisions. The 11 percent increase in reserves
+over last year is net of current year sales of oil and gas
+properties of 3 BCFE.
+o Drilling Results. The majority of the reserve additions
+attributed to drilling operations came from our Rocky Mountain
+and Mid-Continent regions. The increase in the Rockies can be
+attributed primarily to continued development of the Middle
+Bakken play. This is one of the most active plays in the
+United States. Currently concentrated in Montana, the play is
+thought to extend into North Dakota. As of year end, we have
+approximately 181,000 net acres leased in Richland County,
+Montana, and McKenzie and Billings Counties, North Dakota, of
+which we believe approximately 74,000 net acres is in the
+primary trend. The Red River formation continues to result in
+reserve additions in the Rockies as we take full advantage of
+3-D seismic to identify multi-pay structures. Mid-Continent
+reserve additions were primarily from the continued
+exploitation and development of the Northeast Mayfield area,
+although the results were less significant than in the prior
+year. The finding costs resulting from the Mid-Continent area
+were higher than the Company average as a whole.
+o Repurchase of Common Stock. In February 2004, we repurchased
+3,380,818 shares of our common stock from Flying J for a total
+of $91.0 million. We originally issued these shares to Flying
+J on January 29, 2003, in connection with our acquisition of
+oil and gas properties. We also loaned Flying J $71.6 million
+in connection with the property acquisition. Flying J used the
+proceeds from the share repurchase to repay the outstanding
+loan balance. The net $19.4 million difference was funded from
+our available cash and from borrowings under our credit
+facility. The amount funded from borrowings under our credit
+facility was repaid during the second quarter of 2004. In the
+third quarter of 2004, we re-initiated our stock repurchase
+program. Since that time we have repurchased a total of
+489,300 shares of our common stock at an average cost of
+$33.39 per share. These repurchases were funded from available
+cash. As of December 31, 2004, the number of additional shares
+that may be repurchased under the program is 2,510,700.
+4
+Major Customers
+During 2004, sales to Tesoro Refining and Marketing accounted for 20
+percent of our total oil and gas production revenue. During 2003, sales to BP
+America Production Company accounted for 14 percent, sales to Midcoast Energy
+accounted for 13 percent and sales to Tesoro Refining and Marketing accounted
+for 11 percent of our total oil and gas production revenue. During 2002, there
+were no sales to individual customers that accounted for more than 10 percent of
+our total oil and gas production revenue.
+Employees and Office Space
+As of February 15, 2005, we had 256 full-time employees. None of our
+employees are subject to a collective bargaining agreement, and we consider our
+relations with our employees to be good. We lease approximately 47,400 square
+feet of office space in Denver, Colorado, for our executive and administrative
+offices, of which 9,500 square feet is subleased. We also lease approximately
+18,600 square feet of office space in Tulsa, Oklahoma; approximately 11,700
+square feet in Shreveport, Louisiana; approximately 13,700 square feet in
+Houston, Texas; and approximately 22,200 square feet in Billings, Montana.
+Title to Properties
+Substantially all of our working interests are held pursuant to leases
+from third parties. A title opinion is usually obtained prior to the
+commencement of drilling operations on properties. We have obtained title
+opinions or conducted a thorough title review on substantially all of our
+producing properties and believe that we have satisfactory title to such
+properties in accordance with standards generally accepted in the oil and gas
+industry. The majority of the value of our properties is subject to a mortgage
+under our credit facility, customary royalty interests, liens for current taxes,
+and other burdens that we believe do not materially interfere with the use of or
+affect the value of such properties. We perform only a minimal title
+investigation before acquiring undeveloped leasehold.
+Seasonality
+Generally, but not always, the demand and price levels for natural gas
+increase during the colder winter months and decrease during the warmer summer
+months. In addition, pipelines, utilities, local distribution companies and
+industrial users utilize natural gas storage facilities and purchase some of
+their anticipated winter requirements during the summer, which can lessen
+seasonal demand fluctuations. Crude oil and the demand for heating oil are also
+impacted with generally higher prices in the winter. Seasonal anomalies such as
+mild winters sometimes lessen these fluctuations.
+Competition
+The oil and gas industry is intensely competitive. This is particularly
+so in the acquisition of prospective oil and natural gas properties and oil and
+gas reserves. We believe that our leasehold position provides the foundation for
+a strong drilling program. Our competitive position also depends on our
+geological, geophysical and engineering expertise, and our financial resources.
+We believe that the location of our leasehold acreage, our exploration, drilling
+and production expertise and the experience and knowledge of our management and
+industry partners enable us to compete effectively in our core operating areas.
+Notwithstanding our talents and assets, we still face stiff competition from a
+substantial number of major and independent oil and gas companies that have
+larger technical staffs and greater financial and operational resources than we
+do. Many of these companies not only engage in the acquisition, exploration,
+development and production of oil and natural gas reserves, but also have
+5
+refining operations, market refined products and generate electricity. We also
+compete with other oil and natural gas companies in attempting to secure
+drilling rigs and other equipment necessary for drilling and completion of
+wells. Consequently, drilling equipment may be in short supply from time to
+time. Currently, access to incremental drilling equipment in certain regions is
+difficult.
+Government Regulations
+Our business is subject to various federal, state and local laws and
+governmental regulations that may be changed from time to time in response to
+economic or political conditions. Matters subject to regulation include
+discharge permits for drilling operations, drilling bonds, reports concerning
+operations, the spacing of wells, unitization and pooling of properties,
+taxation and environmental protection. From time to time, regulatory agencies
+have imposed price controls and limitations on production by restricting the
+rate of flow of oil and gas wells below actual production capacity in order to
+conserve supplies of oil and gas.
+Energy Regulations. Our sales of natural gas are affected by the
+availability, terms and cost of transportation. The price and terms of access to
+pipeline transportation are subject to extensive federal and state regulation.
+From 1985 to the present, several major regulatory changes have been implemented
+by Congress and the Federal Energy Regulatory Commission that affect the
+economics of natural gas production, transportation and sales. In addition, the
+FERC is continually proposing and implementing new rules and regulations
+affecting those segments of the natural gas industry that remain subject to the
+FERC's jurisdiction, most notably interstate natural gas transmission companies.
+These initiatives may also affect the intrastate transportation of gas under
+certain circumstances. The stated purpose of many of these regulatory changes is
+to promote competition among the various sectors of the natural gas industry.
+The ultimate impact of the complex rules and regulations issued by the
+FERC since 1985 cannot be predicted. In addition, many aspects of these
+regulatory developments have not become final but are still pending judicial and
+final FERC decisions. Regulations implemented by the FERC in recent years could
+result in an increase in the cost of transportation service on certain petroleum
+product pipelines. In addition, some of the FERC's more recent proposals may,
+however, adversely affect the availability and reliability of interruptible
+transportation service on interstate pipelines. Additional proposals and
+proceedings that might affect the natural gas industry are pending before
+Congress and the courts. The natural gas industry historically has been very
+heavily regulated, and there is no assurance that the less stringent regulatory
+approach recently pursued by the FERC and Congress will continue. We do not
+believe that we will be affected by any action taken that differs materially
+from other natural gas producers and marketers with whom we compete.
+Certain operations we conduct involve federal minerals that the
+Minerals Management Service administers. The MMS issues leases covering such
+lands through competitive bidding. These leases contain relatively standardized
+terms and require compliance with federal laws and detailed MMS regulations. For
+offshore operations, lessees must obtain MMS approval for exploration plans and
+development and production plans prior to the commencement of such operations.
+In addition to permits required from other agencies such as the Coast Guard, the
+Army Corps of Engineers and the Environmental Protection Agency, lessees must
+obtain a permit from the MMS prior to the commencement of drilling. Lessees must
+also comply with detailed MMS regulations governing, among other things:
+o engineering and construction specifications for offshore
+production facilities;
+o safety procedures;
+6
+o flaring of production;
+o plugging and abandonment of Outer Continental Shelf wells;
+o calculation of royalty payments and the valuation of
+production for this purpose; and
+o removal of facilities.
+To cover the various obligations of lessees on the OCS, the MMS
+generally requires that lessees post substantial bonds or other acceptable
+assurances that such obligations will be met. The cost of such bonds or other
+surety can be substantial, and we may not be able to continue to obtain bonds or
+other surety in all cases. Under certain circumstances the MMS may require our
+operations on federal leases to be suspended or terminated.
+Many of the states in which we conduct our oil and gas drilling and
+production activities regulate such activities by requiring, among other things,
+drilling permits and bonds and reports concerning operations. The laws of these
+states also govern a number of environmental and conservation matters, including
+the handling and disposing of waste material, plugging and abandonment of wells,
+restoration requirements, unitization and pooling of natural gas and oil
+properties and establishment of maximum rates of production from natural gas and
+oil wells. Some states prorate production to the market demand for oil and
+natural gas.
+Our anticipated coalbed methane gas production from the Hanging Woman
+Basin will be similar to our traditional natural gas production as to the
+physical producing facilities and the product produced. However, the subsurface
+mechanisms that allow the gas to move to the wellbore and the producing
+characteristics of coalbed methane wells are very different from traditional
+natural gas production. Unlike conventional gas wells, which require a porous
+and permeable reservoir, hydrocarbon migration and a natural structural and/or
+stratigraphic trap, the coalbed methane gas is trapped in the molecular
+structure of the coal itself until released by pressure changes resulting from
+the removal of in situ water. Frequently, coalbeds are partly or completely
+saturated with water. As the water is removed, internal pressures on the coal
+are decreased, allowing the gas to desorb from the coal and flow to the
+wellbore. Unlike traditional gas wells, new coalbed methane wells often produce
+water for several months and then, as the water production decreases, natural
+gas production increases as the coal seams de-water.
+Coalbed methane gas production in the Hanging Woman Basin requires
+state permits for the use of well-site pits and evaporation ponds for the
+disposal of produced water. Groundwater produced from the coal seams can
+generally be discharged into arroyos, surface waters, well-site pits and
+evaporation ponds without a permit if it does not exceed surface discharge
+permit levels, and meets state and federal primary drinking water standards. All
+of these disposal options require an extensive third-party water sampling and
+laboratory analysis program to ensure compliance with state permit standards.
+Where water of lesser quality is involved or the wells produce water in excess
+of the applicable volumetric permit limits, additional disposal wells would have
+to be drilled to re-inject the produced water back into deep underground rock
+formations.
+Environmental Regulations. Our operations are subject to numerous
+existing federal, state and local laws and regulations governing environmental
+quality and pollution control. These laws and regulations may require that
+permits be obtained before drilling commences, restrict the types, quantities
+and concentration of various substances that can be released into the
+environment in connection with drilling and production activities, and limit or
+prohibit drilling activities on certain lands lying within wilderness, wetlands
+and other protected areas, including areas containing endangered animal species.
+As a result, these laws and regulations may substantially increase the costs of
+7
+exploring, developing or producing oil and gas and may prevent or delay the
+commencement or continuation of a project. In addition, these laws and
+regulations may impose substantial clean-up, remediation and other obligations
+in the event of any discharges or emissions in violation of such laws and
+regulations.
+To date we have not experienced any material adverse effect on our
+financial condition or results of operations from obligations under
+environmental laws and regulations. We believe that we are in substantial
+compliance with currently applicable environmental laws and regulations and that
+continued compliance with existing requirements would not have a material
+adverse impact on us.
+Risk Factors
+In addition to the other information set forth elsewhere in this Form
+10-K, the following factors should be carefully considered when evaluating St.
+Mary.
+Risks Related to Our Business
+Oil and natural gas prices are volatile, and an extended decline in
+prices would hurt our profitability and financial condition.
+Our revenues, operating results, profitability, future rate of growth
+and the carrying value of our oil and gas properties depend heavily on
+prevailing market prices for oil and gas. Any substantial or extended decline in
+the price of oil or gas would have a material adverse effect on us. It could
+reduce our cash flow and borrowing capacity, as well as the value and the amount
+of our oil and gas reserves.
+Historically, the markets for oil and gas have been volatile, and they
+are likely to continue to be volatile. Wide fluctuations in oil and gas prices
+may result from relatively minor changes in the supply of and demand for oil and
+gas, market uncertainty and other factors that are beyond our control,
+including:
+o worldwide and domestic supplies of oil and natural gas;
+o the ability of the members of the Organization of Petroleum
+Exporting Countries to agree to and maintain oil price and
+production controls;
+o political instability or armed conflict in oil or gas
+producing regions;
+o worldwide economic conditions;
+o the availability of transportation facilities;
+o weather conditions; and
+o actions of governmental authorities.
+Declines in oil and gas prices would reduce our revenue and could also
+reduce the amount of oil and gas that we can produce economically and, as a
+result, could have a material adverse effect on us.
+8
+Our future success depends on our ability to replace reserves.
+Our future success depends on our ability to find, develop and acquire
+oil and gas reserves that are economically recoverable. Our properties produce
+at a declining rate over time. In order to maintain current production rates we
+must locate and develop or acquire new oil and gas reserves to replace those
+being depleted by production. We may do this even during periods of low oil and
+gas prices. In addition, competition for producing oil and gas properties is
+intense and many of our competitors have financial and other resources
+substantially greater than those available to us. Therefore, we may not be able
+to acquire oil and gas properties that contain economically recoverable reserves
+or we may not be able to acquire such properties at acceptable prices. Without
+successful exploration or acquisition activities, our reserves, production and
+revenues will decline rapidly.
+Our producing property acquisitions carry significant risks.
+Successful property acquisitions require an assessment of a number of
+factors beyond our control. These factors include recoverable reserves, future
+oil and gas prices, operating costs and potential environmental and other
+liabilities. These assessments are inexact and their accuracy is inherently
+uncertain. A customary review of subject properties will not necessarily reveal
+all existing or potential problems.
+In connection with our acquisitions, we may not be entitled to
+contractual indemnification for pre-closing liabilities, including environmental
+liabilities. Normally, we acquire interests in properties on an "as is" basis
+with limited remedies for breaches of representations and warranties.
+o Additionally, significant acquisitions can change the nature of our operations
+and business depending upon the character of the acquired properties if they
+have substantially different operating and geological characteristics or are in
+different geographic locations than our existing properties. To the extent that
+acquired properties are substantially different than our existing properties,
+our ability to efficiently realize the expected economic benefits of such
+transactions may be limited.
+We may not be able to successfully integrate future property or corporate
+acquisitions.
+Integrating acquired properties and businesses involves a number of
+special risks, including the possibility that management may be distracted from
+normal business concerns by the need to integrate operations and systems and in
+retaining and assimilating additional employees. Therefore, we may not be able
+to realize all of the anticipated benefits of the acquisitions.
+Substantial capital is required to replace and grow reserves.
+We make, and will continue to make, substantial expenditures to find,
+acquire, develop and produce oil and natural gas reserves. Our capital
+expenditures for oil and gas properties were $313 million for 2004, and we have
+budgeted total capital expenditures of $418 million in 2005. If oil and gas
+prices decrease or we encounter operating difficulties that result in our cash
+flow from operations being less than expected, we may have to reduce the capital
+we can spend unless we raise additional funds through debt or equity financing.
+Debt or equity financing, cash generated by operations or borrowing capacity may
+not be available to us in sufficient amounts or on acceptable terms to meet
+these requirements.
+9
+Future cash flows and the availability of financing will be subject to
+a number of variables, such as:
+o our success in locating and producing new reserves;
+o the level of production from existing wells; and
+o prices of oil and natural gas;
+Issuing equity securities to satisfy our financing requirements could
+cause substantial dilution to existing stockholders. Debt financing could lead
+to us being more vulnerable to competitive pressures and economic downturns.
+If our revenues were to decrease due to lower oil and natural gas
+prices, decreased production or other reasons, and if we could not obtain
+capital through our credit facility or otherwise, our ability to execute our
+development plans, replace our reserves or maintain production levels could be
+greatly limited.
+We could incur substantial additional loans, which could negatively impact our
+financial condition, results of operations and business prospects.
+As of December 31, 2004, we had $137 million in outstanding loans,
+including $100 million outstanding under our 5.75% Senior Convertible Notes due
+2022. Our level of debt could have important consequences on our operations,
+including:
+o requiring us to dedicate a substantial portion of our cash
+flow from operations to required payments on debt, thereby
+reducing the availability of cash flow for working capital,
+capital expenditures and other general business activities;
+o limiting our ability to obtain additional financing in the
+future for working capital, capital expenditures and other
+general business activities;
+o limiting our flexibility in planning for, or reacting to,
+changes in our business and the industry in which we operate;
+and
+o detracting from our ability to successfully withstand a
+downturn in our business or the economy generally.
+The occurrence of any one of these events could have a material adverse
+effect on our business, financial condition, results of operations and business
+prospects.
+We may incur additional debt, including secured debt under our credit
+facility or otherwise, in order to make future acquisitions or to develop our
+properties. We may not be able to generate sufficient cash flow to pay the
+interest on additional debt. Future working capital, borrowings or equity
+financing may not be available to pay or refinance such debt.
+In addition, our credit facility borrowing base is subject to periodic
+borrowing base redeterminations. We could be forced to repay a portion of our
+bank borrowings due to a downward redetermination of our borrowing base. We may
+not have sufficient funds to make such repayment. If we do not have sufficient
+funds and are otherwise unable to negotiate renewals of our borrowing or arrange
+new financing, we may have to sell significant assets. Any such sale could have
+a material adverse effect on our business and financial results.
+10
+We may not be able to obtain credit facility borrowing base redeterminations
+that adequately meet our anticipated financing needs.
+Our current long-term credit facility with a group of banks has a
+maximum loan amount of $300 million. The amount actually available from time to
+time depends on a borrowing base that the lenders periodically redetermine based
+on the value of our oil and gas properties and other assets. In October 2004 the
+banks conducted their normal semi-annual borrowing base redetermination that
+resulted in a borrowing base of $325 million. Since we pay commitment fees based
+on the unused portion of the borrowing base, we elected to retain a total loan
+commitment amount under the facility of $150 million to correspond with our
+projected funding requirements. Our next borrowing base redetermination is
+scheduled to occur by the end of April 2005. The banks may not agree to a
+borrowing base redetermination that is adequate for our planned financing
+requirements.
+Our long term credit facility is scheduled to expire in January 2006.
+We anticipate renegotiating the terms of our facility in the first quarter of
+2005 to ensure that we have a credit facility in place beyond the current
+expiry.
+If oil and gas prices decrease or exploration efforts are unsuccessful, we may
+be required to take additional writedowns.
+There is a risk that we will be required to write down the carrying
+value of our oil and gas properties. This could occur when oil and gas prices
+are low or if we have substantial downward adjustments to our estimated proved
+reserves, increases in our estimates of development costs or deterioration in
+our exploration results.
+We follow the successful efforts accounting method. All property
+acquisition costs and costs of exploratory and development wells are capitalized
+when incurred, pending the determination of whether proved reserves have been
+discovered. If proved reserves are not discovered with an exploratory well, the
+costs of drilling the well are expensed. All geological and geophysical costs on
+exploratory prospects and the costs of carrying and retaining unproved
+properties are expensed as incurred.
+The capitalized costs of our oil and gas properties, on a
+field-by-field basis, may not exceed the estimated future net cash flows of that
+field. If capitalized costs exceed future net revenues, we write down the costs
+of each such field to our estimate of fair market value. Unproved properties are
+evaluated at the lower of cost or fair market value. This type of charge will
+not affect our cash flow from operating activities, but it will reduce the book
+value of our stockholders' equity.
+We review the carrying value of our properties quarterly based on
+prices in effect as of the end of each quarter or as of the time of reporting
+our results. Once incurred, a writedown of oil and gas properties is not
+reversible at a later date even if oil or gas prices increase. St. Mary incurred
+impairment and abandonment charges on proved and unproved properties of $1.9
+million, $4.0 million and $2.4 million in 2004, 2003 and 2002, respectively.
+Estimates of oil and gas reserves are not precise.
+This report and other SEC filings by us contain estimates of our proved
+oil and gas reserves and the estimated future net revenues from those reserves.
+Actual results will likely vary from amounts estimated, and any significant
+negative variance could have a material adverse effect on our future results of
+operations.
+11
+Reserve estimates are based on various assumptions, including
+assumptions required by the SEC relating to oil and gas prices, drilling and
+operating expenses, capital expenditures, taxes and availability of funds. The
+process of estimating reserves is complex. This process requires significant
+decisions and assumptions in the evaluation of available geological,
+geophysical, engineering and economic data for each reservoir. These estimates
+are dependent on many variables and therefore changes often occur as these
+variables evolve and commodity prices fluctuate. However, the likelihood of
+recovery of these reserves is considered more likely than not.
+Actual future production, oil and gas prices, revenues, taxes,
+development expenditures, operating expenses and quantities of recoverable oil
+and gas reserves will most likely vary from those estimated. Any significant
+variance could materially affect the estimated quantities and present value of
+reserves disclosed by us. In addition, we may adjust estimates of proved
+reserves to reflect production history, results of exploration and development,
+prevailing oil and gas prices and other factors, many of which are beyond our
+control.
+As of December 31, 2004, approximately 15 percent of our estimated
+proved reserves were proved undeveloped. Estimation of proved undeveloped
+reserves and proved developed non-producing reserves is nearly always based on
+volumetric calculations rather than the performance data used to estimate
+producing reserves. Recovery of proved undeveloped reserves requires significant
+capital expenditures and successful drilling operations. Production revenues
+from proved developed non-producing reserves will not be realized until some
+time in the future. The reserve data assumes that we will make significant
+capital expenditures to develop our reserves. Although we have prepared
+estimates of our reserves and the costs associated with these reserves in
+accordance with industry standards, these estimated costs may not be accurate,
+development may not occur as scheduled and actual results may not occur as
+estimated.
+You should not construe the present value of future net reserves, or
+PV-10, as the current market value of the estimated oil and natural gas reserves
+attributable to our properties. Management has based the estimated discounted
+future net cash flows from proved reserves on prices and costs as of the date of
+the estimate, in accordance with applicable regulations, whereas actual future
+prices and costs may be materially higher or lower. For example, values of our
+reserves as of December 31, 2004, were estimated using a calculated weighted
+average sales price of $43.45 per barrel of oil (NYMEX) and $6.18 per Mcf of gas
+(Gulf Coast spot price). During 2004 our monthly average realized gas prices,
+excluding the effect of hedging, were as high as $7.27 per Mcf and as low as
+$4.90 per Mcf. For the same period our monthly average realized oil prices were
+as high as $51.21 per Bbl and as low as $32.26 per Bbl. Many factors will affect
+actual future net cash flows, including:
+o the amount and timing of actual production,
+o supply and demand for oil and natural gas,
+o curtailments or increases in consumption by oil and natural
+gas purchasers, and
+o changes in governmental regulations or taxation.
+The timing of the production of oil and natural gas properties and of
+the related expenses affects the timing of actual future net cash flows from
+proved reserves and thus their actual present value. In addition, the 10 percent
+discount factor, which we are required to use to calculate PV-10 for reporting
+purposes, is not necessarily the most appropriate discount factor given actual
+interest rates and risks to which our business or the oil and natural gas
+12
+industry in general are subject. As a result, our actual future net cash flows
+could be materially different from the estimates included in this report.
+Our industry is highly competitive.
+Major oil companies, independent producers, and institutional and
+individual investors are actively seeking oil and gas properties throughout the
+world, along with the equipment, labor and materials required to operate
+properties. Shortages for equipment, labor or materials may result in increased
+costs or the inability to obtain such resources as needed. Many of our
+competitors have financial and technological resources vastly exceeding those
+available to us. Many oil and gas properties are sold in a competitive bidding
+process in which we may lack technological information or expertise available to
+other bidders. We may not be successful in acquiring and developing profitable
+properties in the face of this competition.
+Exploration and development drilling may not result in commercially productive
+reserves.
+Oil and gas drilling and production activities are subject to numerous
+risks, including the risk that no commercially productive oil or natural gas
+will be found. The cost of drilling and completing wells is often uncertain, and
+oil and gas drilling and production activities may be shortened, delayed or
+canceled as a result of a variety of factors, many of which are beyond our
+control. These factors include:
+o unexpected drilling conditions;
+o pressure or irregularities in formations;
+o equipment failures or accidents; and
+o shortages or delays in the availability of drilling rigs and
+the delivery of equipment.
+The prevailing prices of oil and gas also affect the cost of and the
+demand for drilling rigs, production equipment and related services. The
+availability of drilling rigs can vary significantly from region to region at
+any particular time. Although land drilling rigs can be moved from one region to
+another in response to changes in levels of demand, an undersupply of rigs in
+any region may result in drilling delays and higher drilling costs for the rigs
+that are available in that region.
+Another significant risk inherent in our drilling plans is the need to
+obtain drilling permits from state, local and other governmental authorities.
+Delays in obtaining regulatory approvals and drilling permits, including delays
+which jeopardize our ability to realize the potential benefits from leased
+properties within the applicable lease periods, the failure to obtain a drilling
+permit for a well or the receipt of a permit with unreasonable conditions or
+costs could have a material adverse effect on our ability to explore on or
+develop our properties.
+The wells we drill may not be productive and we may not recover all or
+any portion of our investment in such wells. The seismic data and other
+technologies we use do not allow us to know conclusively prior to drilling a
+well that oil or gas is present or may be produced economically. The cost of
+drilling, completing and operating a well is often uncertain, and cost factors
+can adversely affect the economics of a project. Drilling activities can result
+in dry wells or wells that are productive but do not produce sufficient net
+revenues after operating and other costs to cover initial drilling costs.
+13
+Our future drilling activities may not be successful, nor can we be
+sure that our overall drilling success rate or our drilling success rate for
+activity within a particular area will not decline. Unsuccessful drilling
+activities could have a material adverse effect on our results of operations and
+financial condition. Also, we may not be able to obtain any options or lease
+rights in potential drilling locations that we identify. Although we have
+identified numerous potential drilling locations, we may not be able to
+economically produce oil or natural gas from all of them.
+Our business is subject to operating and environmental risks and hazards that
+could result in substantial losses.
+Oil and gas operations are subject to many risks, including well
+blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
+well fluids, fires, formations with abnormal pressures, pipeline ruptures or
+spills, pollution, releases of toxic gas and other environmental risks and
+hazards. If any of these types of events occurs, we could sustain substantial
+losses.
+Under certain limited circumstances we may be liable for environmental
+damage caused by previous owners or operators of properties that we own, lease
+or operate. As a result, we may incur substantial liabilities to third parties
+or governmental entities, which could reduce or eliminate funds available for
+exploration, development or acquisitions or cause us to incur losses.
+We maintain insurance against some, but not all, of these potential
+risks and losses. We have limited coverage for sudden environmental damages. We
+do not believe that insurance coverage for the full potential liability that
+could be caused by sudden environmental damages or insurance coverage for
+environmental damage that occurs over time is available at a reasonable cost. In
+addition, pollution and environmental risks generally are not fully insurable.
+Further, we may elect not to obtain other insurance coverage under circumstances
+where we believe that the cost of available insurance is excessive relative to
+the risks presented. Accordingly, we may be subject to liability or may lose
+substantial portions of certain properties in the event of environmental or
+other damages. If a significant accident or other event occurs and is not fully
+covered by insurance, it could have a material adverse effect on our financial
+condition and results of operations.
+Hedging transactions may limit our potential gains and involve other risks.
+To manage our exposure to price risks in the marketing of our oil and
+natural gas, we enter into commodity price risk management arrangements from
+time to time with respect to a portion of our current or future production.
+While intended to reduce the effects of volatile oil and natural gas prices,
+these transactions may limit our potential gains if oil or natural gas prices
+were to rise substantially over the price established by the hedge. In addition,
+such transactions may expose us to the risk of financial loss in certain
+circumstances, including instances in which:
+o our production is less than expected;
+o the counterparties to our futures contracts fail to perform
+under the contracts; or
+o a sudden, unexpected event materially impacts oil or natural
+gas prices.
+The terms of our hedging agreements may also require that we furnish
+cash collateral, letters of credit or other forms of performance assurance in
+the event that mark-to-market calculations result in settlement obligations by
+us to the counterparties, which would encumber our liquidity and capital
+resources.
+14
+In addition, hedging transactions using derivative instruments involve
+basis risk. Basis risk in a hedging contract occurs when the index upon which
+the contract is based is more or less variable than the index upon which the
+hedged asset is based, thereby making the hedge less effective. For example, a
+NYMEX index used for hedging certain volumes of production may have more or less
+variability than the regional price index used for the sale of that production.
+Our industry is heavily regulated.
+Federal, state and local authorities extensively regulate the oil and
+gas industry. Legislation and regulations affecting the industry are under
+constant review for amendment or expansion, raising the possibility of changes
+that may affect, among other things, the pricing or marketing of oil and gas
+production. Noncompliance with statutes and regulations may lead to substantial
+penalties, and the overall regulatory burden on the industry increases the cost
+of doing business and, in turn, decreases profitability. These authorities
+regulate various aspects of oil and gas drilling and production activities,
+including the drilling of wells (through permit and bonding requirements), the
+spacing of wells, the unitization or pooling of oil and gas properties,
+environmental matters, safety standards, the sharing of markets, production
+limitations, plugging and abandonment, and restoration. To cover the various
+obligations of leaseholders in federal waters, federal authorities generally
+require that leaseholders have substantial net worth or post bonds or other
+acceptable assurances that such obligations will be met. The cost of these bonds
+or other surety can be substantial, and we may not be able to obtain bonds or
+other surety in all cases. Under limited circumstances, federal authorities may
+require any of our operations on federal leases to be suspended or terminated.
+Any such suspension or termination could materially adversely affect our
+financial condition and results of operations.
+We must comply with complex environmental regulations.
+Our operations are subject to complex and constantly changing
+environmental laws and regulations adopted by federal, state and local
+governmental authorities where we are engaged in exploration or production
+operations. New laws or regulations, or changes to current requirements, could
+have a material adverse effect on our business. We will continue to be subject
+to uncertainty associated with new regulatory interpretations and inconsistent
+interpretations between state and federal agencies. We could face significant
+liabilities to the government and third parties for discharges of oil, natural
+gas or other pollutants into the air, soil or water, and we could have to spend
+substantial amounts on investigations, litigation and remediation. Existing
+environmental laws or regulations, as currently interpreted or enforced, or as
+they may be interpreted, enforced or altered in the future, may have a material
+adverse effect on our results of operations and financial condition. As a
+result, we may face material claims with respect to properties we own or have
+owned.
+Our business depends on transportation facilities owned by others.
+The marketability of our oil and gas production depends in part on the
+availability, proximity and capacity of pipeline systems owned by third parties.
+The unavailability of or lack of available capacity on these systems and
+facilities could result in the shutting-in of producing wells or the delay or
+discontinuance of development plans for properties. Although we have some
+contractual control over the transportation of our product, material changes in
+these business relationships could materially affect our operations. Federal and
+state regulation of oil and gas production and transportation, tax and energy
+policies, changes in supply and demand, pipeline pressures, damage to or
+destruction of pipelines and general economic conditions could adversely affect
+our ability to produce, gather and transport oil and natural gas.
+15
+We depend on key personnel.
+Our success will continue to depend on the continued services of our
+executive officers and a limited number of other senior management and technical
+personnel with extensive experience and expertise in evaluating and analyzing
+producing oil and gas properties and drilling prospects, maximizing production
+from oil and gas properties and marketing oil and gas production. Loss of the
+services of any of these people could have a material adverse effect on our
+operations.
+Ownership of working interests, royalty interests and other interests by a
+director and some of our officers may create conflicts of interest.
+As a result of their prior employment with another company with which
+St. Mary engaged in a number of transactions, Ronald D. Boone, a director of St.
+Mary, and two vice presidents of St. Mary own royalty interests in a number of
+St. Mary's properties, which were earned as part of the prior employer's
+employee benefit programs. Those persons have no royalty participation in any
+St. Mary properties acquired or developed subsequent to the beginning of their
+employment with St. Mary.
+Mr. Boone also owns 25 percent of Princeton Resources LLC, which owns
+the oil and gas working interests that he acquired as a result of his prior
+employment. Although Mr. Boone does not manage this entity, he may participate
+in any investment decisions made by it.
+As a result of these transactions and relationships, conflicts of
+interest may exist between these persons and us. Although these persons owe
+fiduciary duties to our stockholders and to us, conflicts of interest may not
+always be resolved in our favor.
+Risks Related to Our Common Stock
+The price of our common stock may fluctuate significantly, which may result in
+losses for investors.
+From January 1, 2003, to February 15, 2005, the last daily sale price
+of our common stock reported by the New York Stock Exchange ranged from a low of
+$23.83 per share to a high of $49.47 per share. We expect our stock to continue
+to be subject to fluctuations as a result of a variety of factors, including
+factors beyond our control. These include:
+o changes in oil and natural gas prices;
+o variations in quarterly drilling, recompletions, acquisitions
+and operating results;
+o changes in financial estimates by securities analysts;
+o changes in market valuations of comparable companies;
+o additions or departures of key personnel; and
+o future sales of our common stock.
+We may fail to meet expectations of our stockholders or of securities
+analysts at some time in the future, and our stock price could decline as a
+result.
+Our certificate of incorporation and bylaws have provisions that discourage
+corporate takeovers and could prevent shareholders from realizing a premium on
+their investment.
+16
+Our certificate of incorporation and bylaws contain provisions that may
+have the effect of delaying or preventing a change of control. These provisions,
+among other things, provide for non-cumulative voting in the election of the
+Board of Directors and impose procedural requirements on stockholders who wish
+to make nominations for the election of Directors or propose other actions at
+stockholders' meetings. These provisions, alone or in combination with each
+other and with the rights plan described below, may discourage transactions
+involving actual or potential changes of control, including transactions that
+otherwise could involve payment of a premium over prevailing market prices to
+shareholders for their common stock.
+Under our stockholder rights plan, if the Board of Directors determines
+that the terms of a potential acquisition do not reflect the long-term value of
+St. Mary, the Board of Directors could allow the holder of each outstanding
+share of our common stock other than those held by the potential acquirer to
+purchase one additional share of our common stock with a market value of twice
+the exercise price. This prospective dilution to a potential acquirer would make
+the acquisition impracticable unless the terms were improved to the satisfaction
+of the Board of Directors. The existence of the plan may impede a takeover not
+supported by our board even though such takeover may be desired by a majority of
+our stockholders or may involve a premium over the prevailing stock price.
+Our shares that are eligible for future sale may have an adverse effect on the
+price of our common stock.
+At February 15, 2005, we had 28,548,362 shares of common stock
+outstanding. Of the shares outstanding, approximately 28,234,000 shares were
+freely tradable without substantial restriction or the requirement of future
+registration under the Securities Act. Also as of that date, options to purchase
+2,756,436 shares of our common stock were outstanding, of which 2,152,871 were
+exercisable. These options are exercisable at prices ranging from $9.25 to
+$41.74 per share. In addition, restricted stock units providing for the issuance
+of up to a total of 227,831 shares of our common stock were outstanding. Sales
+of substantial amounts of common stock, or a perception that such sales could
+occur, and the existence of options or restricted stock units to issue shares of
+common stock at prices that may be below the then-current market price of the
+common stock could adversely affect the market price of the common stock and
+could impair our ability to raise capital through the sale of our equity
+securities.
+A director and his extended family may be able to control us.
+Thomas E. Congdon, a director and our former Chairman of the Board, and
+members of his extended family owned greater than 10 percent of the outstanding
+shares of our common stock as of February 15, 2005. While no formal arrangements
+exist, these extended family members could be inclined to act in concert with
+Mr. Congdon on matters related to control of St. Mary, including for example the
+election of Directors or response to an unsolicited bid to acquire St. Mary.
+Accordingly, Mr. Congdon and his family may be able to control or influence
+matters presented to our Board of Directors and stockholders.
+We may not always pay dividends on our common stock.
+The payment of future dividends remains in the discretion of the Board
+of Directors and will continue to depend on our earnings, capital requirements,
+financial condition and other factors. In addition, the payment of dividends is
+subject to covenants in our credit facility, including the requirement that we
+maintain certain levels of stockholder's equity. The Board of Directors may
+determine in the future to reduce the current annual dividend rate of $0.10 per
+17
+share or discontinue the payment of dividends altogether. Our credit facility
+limits the annual dividend rate that we may pay to $0.20 per share.
+Cautionary Statement about Forward-Looking Statements
+This Annual Report on Form 10-K includes certain statements that may be
+deemed to be "forward-looking statements" within the meaning of Section 27A of
+the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
+1934. All statements, other than statements of historical facts, included in
+this Form 10-K that address activities, events or developments that St. Mary's
+management expects, believes or anticipates will or may occur in the future are
+forward looking statements. Examples of forward-looking statements may include
+discussion of such matters as:
+o The amount and nature of future capital, development and
+exploration expenditures;
+o The drilling of wells;
+o Reserve estimates and the estimates of both future net
+revenues and the present value of future net revenues that are
+included in their calculation;
+o Future oil and gas production estimates;
+o Repayment of debt;
+o Business strategies;
+o Expansion and growth of operations; and
+o Other similar matters such as those discussed in Management's
+Discussion and Analysis of Financial Condition and Results of
+Operations.
+These statements are based on certain assumptions and analyses made by us in
+light of our experience and our perception of historical trends, current
+conditions, expected future developments and other factors we believe are
+appropriate in the circumstances. Such statements are subject to a number of
+assumptions, risks and uncertainties, including such factors as the volatility
+and level of oil and natural gas prices, uncertainties in cash flow, the
+uncertain nature of the expected benefits from the acquisition of oil and gas
+properties, production rates and reserve replacement, the imprecise nature of
+oil and gas reserve estimates, drilling and operating service availability,
+unexpected drilling conditions and results, the risks of various exploration
+strategies, competition, the availability of economically attractive exploration
+and development and property acquisition opportunities and any necessary
+financing, litigation, environmental matters, the potential impact of government
+regulations, and other matters discussed under the caption "Risk Factors", many
+of which are beyond our control. Readers are cautioned that forward-looking
+statements are not guarantees of future performance and that actual results or
+developments may differ materially from those expressed or implied in the
+forward-looking statements.
+Available Information
+Our Internet website address is www.stmaryland.com. Through our
+------------------
+website's financial information section we make available free of charge our
+annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on
+Form 8-K, and amendments to those reports filed with or furnished to the SEC
+under applicable securities laws. These materials are made available as soon as
+reasonably practical after we electronically file such material with, or furnish
+it to, the SEC.
+18
+We also make available through our website's corporate governance
+section our corporate governance guidelines, code of business conduct and
+ethics, and the charters for our Board of Directors' audit committee,
+compensation committee, executive committee and nominating and corporate
+governance committee. These documents are also available in print to any
+stockholder who requests them. Requests for these documents may be submitted to:
+St. Mary Land & Exploration Company
+Investor Relations
+1776 Lincoln Street, Suite 700
+Denver, Colorado 80203
+Telephone: (303) 863-4322
+Information on our website is not incorporated by reference into this
+Annual Report on Form 10-K and should not be considered part of this document.
+Glossary
+The terms defined in this section are used throughout this Annual
+Report on Form 10-K.
+2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a
+two-dimensional cross-section of the subsurface.
+3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a
+three-dimensional picture of the subsurface.
+Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
+reference to oil or other liquid hydrocarbons.
+Bcf. Billion cubic feet, used herein in reference to natural gas.
+BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using
+the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+Behind pipe reserves. Estimated net proved reserves in a formation in which
+production casing has already been set in the wellbore but has not been
+perforated and production tested.
+BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio
+of six Mcf of gas (including gas liquids) to one Bbl of oil.
+Development well. A well drilled within the proved area of an oil or gas
+reservoir to the depth of a stratigraphic horizon known to be productive in an
+attempt to recover proved undeveloped reserves.
+Dry hole. A well found to be incapable of producing either oil or gas in
+sufficient quantities to justify completion as an oil or gas well.
+Estimated net proved reserves. The estimated quantities of oil, gas and gas
+liquids which geological and engineering data demonstrate with reasonable
+certainty to be recoverable in future years from known reservoirs under existing
+economic and operating conditions.
+Exploratory well. A well drilled to find and produce oil or gas in an unproved
+area, to find a new reservoir in a field previously found to be productive of
+oil or gas in another reservoir or to extend a known reservoir beyond its known
+horizon.
+19
+Fee land. The most extensive interest that can be owned in land, including
+surface and mineral (including oil and gas) rights.
+Finding cost. Expressed in dollars per BOE or MCFE. Finding costs are calculated
+by dividing the amount of total capital expenditures for oil and gas activities,
+including the effect of asset retirement obligations, by the amount of estimated
+net proved reserves added through revisions of previous estimates, discoveries
+and purchases during the same period. The information for this calculation will
+be found in the disclosures about oil and gas producing activities in Item 15 of
+Part IV of this report.
+Gross acres. An acre in which a working interest is owned.
+Gross well. A well in which a working interest is owned.
+Hydraulic fracturing. A procedure to stimulate production by forcing a mixture
+of fluid and proppant (usually sand) into the formation under high pressure.
+This creates artificial fractures in the reservoir rock, which increases
+permeability and porosity.
+MBbl. One thousand barrels of oil or other liquid hydrocarbons.
+MMBbl. One million barrels of oil or other liquid hydrocarbons.
+MBOE. One thousand barrels of oil equivalent.
+MMBOE. One million barrels of oil equivalent.
+Mcf. One thousand cubic feet.
+MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined
+using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+MMcf. One million cubic feet.
+MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined
+using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+MMBtu. One million British Thermal Units. A British Thermal Unit is the amount
+of heat required to raise the temperature of a one-pound mass of water by one
+degree Fahrenheit.
+Net acres or net wells. The sum of our fractional working interests owned in
+gross acres or gross wells.
+Net asset value per share. The result of the fair market value of total assets
+less total liabilities, divided by the total number of outstanding shares of
+common stock.
+PV-10 value. The present value of estimated future gross revenue to be generated
+from the production of estimated net proved reserves, net of estimated
+production and future development costs, using prices and costs in effect as of
+the date indicated (unless such prices or costs are subject to change pursuant
+to contractual provisions), without giving effect to non-property related
+expenses such as general and administrative expenses, debt service and future
+income tax expenses or to depreciation, depletion and amortization, discounted
+using an annual discount rate of 10 percent.
+Productive well. A well that is producing oil or gas or that is capable of
+production.
+20
+Proved developed reserves. Reserves that can be expected to be recovered through
+existing wells with existing equipment and operating methods.
+Proved undeveloped reserves. Reserves that are expected to be recovered from new
+wells on undrilled acreage, or from existing wells where a relatively major
+expenditure is required for recompletion.
+Recompletion. The completion for production from an existing wellbore in another
+formation other than that in which the well has previously been completed.
+Reserve life. Expressed in years, represents the estimated net proved reserves
+at a specified date divided by forecasted production for the preceding 12-month
+period.
+Reserve replacement percentage. The sum of reserve extensions and discoveries,
+reserve acquisition, and reserve revisions of previous estimates for a specified
+period of time divided by production for that same period of time.
+Royalty. The share paid to the owner of mineral rights expressed as a percentage
+of gross income from oil and gas produced and sold unencumbered by expenses
+relating to the drilling, completing and operating of the affected well.
+Royalty interest. An interest in an oil and gas property entitling the owner to
+shares of oil and gas production free of costs of exploration, development and
+production.
+Undeveloped acreage. Lease acreage on which wells have not been drilled or
+completed to a point that would permit the production of commercial quantities
+of oil and gas, regardless of whether such acreage contains estimated net proved
+reserves.
+Working interest. The operating interest that gives the owner the right to
+drill, produce and conduct operating activities on the property and to share in
+the production.
+21
+ITEM 2. PROPERTIES
+Operations
+St. Mary's exploration, development and acquisition activities are
+focused in five core operating areas: the Rocky Mountain region; the
+Mid-Continent region; the ArkLaTex region; the Gulf Coast region; and the
+Permian Basin region. Information concerning each of our major areas of
+operations, and summary of our estimated proved reserves as of December 31,
+2004, is shown below.
+Estimated Proved Reserves
+---------------------------------------------------------
+Oil Gas MMCFE PV-10 Value
+------------------ ----------------------
+(MBbl) (MMcf) Amount Percent (In thousands) Percent
+------- ------- --------- -------- -------------- -------
+Rocky Mountain 46,762 75,335 355,907 54% $ 748,916 50%
+Mid-Continent 1,024 129,536 135,678 21% 335,028 22%
+ArkLaTex 1,438 66,931 75,558 12% 173,190 12%
+Gulf Coast 388 31,170 33,498 5% 120,591 8%
+Permian Basin 6,962 6,754 48,527 7% 109,710 7%
+Coalbed Methane - 9,470 9,470 1% 13,688 1%
+------- ------- --------- -------- -------------- -------
+Total 56,574 319,196 658,638 100% $ 1,501,123 100%
+======= ======= ========= ======== ============== =======
+Rocky Mountain Region. Nance Petroleum Corporation, a wholly owned
+subsidiary of St. Mary, has conducted operations in the Williston Basin in
+eastern Montana and western North Dakota since 1991. We have expanded this area
+into the Green River, Powder River, Big Horn and Wind River basins over the past
+three years. In November 2004, we acquired the stock of Goldmark Engineering,
+Inc. along with oil and gas properties from various Goldmark partners for $23.3
+million of cash. The allocation of the purchase price for the net assets
+acquired was $29.4 million of proved reserves and unproved acreage, $1.2 million
+of cash, $753,000 of other assets, $446,000 of payables, a $2.8 million asset
+retirement liability, and a $4.8 million deferred tax liability. The Goldmark
+acquisition added approximately 31.9 BCFE of proved reserves as of the
+acquisition date.
+Conventional oil and gas reserves in the Rocky Mountain region
+accounted for 54 percent of our estimated proved reserves as of December 31,
+2004, or 356 BCFE, 87 percent of which were proved developed and 79 percent of
+which were oil.
+Our office in Billings, Montana includes a 75-person staff. A
+significant portion of the exploration and development in the Rocky Mountain
+region is based on the interpretation of 3-D seismic data. We have successfully
+used 3-D seismic imaging to delineate structure and porosity development in the
+Red River formation as well as the Middle Bakken horizontal dolomite play.
+St. Mary spent $108.5 million on exploration, development and
+acquisitions in the Rocky Mountain region in 2004.
+Our capital budget for the Rocky Mountain region now represents the
+largest portion of our drilling budget at approximately $121 million in 2005.
+This increase is a result of the increased development of the Middle Bakken
+formation, increased drilling associated with the Red River play, and a full
+year development plan for our Hanging Woman Basin coalbed methane project. We
+have approximately 150 wells planned and a risked budget of $24 million at
+Hanging Woman. The Bakken play, which has been primarily in Richland County,
+Montana, is now expanding to McKenzie and Billings Counties in North Dakota. We
+plan on drilling 30 wells in the Bakken during 2005 for total risked capital of
+22
+$30 million. The Red River formation continues to be a major portion of the
+budget with nine wells planned for $13 million. Our growth in Wyoming has
+resulted in an allocated capital budget of $26 million for participation in 69
+gross wells in the Fourbear, Monument Lake, Red Lakes and Standard Draw fields.
+In the Rocky Mountain region, we have a working interest greater than 90 percent
+in 322 wells. Including the development of Hanging Woman Basin, we will be the
+operator of properties representing approximately 83 percent of our 2005 Rocky
+Mountain region capital budget.
+The concentration of our value in the Rockies is at the East Putnam
+field in Richland County, Montana, and at the Rough Rider field in McKenzie
+County, North Dakota. Each of these fields represents two percent of total
+proved reserves and two percent of our PV-10 value. There are nine and 41 gross
+wells producing in these two fields, respectively, with our working interest
+varying from six to 100 percent. Following these fields, the other most
+significant fields are the Brush Lake, South Fork and Ridgelawn areas. Combined,
+these three fields represent five percent of our total reserves and PV10 value.
+As of the end of 2004, the Hanging Woman Basin coalbed methane project
+had 8 BCFE of proved reserves representing one percent of our total proved
+reserves. We are in the early development stage. First production from the field
+began in mid-December 2004. We do not expect production from Hanging Woman to
+account for a material portion of total 2005 production volumes. Because of the
+dewatering time and the low production rates per well, it will take two to three
+years to develop the field to the point of having production volumes that are
+meaningful to our total production.
+Mid-Continent Region. St. Mary has been active in the Mid-Continent
+region since 1973. Operations for the region are managed by our 42-person office
+in Tulsa, Oklahoma. Our long history of operations and proprietary geologic
+knowledge enables us to sustain economic development and exploration programs
+despite periods of adverse industry conditions. We apply current technology in
+hydraulic fracturing and innovative well completion techniques to accelerate
+production and associated cash flow from the region's tight gas reservoirs. We
+also attempt to benefit from the continuing consolidation of operators in the
+basin as we pursue attractive opportunities to acquire properties.
+We have ongoing exploration and development programs in the Anadarko
+and Arkoma basins of Arkansas, Oklahoma and Texas. The Mid-Continent region
+accounts for 21 percent of our estimated proved reserves as of December 31,
+2004, or 136 BCFE, 88 percent of which were proved developed and 95 percent of
+which were natural gas. In 2004 our capital expenditures in the Mid-Continent
+were $104.0 million. We participated in drilling 108 gross wells in this region
+in 2004, 91 percent of which were completed as producers. We operated 36 of
+these drilling projects.
+St. Mary's development and exploration budget in the Mid-Continent
+region for 2005 totals $87 million, down from $96 million in 2004. Included in
+the 2005 budget is $3 million of drilling associated with the Agate acquisition.
+The decrease in the budget is intended to focus investment in drilling with a
+higher potential of return. We plan to be the operator of properties
+representing approximately 80 percent of our capital budget in this region
+during 2005 and to utilize three to five drilling rigs throughout the year.
+Approximately 23 percent of our 2005 Mid-Continent capital budget is
+allocated to deeper, higher-potential wells in the Morrow/Springer formations,
+and 25 percent is allocated to the Atoka formations at the Northeast Mayfield
+field in Beckham County, Oklahoma on the southern edge of the Anadarko Basin. We
+have allocated 48 percent of the drilling activities budget for
+low-to-medium-risk development in the Granite Wash, Osborne, Cottage Grove,
+Cromwell / Wapanucka, Woodford and Spiro formations. With our recently completed
+23
+acquisition of Agate Petroleum, Inc., we have allocated 4 percent of our
+drilling budget to development of the Hartshorne formation.
+The Northeast Mayfield area is the largest concentration of our
+reserves in the Mid-Continent. This field represents approximately 32 BCFE or
+five percent of our proved reserves and $82.7 million, or approximately 6
+percent of our total PV-10 value. Our average working interest in this field is
+24 percent, and we have an interest in approximately 73 gross wells of which we
+operate 42 percent.
+Other significant fields in the Mid-Continent region are the Centrahoma
+field located in Coal County, Oklahoma, in the Arkoma Basin and the Constitution
+field in Jefferson County, Texas. Centrahoma represents three percent of total
+proved reserves and $37.1 million or two percent of total PV-10 value, and the
+Constitution field represents one percent of total proved reserves and $28
+million of PV-10 value. We operate 85 percent of the Centrahoma field but none
+of the 7 gross wells in Constitution field. The other most significant field in
+the Mid-Continent region is the Elk City field in Beckham County, Oklahoma,
+representing two percent of proved reserves and two percent of total PV10 value.
+We operate 18 percent of the wells in Elk City and have an average working
+interest of approximately 13 percent.
+ArkLaTex Region. Our 18-person office in Shreveport, Louisiana, manages
+St. Mary's operations in the ArkLaTex region. The ArkLaTex region accounts for
+12 percent of our estimated proved reserves as of December 31, 2004, or 76 BCFE;
+83 percent of which were proved developed and 89 percent were natural gas. We
+also own rights to over 6,000 square miles of proprietary 2-D seismic data in
+the region. Many of the Shreveport office's successful exploration and
+development programs have derived from niche acquisitions. These acquisitions
+have provided access to strategic holdings of undeveloped acreage and
+proprietary packages of geologic and seismic data resulting in an active program
+of additional development and exploration. We believe the recent acquisition of
+non-operated producing working interests in the Elm Grove field, consisting of
+14.5 BCFE and $34 million of PV-10 value, will provide us a foothold to grow our
+interest in this area.
+Our holdings in the ArkLaTex region are comprised of interests in
+approximately 538 producing gross wells, including 101 wells operated by us;
+interests in leases totaling approximately 149,000 gross acres; and mineral
+servitudes totaling approximately 14,300 gross acres. Our capital expenditures
+in this region in 2004 were $67.3 million, including $37.6 million for
+acquisitions. Following our ownership in the Elm Grove field, the next most
+significant concentration of properties is the Box Church field, which includes
+16 BCFE of proved reserves and working interests in 33 gross wells, all of which
+we operate.
+In 2005 we will grow our drilling capital budget in the ArkLaTex to $34
+million. These capital dollars are budgeted for horizontal wells in the James
+and Pettet Limestones and other tight sands plays and development of the Elm
+Grove and Travis Peak / Cotton Valley plays in East Texas. The budget reflects
+us as operator for 46 percent of estimated expenditures.
+Gulf Coast Region. St. Mary's presence in south Louisiana dates to the
+early 1900's when our founders acquired a franchise property in St. Mary Parish
+on the shoreline of the Gulf of Mexico. These 24,914 acres of fee lands yielded
+$5.5 million of gross oil and gas royalty revenue in 2004. Our Gulf Coast region
+presence increased significantly in 1999 with the acquisition of King Ranch
+Energy, Inc. Including the Louisiana fee lands, the Gulf Coast region accounts
+for five percent of our estimated proved reserves as of December 31, 2004, or 33
+BCFE, 93 percent of which were proved developed and 31 BCFE were natural gas.
+24
+Our 18-person team based in Houston, Texas manages St. Mary's diverse
+activities in our Gulf Coast and Permian Basin regions. Our exploration and
+development budget in the Gulf Coast region for 2005 is $41 million which
+consists of activity both onshore and offshore in Texas and Louisiana. We will
+operate properties representing approximately 33 percent of this amount.
+The most significant field in the Gulf Coast region is the Judge Digby
+Field, located outside Baton Rouge, Louisiana, in Point Coupee Parish. As of the
+end of December 2004, this field represented slightly less than three percent of
+our total PV-10 value with 13.5 BCFE of proved reserves. Production from the
+Judge Digby field totaled 3.6 BCFE in 2004.
+Permian Basin Region. The Permian Basin area covers a significant
+portion of eastern New Mexico and western Texas and is one of the major
+producing basins in the United States. The basin includes hundreds of oil fields
+undergoing secondary and enhanced oil recovery projects. The use of 3-D seismic
+imaging of existing fields and advanced secondary recovery programs are
+substantially increasing oil recoveries in this Basin. Our holdings in the
+Permian Basin resulted from a series of property acquisitions since 1995. We
+believe that our Permian Basin operations provide us with a solid base of
+long-lived oil reserves, promising longer-term exploration and development
+prospects and the potential for additional secondary recovery projects. The
+Permian Basin region accounted for 49 BCFE, or 7 percent of our estimated proved
+reserves as of December 31, 2004. The Permian reserves are 63 percent proved
+developed and 86 percent are oil.
+The Parkway Delaware waterflood project, located in Eddy County, New
+Mexico, represents 19 BCFE or three percent of our proved reserves. The East
+Shugart Delaware Unit is a pilot waterflood located in Lea and Eddy Counties,
+New Mexico that is analogous to the Parkway Delaware Unit and is comprised of 16
+BCFE of total proved reserves. Production from the Permian Basin properties
+represented 3.1 BCFE or 4 percent of the total production for the Company in
+2004.
+Our Permian Basin capital budget for 2005 is $10 million of which we
+anticipate spending 79 percent on properties we operate. We plan to drill 11
+infill wells at Parkway Delaware and eight wells at East Shugart. Our capital
+budget also has seven recompletion projects scheduled at Parkway Delaware. East
+Shugart is still in a pilot phase and is moving into full development of the
+flood in 2005.
+Acquisitions and Divestitures
+We spent a total of $76.7 million on acquisitions of proved and
+unproved oil and gas properties in 2004. The two most significant acquisitions
+were the Goldmark and Border Company acquisitions. On November 1, 2004, we
+acquired the stock of Goldmark Engineering, Inc. and proved and unproved oil and
+gas properties from various Goldmark partners for $23.3 million of cash. The oil
+and gas properties in the Goldmark acquisition are located primarily in the
+Fourbear field in the Big Horn Basin of Wyoming. On December 15, 2004, we
+acquired proved and unproved oil and gas properties from Border Company in and
+around the Elm Grove field located in Louisiana for $37.8 million of cash. We
+made various other smaller acquisitions in 2004 as well. In the aggregate, we
+purchased 52 BCFE of proved reserves in 2004.
+Significant acquisitions prior to 2004 include the acquisitions of oil
+and gas properties in the Rocky Mountain region from Flying J Oil & Gas Inc.
+in January 2003 and from Burlington Resources in December 2002.
+25
+Reserves
+The following table presents summary information with respect to the
+estimates of our proved oil and gas reserves for each of the years in the
+three-year period ended December 31, 2004, as prepared by both Ryder Scott
+Company and Netherland, Sewell & Associates, Inc., both of which are
+independent petroleum engineering firms, and us. For the periods presented,
+Ryder Scott Company evaluated properties representing a minimum of 80 percent of
+the total PV-10 value of our conventional reserves, and we evaluated the
+remainder. The proved oil and gas reserves prepared by Netherland Sewell in 2004
+consist of the coalbed methane developments at Hanging Woman Basin and Atlantic
+Rim. As of December 31, 2004, the PV-10 of proved reserves, prepared by
+Netherland Sewell, was less than one percent of our total PV-10 reserve value.
+The PV-10 values shown in the following table are not intended to represent the
+current market value of the estimated proved oil and gas reserves owned by St.
+Mary. Neither prices nor costs have been escalated. You should read the
+following table along with the section entitled "Risk Factors - Risks Related to
+Our Business - Estimates of oil and gas reserves are not precise."
+As of December 31,
+----------------------------------------------
+Proved Reserves Data: 2004 2003 2002
+----------------------------------------- ------------- --------------- ----------------
+Oil (MBbl) 56,574 47,787 36,119
+Gas (MMcf) 319,196 307,024 274,172
+MMCFE 658,638 593,744 490,887
+PV-10 value, without tax effect (in
+thousands) (1) $ 1,501,123 $ 1,278,165 $ 824,808
+Standardized measure of discounted
+future net cash flows (in thousands) $ 1,033,938 $ 859,956 $ 581,862
+Proved developed reserves 85% 89% 88%
+Reserve replacement 190% 293% 306%
+Reserve life (years) (2) 8.7 7.7 8.9
+----------------
+(1) PV-10 value as of December 31, 2004, was calculated using the
+weighted-average sales price of $40.06 per barrel of oil and $5.80 per
+Mcf of gas. These prices are based on NYMEX prices for oil and a Gulf
+Coast spot price for gas in effect on December 31, 2004, and are then
+adjusted for transportation, quality and basis differentials.
+(2) Reserve life represents the estimated proved reserves at the dates
+indicated divided by actual production for the preceding 12-month
+period.
+26
+Production
+The following table summarizes the average volumes of oil and gas
+produced from properties in which St. Mary held an interest during the periods
+indicated:
+Years Ended December 31,
+-----------------------------------------------------
+2004 2003 2002
+---------------- ---------------- ----------------
+Operating data:
+Net production:
+Oil (MBbl) 4,799 4,541 2,815
+Gas (MMcf) 46,598 49,663 38,164
+MMCFE 75,393 76,909 55,055
+Average net daily production:
+Oil (Bbl) 13,113 12,441 7,713
+Gas (Mcf) 127,316 136,062 104,558
+MCFE 205,992 210,709 150,836
+Average realized sales price (1):
+Oil (per Bbl) $ 32.53 $ 26.96 $ 25.34
+Gas (per Mcf) $ 5.52 $ 4.89 $ 3.00
+Per MCFE $ 5.48 $ 4.75 $ 3.37
+Additional per MCFE data:
+Lease operating expense $ 0.81 $ 0.77 $ 0.66
+Transportation costs $ 0.10 $ 0.09 $ 0.06
+Production taxes $ 0.36 $ 0.29 $ 0.20
+General and administrative $ 0.29 $ 0.28 $ 0.25
+Depreciation, depletion, amortization
+and liability accretion $ 1.22 $ 1.07 $ 0.99
+----------------
+(1) Includes the effects of St. Mary's hedging activities. See
+"Management's Discussion and Analysis of Financial Condition and
+Results of Operations."
+Productive Wells
+As of December 31, 2004, we had working interests in 1,613 gross (727
+net) productive oil wells and 2,068 gross (479 net) productive gas wells.
+Productive wells are either producing wells or wells capable of commercial
+production although currently shut in. One or more completions in the same
+wellbore are counted as one well. A well is categorized under state reporting
+regulations as an oil well or a gas well based upon the ratio of gas to oil
+produced when it first commenced production, and such designation may not be
+indicative of current production.
+27
+Drilling Activity
+All of our drilling activities are conducted on a contract basis with
+independent drilling contractors. We do not own any drilling equipment. The
+following table sets forth the wells drilled and recompleted in which St. Mary
+participated during each of the three years indicated:
+Years Ended December 31,
+------------------------------------------------------------------------------------
+2004 2003 2002
+--------------------------- --------------------------- --------------------------
+Gross Net Gross Net Gross Net
+------------- ------------ ------------ ------------- ----------- -------------
+Development:
+Oil 50 18.08 36 14.88 26 11.52
+Gas 180 53.23 140 43.79 103 38.89
+Non-productive 36 14.29 37 15.98 27 14.42
+------------- ------------ ------------ ------------- ----------- -------------
+266 85.60 213 74.65 156 64.83
+------------- ------------ ------------ ------------- ----------- -------------
+Exploratory:
+Oil 11 9.71 7 3.03 3 1.22
+Gas 83 43.65 14 7.20 1 0.10
+Non-productive 8 2.84 7 4.40 8 2.64
+------------- ------------ ------------ ------------- ----------- -------------
+102 56.20 28 14.63 12 3.96
+------------- ------------ ------------ ------------- ----------- -------------
+Farmout or non-consent 5 - 10 - 8 -
+------------- ------------ ------------ ------------- ----------- -------------
+Total (1) 373 141.80 251 89.28 176 68.79
+============= ============ ============ ============= =========== =============
+----------------
+(1) Does not include seven, 15 and 14 gross wells completed on St. Mary's fee
+lands during 2004, 2003 and 2002, respectively, in which we have only a
+royalty interest.
+28
+Acreage
+The following table sets forth the gross and net acres of developed and
+undeveloped oil and gas leases, fee properties, mineral servitudes and lease
+options held by St. Mary as of December 31, 2004. Undeveloped acreage includes
+leasehold interests that may already have been classified as containing proved
+undeveloped reserves.
+Developed Acres (1) Undeveloped Acres (2) Total
+------------------------ -------------------------- ----------------------------
+Gross Net Gross Net Gross Net
+---------- ---------- ------------ ---------- ------------ ------------
+Arkansas 3,364 421 207 68 3,571 489
+Colorado 2,845 2,206 24,712 13,357 27,557 15,563
+Louisiana 132,153 40,675 23,105 8,841 155,258 49,516
+Mississippi 2,588 262 4,049 2,077 6,637 2,339
+Montana 53,549 33,879 452,638 300,103 506,187 333,982
+New Mexico 6,280 2,694 1,320 1,187 7,600 3,881
+North Dakota 131,362 86,441 160,753 98,504 292,115 184,945
+Oklahoma 245,197 68,602 37,751 23,130 282,948 91,732
+Texas 131,150 33,892 39,464 15,400 170,614 49,292
+Utah (3) 480 115 13,712 5,866 14,192 5,981
+Wyoming 73,993 45,036 422,231 252,694 496,224 297,730
+Other (4) 2,761 903 4,144 1,169 6,905 2,072
+---------- ---------- ------------ ---------- ------------ ------------
+785,722 315,126 1,184,086 722,396 1,969,808 1,037,522
+---------- ---------- ------------ ---------- ------------ ------------
+Louisiana Fee Properties 9,944 9,944 14,970 14,970 24,914 24,914
+Louisiana Mineral Servitudes 9,745 5,306 4,571 4,208 14,316 9,514
+---------- ---------- ------------ ---------- ------------ ------------
+19,689 15,250 19,541 19,178 39,230 34,428
+---------- ---------- ------------ ---------- ------------ ------------
+Total 805,411 330,376 1,203,627 741,574 2,009,038 1,071,950
+========== ========== ============ ========== ============ ============
+----------------
+(1) Developed acreage is acreage assigned to producing wells for the
+spacing unit of the producing formation. Developed acreage in certain of
+St. Mary's properties that include multiple formations with different well
+spacing requirements may be considered undeveloped for certain formations,
+but have only been included as developed acreage in the presentation above.
+(2) Undeveloped acreage is lease acreage on which wells have not been
+drilled or completed to a point that would permit the production of
+commercial quantities of oil and gas regardless of whether such acreage
+contains estimated proved reserves.
+(3) St. Mary holds an overriding royalty interest in an additional 40,100
+gross acres in Utah.
+(4) Includes interests in Alabama, Kansas, Nebraska,
+Nevada and South Dakota.
+29
+ITEM 3. LEGAL PROCEEDINGS
+From time to time, we may be involved in litigation relating to claims
+arising out of our operations in the normal course of business. As of the date
+of this report, no legal proceedings are pending against us that we believe
+individually or collectively could have a material adverse effect upon our
+financial condition or results of operations.
+As previously reported, Nance Petroleum Corporation, a wholly owned
+subsidiary, is named along with several other leaseholders and interested
+parties as an additional co-defendant in a lawsuit that was originally filed in
+the U.S. District Court for the District of Montana on June 12, 2001. The
+plaintiff, the Northern Plains Resource Council, Inc.("NPRC"), an environmental
+public interest group, sued the U.S. Bureau of Land Management, the U.S.
+Secretary of the Interior, the Montana BLM State Director and Fidelity
+Exploration & Production Company. The lawsuit seeks the cancellation of all
+federal leases related to coalbed methane development in Montana issued by the
+BLM since January 1, 1997. This cancellation is sought primarily on the grounds
+of an alleged failure of the BLM to comply with federal environmental laws. NPRC
+alleges that the environmental impacts of coalbed methane development were not
+properly analyzed before the challenged leases were issued. The Montana portion
+of our Hanging Woman Basin coalbed methane project contains approximately 74,000
+total net acres. The lawsuit potentially affects approximately 47,000 net acres
+that are subject to federal leases. Based on information presently available, we
+believe that the BLM complied with the applicable environmental laws, and the
+District Court agreed by granting the defendants' motion for summary judgment in
+December 2003. The court held that the issuance process regarding the federal
+leases in question complied with the applicable environmental laws. The
+plaintiff appealed this decision, and the Ninth Circuit Court of Appeals
+affirmed the decision of the trial court on August 26, 2004. Plaintiff has filed
+a petition for rehearing that was denied by the reviewing panel by its Order
+dated February 10, 2005. The only appeal left for the Plaintiffs is to petition
+for certiori to the U.S Supreme Court. Notwithstanding our success in the lower
+court and the appellate court, there is no assurance as to the ultimate outcome
+of the lawsuit, and therefore, there is no assurance that it will not adversely
+affect our coalbed methane project. Even if the federal leases in Montana become
+unavailable, we are proceeding with this project on non-federal leases in
+Wyoming, and we anticipate acquiring additional non-federal leases in Montana
+and Wyoming.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
+There were no matters submitted to a vote of our security holders
+during the fourth quarter of 2004.
+30
+ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
+The following table sets forth the names, ages and positions held by
+St. Mary's executive officers.
+Name Age Position
+---- --- --------
+Mark A. Hellerstein 52 Chairman of the Board, President and Chief
+Executive Officer
+Douglas W. York 43 Executive Vice President and Chief Operating
+Officer
+Robert L. Nance 68 Senior Vice President, and President and Chief
+Executive Officer of Nance Petroleum Corporation,
+a wholly-owned subsidiary of St. Mary
+Jerry R. Schuyler 49 Senior Vice President and Regional Manager
+Kevin E. Willson 48 Senior Vice President - Mid-Continent Drilling and
+Production
+Robert T. Hanley 58 Vice President - Investor Relations and Management
+Reporting
+David W. Honeyfield 38 Vice President - Finance, Treasurer and Secretary
+Milam Randolph Pharo 52 Vice President - Land and Legal
+Garry A. Wilkening 54 Vice President - Administration and Controller
+Each executive officer has held his respective position during the past
+five years, except as follows:
+Mark A. Hellerstein was appointed Chairman of the Board in September
+2002.
+Douglas W. York was appointed Executive Vice President and Chief
+Operating Officer in September 2003. Mr. York served as Vice-President -
+Acquisitions and Reservoir Engineering from 1996 to September 2003.
+Robert L. Nance was appointed Senior Vice President in March 2001.
+Jerry R. Schuyler joined St. Mary in December 2003 as Senior Vice
+President and Regional Manager of the Gulf Coast region. From November 2001 to
+July 2002, Mr. Schuyler was Senior Vice President and General Manager - Eastern
+Onshore Division for Dominion Exploration & Production, Inc., where he
+managed all operations and exploration for Dominion's Gulf Coast and eastern
+onshore U.S. regions. From March 2000 to November 2001, Mr. Schuyler was Senior
+Vice President and General Manager of Dominion's Onshore U.S. Division, where he
+managed all operations and exploration for all of Dominion's onshore U.S.
+regions. From 1996 to 2000, Mr. Schuyler was President and Managing Director,
+ARCO Middle East & Central Asia, where he managed all operations for ARCO
+International Oil & Gas Company in the Arabian Peninsula, Turkey and
+Pakistan.
+Kevin E. Willson was appointed Senior Vice President and Regional
+Manager in November 2003. Mr. Willson served as Vice President - Mid-Continent
+Exploration/Production from October 1998 to November 2003. Mr. Willson joined
+Anderman/Smith, a predecessor to St. Mary's interests in the Mid-Continent
+region, in 1990 and was appointed Vice President - Mid-Continent Engineering for
+St. Mary in 1996.
+Robert T. Hanley was appointed Vice President - Investor Relations and
+Management Reporting in April 2003. Mr. Hanley served as Vice President -
+Business Development from July 2000 to April 2003. Mr. Hanley was Chief
+Financial Officer of Nance Petroleum Corporation from 1999 to 2000 and Chief
+Financial Officer of Panterra Petroleum, a partnership between St. Mary and
+Nance Petroleum Corporation, from 1992 to 1999.
+31
+David W. Honeyfield joined St. Mary in May 2003 as Vice President -
+Finance, Treasurer and Secretary. Prior to joining St. Mary, Mr. Honeyfield was
+Controller and Chief Accounting Officer of Cimarex Energy Co. from September
+2002 to May 2003 and Controller and Chief Accounting Officer of Key Production
+Company, Inc., which was acquired by Cimarex in September 2002. Prior to joining
+Key Production Company in April 2002, Mr. Honeyfield was a senior audit manager
+with Arthur Andersen LLP in Denver. Mr. Honeyfield had been with Arthur Andersen
+since January 1991.
+Garry A. Wilkening was appointed Vice President - Administration in
+February 1999.
+The executive officers of the Company serve at the pleasure of the
+Board of Directors and do not have fixed terms. Executive officers generally are
+elected at the regular meeting of the Board immediately following the annual
+stockholders meeting. Any officer or agent elected or appointed by the Board may
+be removed by the Board whenever in its judgment the best interests of the
+Company will be served thereby without prejudice, subject however, to
+contractual rights, if any, of the person so removed. Mr. Hellerstein is
+chairman of the Board of Directors and has an employment agreement with St.
+Mary. The agreement is terminable at any time upon 30 days' notice by either
+party. Upon termination of the agreement by St. Mary for any reason other than
+death, disability or misconduct by Mr. Hellerstein, St. Mary is obligated to
+continue to pay his compensation and insurance benefits, at the level at the
+time of termination, for a period of one year.
+There are no family relationships, first cousin or closer, between any
+executive officer and director. There are no arrangements or understandings
+between any officer and any other person pursuant to which that officer was
+elected.
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITYAND RELATED STOCKHOLDER MATTERS
+Market Information. St. Mary's common stock is currently traded on the
+New York Stock Exchange under the symbol SM. The range of high and low sales
+prices for the quarterly periods in 2004 and 2003, as reported by the New York
+Stock Exchange, is set forth below:
+Quarter Ended High Low
+------------------------------- ----------------- -----------------
+December 31, 2004 $ 43.00 $ 37.12
+September 30, 2004 40.13 31.76
+June 30, 2004 37.19 31.80
+March 31, 2004 34.14 27.74
+December 31, 2003 $ 29.19 $ 24.45
+September 30, 2003 28.85 24.45
+June 30, 2003 29.75 24.65
+March 31, 2003 27.23 23.80
+Holders. As of February 15, 2005, the number of record holders of St.
+Mary's common stock was 145. Management believes, after inquiry, that the number
+of beneficial owners of our common stock is in excess of 3,800.
+Dividends. St. Mary has paid cash dividends to stockholders every year
+since 1940. Annual dividends of $0.10 per share were paid in each of the years
+1998 through 2004. We expect that our practice of paying dividends on our common
+stock will continue, although the payment of future dividends on our common
+32
+stock will continue to depend on our earnings, capital requirements, financial
+condition and other factors. In addition, the payment of dividends is subject to
+covenants in our credit facility, including the requirement that we maintain
+certain levels of stockholders' equity and the limitation of our annual dividend
+rate to no more than $0.20 per share. Dividends are currently paid on a
+semi-annual basis. Dividends paid totaled $2.8 million in 2004 and $3.1 million
+in 2003.
+Restricted Shares. Aside from Rule 144 restrictions on shares for
+insiders and restricted shares issued under the Employee Stock Purchase Plan and
+the Non-Employee Director Stock Compensation Plan, St. Mary has no restricted
+shares outstanding as of December 31, 2004.
+Issuer Purchases of Equity Securities. St. Mary did not repurchase any
+shares of its common stock during the fourth quarter of 2004.
+Equity Compensation Plans. St. Mary has a stock option plan, a
+restricted stock plan, an incentive stock option plan, an employee stock
+purchase plan, a non-employee director stock compensation plan under which
+options and shares of St. Mary common stock are authorized for grant or issuance
+as compensation to eligible employees, consultants and members of the Board of
+Directors. Our stockholders have approved each of these plans. See Note 7 -
+Compensation Plans in the Notes to Consolidated Financial Statements included in
+Part IV, Item 15 of this report for further information about the material terms
+of these plans. The following table is a summary of the shares of common stock
+authorized for issuance under our equity compensation plans as of December 31,
+2004:
+( a ) ( b ) ( c )
+Number of securities
+Number of securities remaining available for
+to be issued upon Weighted-average future issuance under
+exercise of exercise price of quity compensation plans
+outstanding options, outstanding options, (excluding securities
+warrants and rights warrants and rights ereflected in column (a))
+Plan Category
+----------------------------------------------------------- ---------------------- ----------------------------
+Equity compensation plans approved
+by security holders 3,053,506 $ 22.32 1,471,349 (1)
+Equity compensation plans not
+approved by security holders - - -
+----------------------- ---------------------- ----------------------------
+Total 3,053,506 $ 22.32 1,471,349
+======================= ====================== ============================
+--------------
+(1) Includes shares that are authorized for issuance under our employee
+stock purchase plan.
+33
+ITEM 6. SELECTED FINANCIAL DATA
+The following table sets forth supplemental selected financial and
+operating data for St. Mary as of the dates and for the periods indicated. The
+financial data for each of the five years presented were derived from the
+consolidated financial statements of St. Mary. The following data should be read
+in conjunction with "Management's Discussion and Analysis of Financial Condition
+and Results of Operations," which includes a discussion of factors materially
+affecting the comparability of the information presented, and in conjunction
+with St. Mary's consolidated financial statements included elsewhere in this
+report.
+Years Ended December 31,
+-------------------------------------------------------------------------
+2004 2003 2002 2001 2000
+--------------- -------------- ------------- -------------- -------------
+(In thousands, except per share data)
+Total operating revenues $ 433,099 $ 393,708 $ 196,305 $ 207,469 $ 195,666
+Income before cumulative effect of
+change in accounting principle $ 92,479 $ 90,140 $ 27,560 $ 40,459 $ 55,620
+Net income per share:
+Basic $ 3.21 $ 3.06 $ 0.99 $ 1.45 $ 2.00
+Diluted $ 2.88 $ 2.80 $ 0.97 $ 1.42 $ 1.97
+Total Assets $ 945,460 $ 735,854 $ 537,139 $ 436,989 $ 321,895
+Long-term obligations:
+Line of credit $ 37,000 $ 11,000 $ 14,000 $ 64,000 $ 22,000
+Convertible Notes $ 99,791 $ 99,696 $ 99,601 - -
+Cash dividends declared per common share $ 0.10 $ 0.10 $ 0.10 $ 0.10 $ 0.10
+34
+Supplemental Selected Financial and Operational Data:
+Years Ended December 31,
+--------------------------------------------------------------------------
+2004 2003 2002 2001 2000
+---------------- -------------- ------------- ------------- --------------
+(In thousands, except per volume data)
+Balance Sheet Data:
+Total working capital $ 12,035 $ 3,101 $ 2,050 $ 34,000 $ 40,639
+Total stockholders' equity $ 484,455 $ 390,653 $ 299,513 $ 286,117 $ 250,136
+Weighted-average shares outstanding:
+Basic 28,851 31,233 27,856 27,973 27,781
+Diluted 33,447 35,534 28,391 28,555 28,271
+Reserves:
+Gas (Mcf) 319,196 307,024 274,172 241,231 225,975
+Oil (Bbls) 56,574 47,787 36,119 23,669 20,950
+MCFE 658,638 593,744 490,887 383,247 351,673
+Production and Operational: Data:
+Oil and gas production revenues,
+including hedging $ 413,318 $ 365,114 $ 185,670 $ 203,973 $ 188,407
+LOE and production taxes $ 95,518 $ 88,509 $ 50,839 $ 55,000 $ 38,461
+DD&A $ 92,223 $ 81,960 $ 54,432 $ 51,346 $ 40,129
+General and administrative $ 22,004 $ 21,197 $ 13,683 $ 11,762 $ 11,166
+Production Volumes:
+Gas (Mcf) 46,598 49,663 38,164 39,491 38,346
+Oil (Bbls) 4,799 4,541 2,815 2,434 2,398
+MCFE 75,393 76,909 55,055 54,093 52,731
+Realized Price - pre hedging:
+Per BBl $ 39.77 $ 29.40 $ 24.67 $ 24.08 $ 29.02
+Per Mcf $ 5.85 $ 5.12 $ 3.10 $ 4.22 $ 3.98
+Realized Price - net of hedging:
+Per Bbls $ 32.53 $ 26.96 $ 25.34 $ 23.29 $ 23.53
+Per Mcf $ 5.52 $ 4.89 $ 3.00 $ 3.73 $ 3.44
+Expense per MCFE Data:
+LOE and production taxes $ 1.27 $ 1.15 $ 0.92 $ 1.02 $ 0.73
+DD&A $ 1.22 $ 1.07 $ 0.99 $ 0.95 $ 0.76
+General and Administrative $ 0.29 $ 0.28 $ 0.25 $ 0.22 $ 0.21
+Cash Flow Data:
+From operations $ 237,162 $ 204,319 $ 141,709 $ 127,492 $ 92,267
+For investing $ (247,006) $ (196,939) $ (180,931) $ (159,075) $ (112,868)
+From (for) financing $ 1,435 $ (3,707) $ 46,260 $ 29,080 $ 13,025
+35
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
+OF OPERATION
+This discussion includes forward-looking statements. Please refer to
+the Cautionary Statement about Forward-Looking Statements section in Part I,
+Item 1 of this document for an explanation of these types of statements.
+Overview of the Company
+General Overview
+We are an independent energy company focused on the exploration,
+exploitation, acquisition and production of natural gas and crude oil in the
+United States. We earn our revenues and generate our cash flows from operations
+primarily from the sale of produced natural gas and crude oil. Our oil and gas
+reserves and operations are concentrated primarily in the Anadarko, Arkoma,
+Permian and various Rocky Mountain basins and the onshore Gulf Coast and
+offshore Gulf of Mexico. We maintain a balanced portfolio of proved reserves,
+development drilling opportunities and non-conventional gas prospects. As of
+December 31, 2004, we had estimated proved reserves of 659 BCFE, with a before
+income tax PV-10 value of $1.5 billion and an after income tax value of $1.0
+billion. Our reserves are 85 percent proved developed and 52 percent oil.
+Oil and Gas Prices
+Our results of operations and financial condition are significantly
+affected by oil and natural gas commodity prices, which can fluctuate
+dramatically. In 2004 oil and gas producers benefited from high oil and gas
+commodity prices. Increased prices of natural gas are the result of tightening
+supply coupled with increasing demand in the United States. Because of finite
+storage capacity, changes in domestic demand created by weather have a
+significant effect on price volatility. Increases in oil price are more a result
+of global events than events in the United States. These include a decrease in
+excess worldwide production capacity, a continuing increase in demand from the
+global economy, and continued instability in the Middle East.
+Reserve Replacement and Growth
+Like all oil and gas exploration and production companies, we face the
+challenge of natural resource production decline. An oil and gas exploration and
+production company depletes part of its asset base with each unit of oil and gas
+it produces. Historically we have been able to grow our production despite this
+natural decline by adding more reserves through acquisitions and drilling than
+we produce. Future growth will depend on our ability to continue to add reserves
+in excess of production.
+We believe that growth in net asset value per share drives appreciation
+in our stock price. Our challenge to grow net asset value per share has always
+been a difficult one. To do this we set a goal of economically replacing 200
+percent of our annual production and growing production by 15 percent per year.
+Please see our additional discussion of oil and gas reserve quantities in our
+critical accounting policies and estimates section. In 2004 we replaced 190
+percent of our reserves at a finding cost of $2.19 per MCFE. We believe the
+increase in finding costs from the $1.05 amount we reported for the year ended
+December 31, 2003, is generally reflective of increasing costs industry-wide
+together with 2003 being an excellent year for St. Mary. Finding cost and
+reserve replacement percentage are defined in the glossary at the end of Part I
+Item 1 of this report. They are comparison measures used to evaluate the
+effectiveness of an oil and gas company's reserve replacement program and a
+36
+snapshot in time of its future profitability. You should note that aberrations,
+causing both good and bad results, will occur over short intervals of time.
+Sustainability in our business is dependent on the ability to create
+new ideas and new value year after year. The challenges we face are becoming
+increasingly difficult as North American oil and gas production continues to
+decline and other exploration and production companies compete for available
+reserves. We believe we have a formula for meeting these challenges. We have
+placed talented geoscientists, engineers and landmen in each of our regional
+offices where their local knowledge and experience can be fully utilized. They
+are supported with a strong balance sheet and fiscal and operating discipline.
+In 2004 our pre-tax PV-10 value for proved reserves increased 17
+percent to $1.5 billion, with a standardized measure value of $1.0 billion.
+These amounts reflect an 11 percent increase in reserves, a 29 percent increase
+in adjusted oil reserve pricing to $40.06 per barrel, and a two percent increase
+in adjusted gas reserve pricing to $5.80 per Mcf.
+2004 Highlights
+In 2004 we experienced continuing high oil and gas prices, a modest
+decrease in production and earnings, an 11 percent increase in proved reserves
+obtained at an acceptable reserve replacement cost, moderate increases in
+operating costs, profitable sales of non-strategic assets, and advancement of
+the Hanging Woman Basin coalbed methane project to the production stage with
+evaluated proved reserves. Highlights for 2004 also include good drilling
+results at the horizontal Middle Bakken play and in the Red River formation in
+the Williston Basin; the repurchase of approximately 3.4 million shares of our
+common stock from Flying J at a price of $26.92 per share; the repurchase of an
+additional 489,300 shares of our common stock under our stock repurchase program
+at an average price of $33.39 per share, and we closed on $76.7 million of oil
+and gas property acquisitions for a total of $68.8 million in cash. Our cash
+outflows were funded by existing cash and short-term investments on hand, from
+operating cash flows and from funds available under our existing credit
+facility. From December 2003 to December 2004 the outstanding balance on our
+credit facility increased by $26.0 million.
+In 2004 oil prices soared to record levels as excess OPEC capacity
+shrank to an estimated one percent to two percent of total demand. Demand for
+oil was impacted by the growing economies of China and India as well as from a
+recovering U.S. economy. Spot market prices reflected worldwide concerns about
+producer ability to ensure sufficient supply to meet increasing demand amid a
+host of uncertainties caused by weather-related destruction, political
+instability, a weaker US dollar, oil rig workers strikes and crude oil refining
+constraints. Average natural gas prices for the year were at an all-time high
+due to supply and transportation constraints, weather-related lost production,
+and continuing strong demand for natural gas in domestic markets resulting from
+an improving economy and the effect of high oil prices on natural gas demand.
+NYMEX prices for the year averaged $6.09 per MMBtu and $41.40 per barrel,
+translating into a 15 percent increase to our per MCFE realized price. At
+December 31, 2004, the 12-month NYMEX strip was $42.59 per barrel for oil and
+$6.27 per MMBtu for gas.
+Net income for 2004 was $92.5 million or $2.88 per diluted share
+compared to $95.6 million or $2.80 per diluted share for the prior year. Net
+cash provided by operating activities was $237.2 million, up 16 percent from
+2003. Production decreased two percent to 75.4 BCFE. Our average realized price
+increased 15 percent to $5.48 per MCFE. Unit costs increased modestly for the
+period as production expenses increased $0.12 to $1.27 per MCFE, DD&A with
+impairments increased $0.15 to $1.22 per MCFE and adjusted general and
+administrative expense increased $0.01 to $0.29 per MCFE from $0.28 per MCFE in
+2003. The $0.28 per MCFE general and administrative amount for 2003 has been
+37
+adjusted to reflect the separate presentation of the change in net profits plan
+liability expense as discussed in detail below in our comparison of financial
+results and trends between 2004 and 2003. Other analyses throughout this report
+also reflect changes to exploration expense and general and administrative
+expenses for this item.
+The future outlook for oil and gas prices to remain high is very
+positive, and the worldwide economy appears to be recovering. We have attractive
+prospects to drill. Rig counts are growing, and we have seen the impact of
+escalating rig and other service costs. The country's ability to supply gas
+remains challenged as the average decline rate for natural gas has increased
+from 16 percent to 30 percent over the past thirteen years. This change is a
+result of increased activity in the Gulf of Mexico where reserve lives are very
+short, the use of 3D seismic to identify smaller reservoirs, the use of better
+completion techniques that allow reserves to be produced faster, and more
+efficient high deliverability storage that allows wells to be produced at full
+capacity all year long. New sources of gas such as LNG, frontier regions (e.g.
+deepwater Gulf of Mexico and Mackenzie Delta, Alaska) and unconventional gas
+plays are all more costly and have long lead times, but at some point could have
+a positive impact on supply. We believe oil prices are high now due to
+perceptions of reduced spare capacity, increasing worldwide demand and an
+apparent increased target price range for OPEC due to a decline in the value of
+the dollar.
+We enter 2005 in good financial condition and with a capital
+expenditure budget of $418 million. In an environment with a competitive
+acquisition market and increasing drilling and service costs, we plan to add
+value in 2005 as follows:
+o Of the $418 million capital expenditures budget, 30 percent is
+allocated for acquisitions. The remaining 70 percent available
+for exploration and development is allocated 23 percent for
+conventional projects and 6 percent for coalbed methane
+projects in the Rocky Mountain region, 21 percent in the
+Mid-Continent region, 10 percent in the Gulf Coast region, 8
+percent in the ArkLaTex region, and 2 percent in the Permian
+region. The 2005 exploration and development budget is $293
+million, which represents a 28 percent increase over 2004
+exploration and development expenditures.
+o Our Hanging Woman Basin coalbed methane project will move into
+full development with the drilling of approximately 150 wells
+in Wyoming and the production of more meaningful volumes from
+wells drilled last year. Our strong balance sheet would allow
+us to pursue other potentially large unconventional
+opportunities.
+o On January 5, 2005, the Company closed the acquisition of
+Agate Petroleum Inc. for $39.6 million in cash. The estimated
+preliminary purchase accounting results in the recording of
+approximately $42.1 million to oil and gas properties, $3.0
+million to working capital, $9.4 million to goodwill, deferred
+income tax liability of $13.6 million and a $1.3 million asset
+retirement obligation. The goodwill and deferred income tax
+liability are a result of acquiring assets with tax basis that
+is lower than book basis. Accounting rules are inconsistent
+with the economic evaluation criteria we applied in
+determining the bid amount for this transaction because
+present value considerations cannot be applied to the amounts
+recorded for deferred income taxes.
+o We anticipate that acquisitions and our drilling programs will
+result in increased production.
+38
+A year-to-year overview of selected reserve, production and financial
+information, including trends:
+As of and for the Years Ended
+------------------------------------------- % of Change Between
+2004 2003 2002 2004/2003 2003/2002
+------------ ----------- ------------ --------- ---------
+Selected Operations Data (In Thousands, Except Price and Per MCFE Amounts):
+Total proved reserves (PV-10 basis)
+-----------------------------------
+Natural gas (Mcf) 319,196 307,024 274,172
+Oil (Bbl) 56,574 47,787 36,119
+MCFE 658,638 593,744 490,887 11% 21%
+Net production volumes
+----------------------
+Natural gas (Mcf) 46,598 49,663 38,164
+Oil (Bbl) 4,799 4,541 2,815
+MCFE 75,393 76,909 55,055 (2)% 40%
+MCFE per day 206 211 151 (2)% 40%
+Average daily production
+------------------------
+Natural gas (Mcf) 127 136 105
+Oil (Bbl) 13 12 8
+MCFE 206 211 151 (2)% 40%
+Oil & gas production revenues
+---------------------------------
+Gas production, including hedging $ 257,206 $ 242,670 $ 114,334
+Oil production, including hedging 156,112 122,444 71,336
+------------ ----------- ------------
+Total $ 413,318 $ 365,114 $ 185,670 13% 97%
+============ =========== ============
+Oil & gas production costs
+------------------------------
+Lease operating expenses $ 61,269 $ 59,152 $ 36,472
+Transportation costs 7,235 7,197 3,184
+Production taxes 27,014 22,160 11,183
+------------ ----------- ------------
+Total $ 95,518 $ 88,509 $ 50,839 8% 74%
+============ =========== ============
+Average realized sales price (1)
+--------------------------------
+Natural gas (per Mcf) $ 5.52 $ 4.89 $ 3.00 13% 63%
+Oil (per Bbl) $ 32.53 $ 26.96 $ 25.34 21% 6%
+Per MCFE data:
+--------------
+Average net realized price (1) $ 5.48 $ 4.75 $ 3.37 15% 41%
+Lease operating expense (0.81) (0.77) (0.66) 5% 17%
+Transportation costs (0.10) (0.09) (0.06) 11% 50%
+Production taxes (0.36) (0.29) (0.20) 24% 45%
+General and administrative (0.29) (0.28) (0.25) 4% 27%
+------------ ----------- ------------
+Operating profit $ 3.92 $ 3.32 $ 2.20 18% 49%
+============ =========== ============
+Depletion, depreciation and amortization $ 1.22 $ 1.07 $ 0.99 15% 8%
+Financial Information (In Thousands, Except Per Share Amounts):
+Working capital $ 12,035 $ 3,101 $ 2,050 358% 51%
+Long-term debt $ 136,791 $ 110,696 $ 113,601 24% (3)%
+Stockholders' equity $ 484,455 $ 390,653 $ 299,513 26% 30%
+Net income $ 92,479 $ 95,575 $ 27,560 (3)% 247%
+Basic net income per common share $ 3.21 $ 3.06 $ 0.99 5% 209%
+Diluted net income per common share $ 2.88 $ 2.80 $ 0.97 3% 189%
+Basic weighted-average shares outstanding 28,851 31,233 27,856 (8)% 12%
+Diluted weighted-average shares outstanding 33,447 35,534 28,391 (6)% 25%
+Net cash provided by operating activities $ 237,162 $ 204,319 $ 141,709 16% 44%
+$ (196,939) 25% 9%
+Net cash used in investing activities $ (247,006) ) $(180,931)
+Net cash provided by (used in) financing
+activities $ 1,435 $ (3,707) $ 46,260 139% (108)%
+--------------------
+(1) Includes the effects of our hedging activities.
+39
+We present this table as a summary of information relating to those key
+indicators of financial condition and operating performance that we believe to
+be important.
+The increase in our reserve volumes reflects our drilling results and
+acquisition activity combined with increases in natural gas and crude oil prices
+used to evaluate reserves. Please see Note 12 of Part IV, Item 15 for additional
+details. Over time these will be the factors that determine if we are successful
+in achieving our target of replacing 200 percent of our production each year. We
+anticipate that we must continue our successful drilling program and average one
+or more relatively significant acquisitions per year in the current price
+environment to achieve this level of growth. The measure of our success will
+vary from year-to-year due to changes in these factors, some of which we can
+control and others which we cannot control. From January 1, 2002, to December
+31, 2004, we replaced 259 percent of our production at a finding cost of $1.38
+per MCFE.
+The changes in production volumes, oil and gas production revenues and
+costs reflect the cyclical and highly volatile nature of prices our industry
+receives for production and the effect of the timing of acquisitions. Actual
+results in 2002 reflected a lower price environment than in either 2003 or 2004.
+We closed our acquisition of the Burlington Resources properties in late 2002
+and our acquisition of the Flying J properties in early 2003. Production of 13.8
+MMCFE from these two acquisitions was realized in 2003. These were the two
+largest acquisitions in our history and, combined with our successful drilling
+results in 2002 and 2003, resulted in a 40 percent increase in production from
+2002 to 2003. The comparison of changes in production from 2003 to 2004 reflects
+the mix of results from our drilling programs in 2004 and the timing of our
+acquisitions made in the fourth quarter of 2004.
+We present per MCFE information since we use this information to
+evaluate our performance relative to our peers and to measure trends that we
+believe require analysis. Our year-to-year comparison of financial results
+presented later provides additional details for the changes between years. We
+expect oil and gas production expenses will increase in 2005 as a result of
+increased activity in our higher-cost Rocky Mountain region, increased
+production taxes, and general inflation due to higher oil and gas pricing.
+Depreciation, depletion and amortization will continue to increase due to the
+higher costs associated with finding and acquiring crude oil and natural gas
+reserves. General and administrative expense is also projected to increase for
+expense associated with our net profits plan, expensing of stock-based
+compensation and costs we incur to comply with the Sarbanes-Oxley Act of 2002.
+We had a modest decrease in net income from 2003 to 2004. However, if
+we compare net income before the cumulative effect of change in accounting
+principle recorded in 2003, we had a net income increase driven by realized
+price increases of 13 percent for natural gas and 21 percent for oil. By
+containing our costs, our operating profit as a percentage of net realized price
+was 71 percent in 2004 compared to 70 percent in 2003 and 65 percent in 2002.
+Net income as a percentage of oil and gas revenue net of hedging loss was 22
+percent in 2004, 25 percent in 2003 and 15 percent in 2002.
+We have in-the-money stock options, unvested restricted stock units and
+convertible notes that are considered dilutive securities. At times these
+dilutive securities can affect our earnings per share, and both basic and
+diluted earnings per share are presented in the table above. You should review
+Note 1 of Part IV, Item 15 of this report for a detailed explanation. Our basic
+and diluted weighted-average common shares outstanding used in our 2004 earnings
+per share calculations reflects a decrease in shares caused by our repurchase of
+our common stock from Flying J and the re-initiation of our stock repurchase
+program offset by an increase in outstanding shares related to stock options.
+The remaining information in the table relates to information we have
+provided in operations update press releases and is intended to supplement the
+discussion above.
+40
+Overview of Liquidity and Capital Resources
+We own depleting assets. In order to maintain our current size and to
+sustain our projected growth levels, we will have to successfully invest capital
+into new projects and acquisitions. The following analysis and discussion
+includes our assessments of market risk and possible effects of inflation and
+changing prices.
+Sources of cash
+Our primary sources of liquidity are the cash provided by operating
+activities, debt financing, sales of non-strategic properties and access to the
+capital markets. All of these sources can be impacted by the general condition
+of our industry and significant fluctuations in oil and gas prices, operating
+costs and volumes produced. We have virtually no control over the market prices
+for oil and gas. A decrease in these market prices would reduce expected cash
+flow from operating activities, might reduce the borrowing base on our credit
+facility, could reduce the value of non-strategic properties we might consider
+selling and historically has limited our industry's access to the capital
+markets.
+Our current credit facility. On January 29, 2003, we entered into a
+$300.0 million credit facility with Wachovia Bank as Administrative Agent and
+eight other participating banks. This credit facility has a maturity date of
+January 27, 2006. We anticipate renegotiating the terms of our facility in the
+first quarter of 2005 to ensure that we have a credit facility in place beyond
+the date of current expiration. The calculated borrowing base as of December 31,
+2004, is $325.0 million. We have elected a commitment amount of $150.0 million
+under this facility, which results in lower commitment fees payable to the bank
+syndicate. We believe this commitment level is adequate for our near-term
+liquidity requirements. Under our existing credit facility, our next borrowing
+base redetermination is scheduled to occur by the end of April 2005. You should
+note the possibility that the banks may not agree to a borrowing base
+redetermination that is adequate for our planned financing requirements. We must
+comply with certain financial and non-financial covenants, and we are currently
+in compliance with all of these covenants. Interest and commitment fees are
+accrued based on the borrowing base utilization percentage. LIBOR based
+borrowings accrue interest at LIBOR plus the applicable margin from the
+utilization table located in Note 5 of Part IV, Item 15 of this report, and
+Alternate Base Rate borrowings accrue interest at prime plus the applicable
+margin from the utilization table. Commitment fees are accrued on the unused
+portion of the aggregate commitment amount and are included in interest expense
+in the consolidated statements of operations. Our loan balance of $37.0 million
+on December 31, 2004, was comprised of $10.0 million in ABR borrowings and $27.0
+million in LIBOR based loans.
+Our weighted-average interest rate paid in 2004 was 7.1 percent and
+included commitment fees paid on the unused portion of the credit facility
+borrowing base, amortization of deferred financing costs, and amortization of
+the contingent interest embedded derivative associated with the convertible
+notes.
+Interest Rate Market Risk. Market risk is estimated as the potential
+change in fair value resulting from an immediate hypothetical one-percentage
+point parallel shift in the yield curve. The sensitivity analysis discussed
+below presents the hypothetical change in fair value of those financial
+instruments we held at December 31, 2004, that are sensitive to changes in
+interest rates. For fixed-rate debt, interest rate changes affect the fair
+market value but do not impact results of operations or cash flows. Conversely,
+interest rate changes for floating-rate debt generally do not affect the fair
+market value but do impact future results of operations and cash flows, assuming
+other factors are held constant. The carrying amount of our floating rate debt
+approximates its fair value. After consideration of the effect of interest rate
+swaps discussed below, we had floating-rate debt of $87 million and fixed-rate
+debt of $50 million at December 31, 2004. Assuming constant debt levels, the
+41
+cash flow impact for the next year resulting from a one-percentage point change
+in interest rates would be approximately $870,000 before taxes. The results of
+operations impact might be less than this amount as a direct effect of the
+capitalization of interest for wells drilled in the next year. Since we cannot
+predict the exact amount that would be capitalized, we cannot predict the exact
+effect that a one-percentage point shift would have on the results of
+operations.
+Uses of cash
+We use cash for the acquisition, exploration and development of oil and
+gas properties and for the payment of debt obligations, trade payables and
+stockholder dividends. Exploration and development programs are generally
+financed from internally generated cash flow, debt financing and cash and cash
+equivalents on hand. Cash used for the acquisition of oil and gas properties and
+the payment of stockholder dividends is discretionary and can be reduced or
+eliminated in the event of an unexpected decrease in oil and gas prices. At any
+given point in time we may be obligated to pay for commitments to explore for or
+develop oil and gas properties or incur trade payables. However, future
+obligations can be reduced or eliminated when necessary. Over the next year we
+are required to only make interest payments on our debt obligations. An
+unexpected increase in oil and gas prices would provide flexibility to modify
+our uses of cash flow.
+Over the course of 2004 we increased our outstanding debt by a net
+$26.0 million. Using this amount, cash on hand and cash flows from operations we
+paid $68.8 million for property acquisitions, spent $199.4 million on capital
+development and used $35.7 million to repurchase our common stock. We also made
+$14.8 million of cash payments for income taxes and $2.8 million for dividends.
+At February 15, 2005, we had $46.0 million outstanding on our credit facility.
+On February 9, 2004, we repurchased for $91.0 million the 3,380,818
+restricted shares of common stock that we issued to Flying J on January 29,
+2003. Flying J used the proceeds to repay their outstanding loan principal
+balance to us of $71.6 million. Accrued interest on the loan, which was not
+recorded by us for financial reporting purposes due to the non-recourse nature
+of the loan, was forgiven. The $19.4 million net cash outlay was funded from our
+existing cash balance and borrowings under our credit facility. See Note 3 of
+Part IV, Item 15 of this report.
+We re-initiated our stock repurchase program in August 2004. Since that
+time we have repurchased a total of 489,300 shares of our common stock for $16.3
+million. As of February 15, 2005, there were 2,510,700 shares authorized to be
+repurchased under the program.
+The following table presents amounts and percentage changes between
+years in net cash flows from our operating, investing and financing activities.
+The analysis following the table should be read in conjunction with our
+consolidated statements of cash flows in Part IV, Item 15 of this report.
+Amount of Change Between Percent of Change Between
+----------------------------- -----------------------------
+2004/2003 2003/2002 2004/2003 2003/2002
+------------- ------------ ------------- ------------
+Net Cash Provided By Operating Activities $ 32,843 $ 62,610 16% 44%
+Net Cash Used In Investing Activities $ (50,067) $ (16,008) 25% 9%
+Net Cash Provided By (Used In) Financial Activities $ 5,142 $ (49,967) (139)% (108)%
+42
+Analysis of cash flow changes between 2004 and 2003
+Operating activities. Sources of cash flow from oil and gas sales
+increased $40.7 million from the period ended December 31, 2003 to the period
+ended December 31, 2004. This was a result of a 15 percent increase in our
+realized prices that offset a net production decrease between the comparative
+periods. Cash expenditures for operating expenses, exploration expense and
+administrative expenses increased by $2.4 million. Other revenue items decreased
+by $5.7 million.
+Investing Activities. The increase in net cash used resulted from $75.6
+million of increased drilling expenditures in 2004 over 2003 and from a 2004
+cash payment of $3.8 million held as a deposit for our Agate acquisition. These
+increases were offset by a $7.6 million decrease in acquisition activity in
+2004. Total capital expenditures increased by 34 percent to $268.2 million from
+$200.2 million in 2003. Proceeds from sales of oil and gas properties decreased
+by $20.7 million, but expiration of the restriction period for funds held for
+deferred tax exchange of oil and gas properties and net receipts from short-term
+investments resulted in a net cash provided change between periods of $41.8
+million. Volumes, revenue and net operating margin from properties that were
+sold in 2003 and 2004 were not a material component in the consolidated
+statements of operations or balance sheets for any year presented, nor do they
+represent a group of assets that would qualify for discontinued operations
+accounting treatment.
+Cash expended in 2003 for acquisitions of oil and gas properties
+included our utilization of $71.6 million of short-term investments, cash
+equivalents and increased borrowings under our credit facility to provide a loan
+to Flying J as part of our acquisition of properties. This loan was secured by
+the shares of our common stock issued in the transaction.
+Financing activities. The $5.1 million increase in cash provided by
+financing activities reflects the $26.0 million we borrowed on our credit
+facility in 2004 to fund acquisitions and drilling activity and an $11.5 million
+increase in proceeds from stock option exercises over the 2003 amounts. We paid
+$19.4 million to repurchase our shares from Flying J on February 9, 2004, and we
+paid $16.3 million to repurchase shares under our stock repurchase program. In
+2003 we borrowed to fund our acquisition of properties from Flying J and used
+cash flow from operations to reduce our outstanding debt for the year.
+St. Mary had $6.4 million in cash and cash equivalents and had working
+capital of $12.0 million as of December 31, 2004, compared to $14.8 million in
+cash and cash equivalents and working capital of $3.1 million as of December 31,
+2003.
+Analysis of cash flow changes between 2003 and 2002
+Operating activities. The differences above reflect increases in
+sources of cash flow from oil and gas sales due to a 40 percent increase in
+production and a 41 percent increase in price. We did not see the full $99.2
+million benefit of the net change between years in our cash flow since $40.8
+million of the change in net income, adjusted for non-cash items, related to a
+2003 increase in outstanding accounts receivable of $29.7 million and an $11.1
+million decrease in outstanding accounts receivable in 2002. The remaining $5.7
+million difference relates to proceeds from asset sales, collections of
+refundable income tax and increases in prepaid expenses and accounts payable.
+Investing Activities. The increase results primarily from additional
+capital and exploration costs. Total 2003 capital expenditures for cash,
+including acquisitions of oil and gas properties, increased $15.5 million or 8
+percent to $200.2 million in 2003 compared to $184.7 million in 2002. Increases
+in proceeds from sales were partially offset by amounts deposited in long-term
+restricted cash accounts for the tax-deferred exchange of oil and gas
+properties. The long-term restricted cash was available to be used for the
+43
+acquisition of oil and gas properties in 2004. The amount of cash invested in
+long-term restricted cash reflects our projection of the likelihood we will be
+successful. Our sales of proved oil and gas properties in 2003 resulted in $23.5
+million of cash proceeds. Revenue and net operating margin from the properties
+that we sold were not a material component of the current year or any prior year
+component of the consolidated statements of operations or balance sheets, nor do
+they represent a group of assets that would qualify for discontinued operations
+accounting treatment.
+Cash expended in 2003 for acquisitions of oil and gas properties
+includes our utilization of $71.6 million of short-term investments, cash
+equivalents and increased borrowings under our credit facility to provide a loan
+to Flying J as part of our acquisition of properties. This loan was secured by
+the shares of our common stock issued in the transaction.
+In December 2002 we purchased oil and gas properties from Burlington
+Resources Oil & Gas Company LP for $69.5 million in cash. We financed this
+acquisition using cash on hand and a portion of our credit facility.
+Financing activities. The $50.0 million decrease from 2002 to 2003
+reflects the issuance of our convertible notes and a $3.0 million pay down of
+our credit facility in 2003.
+In March 2002, we issued a total of $100.0 million of our convertible
+notes with a 0.5 percent contingent interest provision in a private placement.
+Interest payments are due on March 15 and September 15 of every year. We
+received net proceeds of $96.8 million after deducting the initial purchasers'
+discount and offering expenses payable by us. The convertible notes are general
+unsecured obligations and rank on a parity in right of payment with all our
+existing and future senior indebtedness and other general unsecured obligations,
+and are senior in right of payment with all our future subordinated
+indebtedness. We used a portion of the net proceeds from the convertible notes
+to repay our credit facility balance and used the remaining net proceeds to fund
+a portion of our 2002 capital expenditures. In October 2004 we entered into
+interest rate swap agreements on a total notional amount of $50.0 million of the
+convertible notes, which lowered our interest expense in 2004. The convertible
+notes can be converted into our common stock at a conversion price of $26.00 per
+share, subject to adjustment. See Note 5 of Part IV, Item 15 of this report for
+a more detailed discussion of the conversion features. The first date that St.
+Mary may redeem the convertible notes is in March 2007. Our current stock price
+is in excess of the $26.00 conversion price.
+St. Mary had $14.8 million in cash and cash equivalents and had working
+capital of $3.1 million as of December 31, 2003, compared to $11.2 million in
+cash and cash equivalents and working capital of $2.1 million as of December 31,
+2002.
+2005 Capital Expenditure Budget
+We continuously evaluate opportunities in the marketplace for oil and
+gas properties and, accordingly, may be a buyer or a seller of properties at
+various times. We will continue to emphasize smaller niche acquisitions
+utilizing our technical expertise, financial flexibility and structuring
+experience. In addition, we are also actively seeking larger acquisitions of
+assets or companies that would afford opportunities to expand our existing core
+areas, add additional geoscientists and/or engineers, or gain a significant
+acreage and production foothold in a new basin.
+44
+Expenditures for exploration and development of oil and gas properties
+and acquisitions are the primary use of our capital resources. We anticipate
+spending approximately $418 million for capital and exploration expenditures in
+2005 with $125 million allocated for acquisitions of producing properties.
+Anticipated ongoing exploration and development expenditures for each of our
+core areas are as follows:
+---------------------------------
+Gross Well
+In Millions Count
+--------------- ---------------
+Rocky Mountain region $ 95 118
+Mid Continent region 87 90
+Gulf Coast region 41 27
+ArkLaTex region 34 81
+Coalbed Methane 26 183
+Permian Basin region 10 35
+--------------- ---------------
+Total $ 293 534
+=============== ===============
+We regularly review our capital expenditure budget to reflect changes
+in current and projected cash flows, acquisition opportunities, debt
+requirements and other factors. The above allocations are subject to change
+based on various factors and results, including the availability of drilling and
+service rigs.
+The following table sets forth certain information regarding the costs
+incurred by us in our oil and gas activities:
+Years Ended December 31,
+-----------------------------------------------------
+2004 2003 2002
+--------------- ---------------- ---------------
+(In thousands)
+Development costs $ 190,829 $ 111,908 $ 74,376
+Exploration costs 37,977 33,296 22,548
+Acquisitions:
+Proved 69,054 73,989 85,559
+Unproved 7,646 8,942 2,147
+Leasing activity 7,877 7,480 8,128
+--------------- ---------------- ---------------
+Total $ 313,383 $ 235,615 $ 192,758
+=============== ================ ===============
+Our costs incurred for capital and exploration activities in 2004
+increased $77.8 million or 33 percent compared to 2003. This increase was a
+result of a planned $20.3 million increase in the drilling activity budget, a
+$17.1 million increase in the acquisition budget, an $8.6 million increase in
+capitalized costs associated with asset retirement obligations, and an
+additional $63.0 million spent on opportunities that arose during 2004. We
+reallocated $31.2 million from the acquisitions budget for these opportunities.
+We continue to move forward with the development of coalbed methane
+reserves in our Hanging Woman Basin project. We have 154,000 net lease acres in
+the basin and are concentrating our initial development on 80,000 net acres
+located in Wyoming. Outstanding legal challenges filed by environmental public
+interest groups affect 47,000 net acres in Montana relating to this project. See
+Legal Proceedings under Part I, Item 3 of this report.
+45
+In 2002 we used a portion of the proceeds from our convertible debt
+offering to fund our capital expenditures budget, but historically we have used
+internally generated cash flow, existing cash and our credit facility. We
+believe that internally generated cash flow and our credit facility will be
+utilized in 2005. The amount and allocation of future capital and exploration
+expenditures will depend upon a number of factors including the number and size
+of available acquisition opportunities, whether we can make economic
+acquisitions and our ability to assimilate acquisitions we are considering.
+Also, the impact of oil and gas prices on investment opportunities, the
+availability of capital and borrowing capability and the success of our
+development and exploratory activity could lead to funding requirements for
+further development.
+Financing alternatives
+The debt and equity financing capital markets remain very attractive to
+energy companies who operate in the exploration and production segment. This is
+a result of strong commodity prices and the general strength reflected in the
+balance sheets of the companies in this segment. As our cash balance and
+availability under our existing credit facility are significant, we are not
+currently considering accessing the capital markets in 2005. However, if
+additional development or attractive acquisition opportunities arise that exceed
+our current available resources, we may consider other forms of financing,
+including the public offering or private placement of equity or debt securities
+as well as expanding our borrowing availability under traditional secured bank
+financing.
+Sensitivity analysis
+The next table reflects our estimate of the effect on cash flow from
+operations for the years presented of a 10 percent change in our average
+realized sales price for natural gas, for oil and in total. These amounts have
+been reduced by the effective income tax rate applicable to each period since a
+reduction in revenue would reduce cash requirements to pay income taxes. General
+and administrative expenses have not been adjusted. To fund the capital and
+exploration expenditures we incurred in those years we would have been required
+to access our credit facility as a source of funds. In each of these years we
+had sufficient borrowing base available under our credit facility to meet this
+contingency without reducing or eliminating expenditures and affecting our
+growth strategy. Taking into account the February 15, 2005, loan balance of our
+credit facility we believe we have sufficient borrowing base available to
+continue our growth strategy if prices should change.
+Pro Forma effect on revenues of a 10
+percent change in average sales price:
+------------------------------------------------
+As of and for the Years Ended December 31,
+-------------------------------------------------
+2004 2003 2002
+-------------- ---------------- ---------------
+(In thousands)
+Natural Gas $ 15,280 $ 13,889 $ 6,944
+Oil $ 9,180 $ 6,979 $ 4,350
+-------------- ---------------- ---------------
+Total $ 24,460 $ 20,868 $ 11,294
+============== ================ ===============
+Summary of oil and gas production hedges in place
+Our net realized oil and gas prices are impacted by hedges we have
+placed on future forecasted transactions. We have historically entered into
+hedges of existing production around the time we make acquisitions of producing
+oil and gas properties. Our intent is to lock-in a significant portion of an
+equivalent amount of our existing production to the prices we used to evaluate
+the economics of our acquisition. We are also hedging a small percentage of our
+forecasted production on a discretionary basis.
+46
+Note 10 of Part IV, Item 15 of this report contains important
+information about our oil and gas derivative contracts including the volumes and
+average contract prices of hedges we currently have in place as of December 31,
+2004. We have not entered into any additional hedges as of February 15, 2005. We
+anticipate that all hedge transactions will occur as expected.
+For swap contracts in place on December 31, 2004, a hypothetical
+increase of 10 percent in future gas strip prices representing a $0.58
+weighted-average increase per MMBtu applied to a notional amount of 9.9 million
+MMBtu covered by natural gas swaps would cause a decrease in the value of
+derivative instruments of $5.7 million. A hypothetical increase of 10 percent in
+the future NYMEX strip oil prices representing a $4.12 increase per Bbl applied
+to a notional amount of 1.4 MMBbl covered by crude oil swaps would cause a
+decrease in the value of derivative instruments of $5.7 million.
+For collar contracts in place on December 31, 2004, a hypothetical
+increase of 10 percent in future gas strip prices representing a $0.57
+weighted-average increase per MMBtu applied to a notional amount of 1.9 million
+MMBtu covered by natural gas collars would cause a decrease in the value of
+derivative instruments of $729,000.
+The effect of price increases would impact our hedge gain or loss
+amounts. However, these are cash flow hedges with high correlation, and the
+price we receive on the underlying production would be higher by approximately
+the same amount. The effect on our results of operations would be minimal.
+Summary of interest rate hedges in place
+We entered into fixed-rate to floating-rate interest rate swaps on
+$50.0 million of convertible notes on October 3, 2003. We attempt to maintain a
+balanced allocation between fixed and floating rate debt. As our usage of the
+credit facility at that time was nearing zero, we elected to exchange fixed rate
+payments for floating rate payments on a portion of the interest on our
+convertible notes. This hedge does not qualify for fair value hedge treatment
+under SFAS No. 133, Accounting for Derivative Instruments and Hedging
+Activities. Excluding accrued payments due to us at December 31, 2004, the
+interest rate swaps had a fair value liability of $432,000. Derivative loss in
+the consolidated statements of operations for the years ended December 31, 2004,
+and 2003, includes $328,000 and $104,000, respectively, of loss related to the
+fair value liability increase.
+Schedule of contractual obligations
+The following table summarizes our future estimated principal payments
+and minimum lease payments for the periods specified (in millions):
+Less than More than 5
+Contractual Obligations Total 1 year 1-3 years 3-5 years years
+--------------------------- ----------- ----------- ----------- ----------- -------------
+Long-Term Debt $ 137.0 $ - $ 137.0 $ - $ -
+Operating Leases 10.7 2.4 3.1 2.3 2.9
+Other Long-Term Liabilities 10.6 1.8 4.7 1.7 2.4
+----------- ----------- ----------- ----------- -------------
+Total $ 158.3 $ 4.2 $ 144.8 $ 4.0 $ 5.3
+=========== =========== =========== =========== =============
+This table excludes the unfunded portion of our estimated pension
+liability of $1.4 million, as we cannot determine with accuracy the timing of
+future payments. The table also excludes estimated payments associated with our
+47
+net profits plan. We record a liability for the estimated future payments.
+However, predicting the precise timing the liability will be paid is contingent
+upon estimates of appropriate discount factors adjusting for risk and time-value
+and upon a number of factors that we cannot control. We have excluded asset
+retirement obligations because we are not able to precisely predict the timing
+for these amounts. Pension liabilities and asset retirement obligations are
+discussed in Note 8 and Note 9, respectively, and the net profits plan is
+discussed in Note 7 of Part IV, Item 15 of this report.
+Three leases for office space will expire in year 3, and a fourth
+office space lease will expire in year 4. Estimated costs to replace these
+leases are not included in the table above. For purposes of the table we assume
+that the holders of our convertible notes will not exercise the conversion
+feature. If the holders do exercise their conversion feature, we will not have
+to repay the $100.0 million upon conversion. Our common shares outstanding would
+increase by 3,846,150 shares.
+We believe that we will continue to pay annual dividends of at least
+$0.10 per share. We anticipate making cash payments for income taxes, dependent
+on net income and capital spending.
+Off-Balance Sheet Arrangements
+Aside from operating leases we do not have any off-balance sheet
+financing nor do we have any unconsolidated subsidiaries.
+Critical Accounting Policies and Estimates
+We are engaged in the exploration, development, acquisition and
+production of natural gas and crude oil. Our discussion of financial condition
+and results of operation is based upon the information reported in our
+consolidated financial statements. The preparation of these consolidated
+financial statements requires us to make assumptions and estimates that affect
+the reported amounts of assets, liabilities, revenues and expenses as well as
+the disclosure of contingent assets and liabilities at the date of our financial
+statements. We base our decisions affecting the estimates we use on historical
+experience and various other sources that are believed to be reasonable under
+the circumstances. Actual results may differ from the estimates we calculate due
+to changing business conditions or unexpected circumstances. Policies we believe
+are critical to understanding our business operations and results of operations
+are detailed below. For additional information on our significant accounting
+policies you should see Note 1 - Summary of Significant Accounting Policies,
+Note 9 - Asset Retirement Obligations, and Note 12 - Disclosures About Oil and
+Gas Producing Activities in Part IV, Item 15 of this report.
+Oil and gas reserve quantities. Estimated reserve quantities and the
+related estimates of future net cash flows are the most important estimates for
+an exploration and production company because they affect the perceived value of
+our company, are used in comparative financial analysis ratios, and are used in
+significant accounting estimates including the periodic calculations of
+depletion, depreciation and impairment for our proved oil and gas properties.
+Proved oil and gas reserves are the estimated quantities of crude oil, natural
+gas and natural gas liquids which geological and engineering data demonstrate
+with reasonable certainty to be recoverable in future periods from known
+reservoirs under existing economic and operating conditions. Future cash inflows
+and future production and development costs are determined by applying benchmark
+prices and costs, including transportation, quality and basis differentials, in
+effect at the end of each period to the estimated quantities of oil and gas
+remaining to be produced at the end of that period. Expected cash flows are
+reduced to present value using a discount rate that depends upon the purpose for
+which the reserve estimates will be used. For example, the standardized measure
+calculation required by SFAS No. 69, Disclosures about Oil and Gas Producing
+48
+Activities, requires a 10 percent discount to be applied. Although reserve
+estimates are inherently imprecise, and estimates of new discoveries and
+undeveloped locations are more imprecise than those of established proved
+producing oil and gas properties, we make considerable effort to estimate our
+reserves. We expect that periodic reserve estimates will change in the future as
+additional information becomes available or as oil and gas prices and operating
+and capital costs change. We evaluate and estimate our oil and gas reserves at
+December 31 and June 30 of each year. For purposes of depletion, depreciation,
+and impairment, reserve quantities are adjusted at all interim periods for the
+estimated impact of additions and dispositions. Changes in depletion,
+depreciation or impairment calculations caused by changes in reserve quantities
+or net cash flows are recorded in the period that the reserve estimates changed.
+The following table presents information regarding reserve changes from
+period to period that reflect changes from items we do not control, such as
+price, and from changes resulting from better information due to production
+history and well performance. These changes do not require a capital expenditure
+on our part, but may have resulted from capital expenditures we incurred to
+develop other estimated proved reserves.
+Years Ended December 31,
+----------------------------------------------------------------------------
+2004 2003 2002
+----------------------- ------------------------ -------------------------
+MMCFE Percent MMCFE Percent MMCFE Percent
+of total of total of total
+Change Additons Change Additons Change Additons
+---------- ----------- ----------- ----------- ----------- ------------
+Revisions resulting
+from price changes 16,206 11% 6,750 3% 33,931 20%
+Revisions resulting
+From performance (26,127) (18)% 14,290 6% (7,569) (4)%
+---------- ----------- ----------- ----------- ----------- ------------
+Total (9,921) (7)% 21,040 9% 26,362 16%
+========== =========== =========== =========== =========== ============
+Over the three-year period, we added 537.0 million MCFE of reserves,
+and 56.9 million MCFE, or 11 percent, were a result of price changes. A 19.4
+million MCFE, or four percent, reduction in reserves was a result of changes in
+estimates based on the performance of our oil and gas properties. As previously
+noted, oil and gas prices are volatile and estimates of reserves are inherently
+imprecise. Consequently, we anticipate we will continue to experience these
+types of changes.
+The following table reflects the estimated MMCFE change and percentage
+change to our reported reserve volumes from the described hypothetical changes:
+Years Ended December 31,
+----------------------------------------------------------------------
+2004 2003 2002
+---------------------- --------------------- -----------------------
+MMCFE Percent MMCFE Percent MMCFE Percent
+Change Change Change Change Change Change
+----------- --------- ---------- --------- ----------- ----------
+A 10% decrease in pricing 16,672 3% 9,479 2% 8,700 2%
+A 10% decrease in proved
+undeveloped reserves 9,839 1% 6,744 1% 6,043 1%
+Additional reserve information can be found in the reserve table and
+discussion included in Item 1 of Part I of this report.
+49
+Successful efforts method of accounting. Generally accepted accounting
+principles provide for two alternative methods for the oil and gas industry to
+use in accounting for oil and gas producing activities. These two methods are
+generally known in our industry as the full cost method and the successful
+efforts method. Both methods are widely used. The methods are different enough
+that in many circumstances the same set of facts will provide materially
+different financial statement results within a given year. We have chosen the
+successful efforts method of accounting for our oil and gas producing
+activities, and a detailed description is included in Note 1 of Part IV, Item 15
+of this report.
+Revenue recognition. Our revenue recognition policy is significant
+because revenue is a key component of our results of operations and our
+forward-looking statements contained in our analyses of liquidity and capital
+resources. We derive our revenue primarily from the sale of produced natural gas
+and crude oil. We report revenue gross for the amounts we receive before taking
+into account production taxes and transportation costs which are reported as
+separate expenses. Revenue is recorded in the month our production is delivered
+to the purchaser, but payment is generally received between 30 and 90 days after
+the date of production. At the end of each month we make estimates of the amount
+of production delivered to the purchaser and the price we will receive. We use
+our knowledge of our properties; their historical performance; the anticipated
+effect of weather conditions during the month of production; NYMEX and local
+spot market prices; and other factors as the basis for these estimates.
+Variances between our estimates and the actual amounts received are recorded in
+the month payment is received. A 10 percent change in our year-end revenue
+accrual would have impacted net income before tax by $7.9 million in 2004.
+Crude oil and natural gas hedging. Our crude oil and natural gas
+hedging contracts will usually qualify for cash flow deferral hedge accounting
+under SFAS No. 133. This policy is significant because it affects the timing of
+revenue recognition in our statements of operations and is discussed prominently
+in our forward-looking statements contained in our discussions of liquidity and
+capital resources. Under this accounting pronouncement a majority of the gain or
+loss from a contract qualifying as a cash flow hedge is deferred as to statement
+of operations recognition. The position reflected in the statement of operations
+is based on the actual settlements with the counterparty. If our natural gas and
+crude oil hedge contracts did not qualify for hedge accounting treatment or we
+chose not to use this hedge accounting methodology, our periodic statements of
+operations could include significant changes in the estimate of non-cash
+derivative gain or loss due to swings in the value of these contracts.
+Consequently we would report a different amount for oil and gas hedge loss in
+our statements of operations. These fluctuations could be especially significant
+in a volatile pricing environment such as we have encountered over the last
+three years. Net income after tax would have increased or (decreased) for 2004,
+2003 and 2002 by the following amounts: $2.6 million, $(14.3 million), and $(6.3
+million), respectively.
+Asset retirement obligations. Under SFAS No. 143, Accounting for Asset
+Retirement Obligations, we are required to recognize an estimated liability for
+future costs associated with the abandonment of our oil and gas properties. We
+base our estimate of the liability on our historical experience in abandoning
+oil and gas wells projected into the future based on our current understanding
+of federal and state regulatory requirements. Our projections require us to
+estimate economic lives of our properties, future inflation rates applied to
+external estimates as well as a credit adjusted risk-free rate to use in present
+value calculations. The statement of operations impact of this calculation is
+reflected in our depreciation, depletion and amortization calculations and
+occurs over the remaining life of our oil and gas properties.
+Valuation of long-lived and intangible assets. Our property and
+equipment is recorded at cost. An impairment allowance is provided on unproved
+property when we determine that the property will not be developed or the
+carrying value will not be realized. We evaluate the realizability of our proved
+properties and other long-lived assets whenever events or changes in
+circumstances indicate that impairment may be appropriate. Our impairment test
+50
+compares the expected undiscounted future net revenues from a property, using
+escalated pricing, with the related net capitalized costs of the property at the
+end of each period. When the net capitalized costs exceed the undiscounted
+future net revenue of a property, the cost of the property is written down to
+our estimate of fair value, which is determined by applying a discount rate that
+we believe is indicative of the current market. Our criteria for an acceptable
+internal rate of return are subject to change over time. Different pricing
+assumptions or discount rates could result in a different calculated impairment.
+Change in Net Profits Plan liability. We record the estimated liability
+of future payments under our net profits plan because it is a vested employee
+benefit. The estimated liability is calculated based on a number of interrelated
+assumptions we control, including estimates of oil and gas reserves, recurring
+and workover lease operating expense, tax rates, present value discount factors
+and certain pricing assumptions. The estimates we use in calculating the
+liability are modified by us from reporting period to reporting period based on
+new information attributable to the underlying assumptions. Changes in the
+estimated liability of future payments associated with this plan are recorded as
+increases or decreases to expense in the current period. Changes in estimated
+future pricing, the costs of operating properties, tax rates, reserve
+quantities, production rates, or discount factors could have a material impact
+on the calculated liability and our consolidated statements of operations.
+Changes in the expense caused by changes in the underlying estimates are
+recorded in the period that the estimates change. A significant component of the
+estimated future liability is based on oil and gas pricing. A 10 percent
+increase to the pricing assumptions used in the measurement of this liability at
+December 31, 2004 would have decreased net income before taxes by $8.1 million
+in 2004.
+Income taxes. We provide for deferred income taxes on the difference
+between the tax basis of an asset or liability and its carrying amount in our
+financial statements in accordance with SFAS No. 109, Accounting for Income
+Taxes. This difference will result in taxable income or deductions in future
+years when the reported amount of the asset or liability is recovered or
+settled, respectively. Considerable judgment is required in determining when
+these events may occur and whether recovery of an asset is more likely than not.
+Additionally, our federal and state income tax returns are generally not filed
+before the consolidated financial statements are prepared, therefore we estimate
+the tax basis of our assets and liabilities at the end of each period as well as
+the effects of tax rate changes, tax credits and net operating and capital loss
+carryforwards and carrybacks. Adjustments related to differences between the
+estimates we used and actual amounts we reported are recorded in the period in
+which we file our income tax returns. These adjustments and changes in our
+estimates of asset recovery could have an impact on our results of operations. A
+one percent change in our effective tax rate would have affected our calculated
+income tax expense by $1.5 million for the year ended December 31, 2004.
+Stock based compensation. We account for stock-based compensation using
+the intrinsic value recognition and measurement principles detailed in
+Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to
+Employees. No stock-based employee compensation expense relating to stock
+options has been reflected in our general and administrative expense as all
+options granted under our plans had an exercise price equal to the market value
+of the underlying common stock on the date of grant. We currently use the
+Black-Scholes option valuation model to calculate required disclosures under
+SFAS No. 123. In December 2004 the FASB issued SFAS No. 123(R), Shared-Based
+Payment. This statement provides for the accounting for transactions in which an
+entity exchanges equity instruments or incurs liabilities in exchange for goods
+or services. The statement is effective for us as of July 1, 2005. Following
+implementation, we anticipate that we will have expense associated with unvested
+options totaling $5.7 million that must be recorded in future periods under the
+modified-prospective method.
+51
+Additional Comparative Data in Tabular Format:
+Change Between Years
+----------------------------------------
+Oil and Gas Production Revenues: 2004 and 2003 2003 and 2002
+------------------ ------------------
+Increase in oil and gas production $ 48,204 $ 179,444
+revenues (in thousands)
+Components of Revenue Increases (Decreases):
+Natural Gas
+-----------
+Price change per Mcf $ 0.63 $ 1.89
+Price percentage change 13% 63%
+Production change (MMcf) (3,065) 11,499
+Production percentage change (6)% 30%
+Oil
+---
+Price change per Bbl $ 5.57 $ 1.62
+Price percentage change 21% 6%
+Production change (MBbl) 258 1,726
+Production percentage change 6% 61%
+Our product mix as a percentage of total oil and gas revenue and production:
+Years Ended December 31,
+-------------------------------------------------
+2004 2003 2002
+-------------- -------------- -------------
+Revenue
+-------
+Natural Gas 59% 66% 63%
+Oil 41% 34% 37%
+Production
+Natural Gas 62% 65% 69%
+Oil 38% 35% 31%
+Information regarding the effects of oil and gas hedging activity:
+Years Ended December, 31
+---------------------------------------------------------------
+2004 2003 2002
+------------------ ------------------- ------------------
+Natural Gas Hedging
+-------------------
+Percentage of gas production hedged 25% 40% 45%
+Natural gas MMBtu hedged 12.9 million 21.7 million 18.9 million
+(Decrease) in gas revenue ($15.5 million) ($11.4 million) ($4.1 million)
+Average realized gas price per Mcf before hedging $ 5.85 $ 5.12 $ 3.10
+Oil Hedging
+-----------
+Percentage of oil production hedged 45% 54% 54%
+Oil volumes hedged (MBbl) 2,156 2,474 1,518
+Increase (decrease) in oil revenue ($34.8 million) ($11.1 million) $1.9 million
+Average realized oil price per Bbl before hedging $ 39.77 $ 29.40 $ 24.69
+52
+Information regarding the components of exploration expense:
+Years Ended December 31,
+---------------------------------------------------
+2004 2003 2002
+-------------- --------------- --------------
+Summary of Exploration Expense (In millions)
+--------------------------------------------
+Geological and geophysical expenses $ 7.3 $ 5.1 $ 3.5
+Exploratory dry holes 4.2 8.5 7.7
+Overhead and other expenses 17.1 11.7 8.1
+-------------- --------------- --------------
+$ 28.6 $ 25.3 $ 19.3
+============== =============== ==============
+Comparison of Financial Results and Trends between 2004 and 2003
+Oil and gas production revenues. Average net daily production decreased
+two percent to 206.0 MMCFE for 2004 compared with 210.7 MMCFE in 2003. Wells
+completed and properties acquired in 2003 and during 2004 have added revenue of
+$102.8 million and average net daily production of 38.2 MMCFE in 2004 compared
+to 2003. These increases are offset by natural declines in production from older
+properties and 3.9 MMCFE per day of 2003 production from properties that were
+sold in 2003.
+Oil and gas hedge loss. As noted in the table above, the 124 percent
+increase in total oil and gas hedge loss to $50.3 million was caused by a 35
+percent increase in the average pre-hedge oil price and a 14 percent increase in
+the pre-hedge gas price.
+Oil and gas production expenses. Total production costs increased $7.0
+million or eight percent to $95.5 million for 2004, from $88.5 million in 2003.
+Our acquisition of properties added $2.8 million of incremental production
+costs, and wells completed in 2003 and 2004 added $7.7 million of incremental
+production costs in 2004 that were not reflected in 2003. We experienced an
+increase in production taxes consistent with the increase in revenue from higher
+realized prices.
+Total oil and gas production costs per MCFE increased $0.12 to $1.27
+for 2004, compared with $1.15 for 2003. This increase is comprised of the
+following:
+o A $0.07 increase in production taxes due to higher realized
+per MCFE prices;
+o A $0.01 increase in transportation costs;
+o A $0.01 decrease in LOE relating to workover charges;
+o A $0.04 increase in LOE that reflects increasing costs in our
+Rocky Mountain region; and
+o A $0.01 increase reflecting a general increases in LOE per
+MCFE in our other core areas.
+Exploration expense. Exploration expense increased 13 percent in 2004.
+The most significant component of our increase to exploration expense was $5.5
+million for exploration overhead we are incurring as we increase the size of our
+geologic and exploration staff.
+General and administrative expense. General and administrative expenses
+increased $807,000 or four percent to $22.0 million for 2004, compared with
+$21.2 million in 2003. The increase in cost on a per MCFE basis of $0.01
+reflects the effect of the four percent increase in G&A and a two percent
+decrease in production between the respective periods.
+An increase in our employee count from 226 to 249 has resulted in a
+general increase in G&A of $4.2 million between 2004 and 2003. That increase
+plus a $913,000 increase in fees that are directly related to Sarbanes-Oxley
+compliance, and a $959,000 increase in other professional fees were offset by an
+53
+increase of $5.5 million of general and administrative expense we allocated to
+exploration expense.
+Change in Net Profits Plan liability. This expense is the change in the
+net present value of estimated future incentive compensation payments to be made
+to plan participants under the computational provisions of the plan. During 2004
+we determined that the expense adjustment related to the estimated future net
+profits plan liability should be presented separately from general and
+administrative and exploration expense because this liability is calculated
+based on the estimated net cash flows not yet realized from the future
+production of oil and gas and as such are not current expenses like general and
+administrative or exploration expense. This reclassification has the effect of
+reducing previously reported general and administrative expense and exploration
+expense to include only those amounts paid or accrued under the net profits plan
+that relate to current period oil and gas operations. For the year ended
+December 31, 2004, the expense related to the change in the estimated liability
+for this plan increased to $24.4 million from $5.3 million for 2003. This
+increase is due to the performance of individual pools, the effect of a higher
+price environment, and the application of lower discount rates to reflect the
+current economics of the market. Adjustments to the liability are subject to
+estimation and may change dramatically from year-to-year based on assumptions
+used for production rates, reserve quantities, commodity pricing, discount
+rates, tax rates, and production costs.
+Interest expense. Interest expense decreased by $1.7 million to $6.2
+million for 2004 compared to $8.0 million for 2003. The decrease reflects the
+benefit of interest rate swaps we entered into on October 3, 2003, and decreased
+average borrowings under our credit facility in 2004 relative to the prior year.
+Income tax expense. Income tax expense totaled $53.7 million for 2004
+and $55.9 million in 2003, resulting in effective tax rates of 36.8 percent and
+38.3 percent, respectively. The effective rate change from 2003 reflects
+percentage depletion and other permanent differences as well as changes in the
+composition of the highest marginal state tax rates as a result of acquisition
+and drilling activity. The cumulative effect of the change in marginal state tax
+rates that we recorded in 2004 was a result of filing our 2003 income tax
+returns and completing the evaluation of the impact on future temporary
+difference reversals.
+The current portion of the income tax expense in 2004 is $22.5 million
+compared to $32.2 million in 2003. These amounts are 42 percent and 58 percent
+of the total tax for the respective periods. The difference results from
+decreased estimated taxable income caused by an increase in the estimated
+percentage of deductible intangible drilling costs relative to total income and
+the effect of an increase in stock option exercises. Unless the prices we
+receive for oil and gas change radically from our projections or we adjust the
+drilling portion of our budget, we estimate that the proportion of taxable
+income to book income will remain somewhat the same in 2005. Therefore, we
+believe that current taxable income will be lower and that the current portion
+of income tax as a percentage of total income tax will also remain somewhat the
+same.
+Cumulative effect of change in accounting principal, net of income tax.
+On January 1, 2003 we adopted SFAS No. 143. The impact of adoption resulted in
+income to us of $8.8 million offset by the deferred income tax effect of $3.4
+million. See Note 9 in Part IV, Item 15 of this report.
+Comparison of Financial Results and Trends between 2003 and 2002
+Oil and gas production revenues. Average net daily production increased
+40 percent to 210.7 MMCFE for 2003 compared with 150.8 MMCFE in 2002. Included
+in our 2003 production volumes are 13.8 MMCFE from the Burlington and Flying J
+54
+acquisitions. Wells completed and acquired in 2002 and 2003 have added revenue
+of $135.3 million and average net daily production of 71.0 MMCFE in 2003
+compared to 2002.
+Oil and gas hedge loss. The $20.2 million increase in loss between 2003
+and 2002 results from a combination of increased prices for oil and gas and an
+increase in the volumes we hedged as a result of our Burlington and Flying J
+property acquisitions.
+Oil and gas production expenses. Total production costs increased $37.7
+million to $88.5 million for 2003, from $50.8 million in 2002. Our acquisition
+of properties from Burlington and Flying J added $24.9 million of incremental
+production costs, and wells completed in 2002 and 2003 added $7.9 million of
+incremental production costs in 2003 that were not reflected in 2002.
+Additionally, we experienced an increase in production taxes consistent with the
+increase in revenue from higher realized prices.
+Total oil and gas production costs per MCFE increased $0.23 to $1.15
+for 2003, compared with $0.92 for 2002. This increase is comprised of the
+following:
+o A $0.09 increase in production taxes due to higher realized
+per MCFE prices;
+o A $0.03 increase due to rising transportation costs in our
+Rockies and Mid-Continent regions;
+o A $0.03 increase in LOE relating to workover charges for
+projects in our Gulf Coast, Rocky Mountain and ArkLaTex
+regions;
+o A $0.14 increase in LOE that reflects our addition of
+higher-cost oil properties in our Rocky Mountain region
+through acquisitions from Burlington and Flying J; and
+o A $0.06 decrease reflecting general decreases in LOE per MCFE
+in our other core areas.
+Exploration expense. Exploration expense increased 31 percent in 2003.
+The most significant component of our increase to exploration expense was $3.6
+million for increased exploration overhead due to increases in our geologic and
+exploration staff as a result of the acreage we have acquired in the Williston,
+Green River, Wind River and Powder River basins and due to increases in our
+exploration-related incentive compensation.
+General and administrative expense. General and administrative expenses
+increased $7.5 million or 55 percent to $21.2 million for 2003, compared with
+$13.7 million in 2002. The increase in cost on a per MCFE basis reflects a
+higher percentage increase in G&A than the proportionate increase in
+production of 40 percent for the period.
+An increase in our employee count from 185 to 226 resulted in a general
+increase in G&A of $5.4 million between 2003 and 2002. That increase plus a
+$6.8 million increase in expense associated with our incentive compensation
+plans, a $1.0 million increase in accrued charitable contributions expense and a
+$539,000 increase in insurance and corporate governance costs were offset by a
+$6.9 million increase in COPAS overhead reimbursement from operations and
+G&A we allocated to exploration expense. COPAS overhead reimbursement from
+operations increased by $3.5 million due to 413 additional properties we operate
+in our Rocky Mountain region as a result of our Burlington and Flying J
+acquisitions. During 2003 we sold 74 of these properties. The increase in
+expense associated with our incentive compensation plans reflects both the
+benefit we received from the current price environment for past employee
+performance and the performance of our employees during that year.
+55
+Change in Net Profits Plan liability. The increase in the estimated
+liability resulted in expense of $5.3 million for the year ended December 31,
+2003 compared to $846,000 for 2002.
+Interest expense. Interest expense increased by $4.1 million to $8.0
+million for 2003 compared to $3.9 million for 2002. The increase reflects a full
+year of accrued interest in 2003 on our convertible notes that were issued in
+March 2002, the benefit of an interest rate swap that reduced interest expense
+in 2002 by $839,000, the 0.5 percent contingent interest provision which applied
+in all of 2003 but for only 15 days during the comparable period in 2002, and
+increased borrowings under our credit facility in 2003 relative to the prior
+year.
+Income tax expense. Income tax expense totaled $55.9 million for 2003
+and $15.0 million in 2002, resulting in effective tax rates of 38.3 percent and
+35.3 percent, respectively. The effective rate change from 2002 reflected an
+increase in our highest marginal federal tax rate, the expiration of the Section
+29 tax credit, adjustments to valuation allowances to reflect the likelihood
+that prior Alternative Minimum Tax credits created by Section 29 credits will
+not be used, changes in the composition of the highest marginal state tax rates
+as a result of our recent acquisitions and the 2002 adjustment to valuation
+allowances against state income taxes from net operating loss carryovers.
+The current portion of the income tax expense in 2003 was $32.2 million
+compared to $569,000 in 2002. These amounts are 58 percent and 4 percent of the
+total tax for the respective periods. The difference resulted from increased
+taxable income caused by significantly higher oil and gas prices and production,
+and a reduction in the percentage of deductible intangible drilling costs
+relative to total income.
+Cumulative effect of change in accounting principal, net of income tax.
+On January 1, 2003 we adopted SFAS No. 143. The impact of adoption resulted in
+income to us of $8.8 million offset by the deferred income tax effect of $3.4
+million. See Note 9 of the Notes to Consolidated Financial Statements under Part
+IV, Item 15 of this report.
+Other Liquidity and Capital Resource Information
+Common Stock Activity
+On January 29, 2003, we financed the acquisition of oil and gas
+properties by issuing a total of 3,380,818 restricted shares of our common stock
+to Flying J Oil & Gas Inc. and Big West Oil & Gas Inc. In addition, we
+made a non-recourse loan to Flying J and Big West in the amount of $71.6 million
+at LIBOR plus 2 percent for up to a 39-month period. We also entered into a put
+and call option agreement with Flying J whereby during the 39-month loan period
+Flying J could elect to put these shares to us for $71.6 million plus accrued
+interest on the loan during the first thirty months of the loan period, and we
+could elect to call the shares for $97.4 million, with the proceeds from the
+exercise of either the put option or the call option to be applied to the
+repayment of the loan. For financial reporting purposes the above arrangements
+were treated as an acquisition of properties in exchange for $71.6 million of
+cash plus the net option to Flying J valued at $1.0 million, resulting in a
+total valuation of $72.6 million. See Note 3 of Part IV, Item 15 of this report.
+On February 9, 2004, we repurchased for $91.0 million the 3.4 million
+restricted shares of common stock. Flying J used the proceeds to repay their
+outstanding loan principal balance to us. Accrued interest on the loan, which
+was not recorded by us for financial reporting purposes due to the non-recourse
+nature of the loan, was forgiven. The $19.4 million net cash outlay was funded
+from our existing cash balance and borrowings under our credit facility. See
+Note 3 of Part IV, Item 15 of this report.
+56
+We reinitiated our stock repurchase program in August 2004. In the
+third quarter of 2004 we repurchased a total of 489,300 shares of our common
+stock for $16.3 million.
+During 2004 we received net proceeds of $14.0 million from employee's
+and director's options exercises on 699,526 shares of common stock.
+Pension Benefits
+Substantially all of our employees who meet age and service
+requirements participate in a non-contributory defined benefit pension plan. At
+December 31, 2004, we have recorded a $746,000 pre-tax loss in accumulated other
+comprehensive income related to this plan. We believe this obligation will be
+funded from future cash flow from operating activities. For purposes of
+calculating our obligation under the plan, we have used an expected return on
+plan assets of eight percent. We think this rate of return is appropriate over
+the long-term given the 60 percent equity and 40 percent debt securities mix of
+investment for plan assets and the historical rate of return provided by equity
+and debt securities since the 1920s. Our estimated rate of return was 11.7
+percent for 2004 and was 24.6 percent for 2003. The difference in investment
+income using our projected rate of return compared to our actual rates of return
+for the past two years was not material and will not have a material effect on
+statements of operation or cash flow from operating activities in future years.
+For the 2004 plan year, a 0.50 percentage point decrease in the
+discount rate combined with a 0.50 percentage point increase in the rate of
+future compensation increases caused a $971,000 increase in the projected
+benefit obligation of the plan. We do not believe this change was material and
+project that it will not have a material effect on the results of operations or
+on cash flow from operating activities in future periods.
+We also have a supplemental non-contributory defined benefit pension
+plan that covers certain management employees. There are no plan assets for this
+plan. For the 2004 plan year, a 0.50 percentage point decrease in the discount
+rate combined with a 0.50 percentage point increase in the rate of future
+compensation increases caused a $126,000 increase in the projected benefit
+obligation for this plan. This plan's accumulated benefit obligation was $1.2
+million at December 31, 2004, and 2003. We believe this obligation will be
+funded from future cash flow from operating activities.
+Accounting Matters
+We recognized a $5.4 million gain net of income tax in 2003 from the
+adoption of SFAS No. 143 effective January 1, 2003.
+In December 2004 the FASB issued a revision to SFAS No. 123. See Note 7
+of Part IV, Item 15 of this report for more detailed discussion regarding the
+impact of adoption.
+Environmental
+St. Mary's compliance with applicable environmental regulations has not
+resulted in any significant capital expenditures or materially adverse effects
+to our liquidity or results of operations. We believe we are in substantial
+compliance with environmental regulations and foresee that no material
+expenditures will be incurred in the future. However, we are unable to predict
+the impact that future compliance with regulations may have on future capital
+expenditures, liquidity and results of operations.
+57
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
+The information required by this item is provided under the captions
+"Interest Rate Market Risk" and "Sensitivity Analysis" in Item 7 above and is
+incorporated herein by reference.
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
+The Consolidated Financial Statements that constitute Item 8 follow the
+text of this report. An index to the Consolidated Financial Statements and
+Schedules appears in Item 15(a) of this report.
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
+FINANCIAL DISCLOSURE
+None.
+ITEM 9A. CONTROLS AND PROCEDURES
+We maintain a system of disclosure controls and procedures that are
+designed to ensure that information required to be disclosed in our SEC reports
+is recorded, processed, summarized and reported within the time periods
+specified in the SEC's rules and forms, and to ensure that such information is
+accumulated and communicated to our management, including the Chief Executive
+Officer and the Vice-President - Finance, as appropriate to allow timely
+decisions regarding required disclosure.
+We carried out an evaluation, under the supervision and with the
+participation of our management, including the Chief Executive Officer and the
+Vice-President - Finance, of the effectiveness of the design and operation of
+our disclosure controls and procedures as of the end of the period covered by
+this Annual Report on Form 10-K. Based upon that evaluation, the Chief Executive
+Officer and the Vice-President - Finance concluded that our disclosure controls
+and procedures are effective for the purposes discussed above as of the end of
+the period covered by this Annual Report on Form 10-K. There was no significant
+change in our internal control over financial reporting that occurred during our
+most recent fiscal quarter that has materially affected, or is reasonably likely
+to materially affect, our internal control over financial reporting.
+MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
+To the Stockholders' of St. Mary Land & Exploration Company
+Management of the Company is responsible for establishing and maintaining
+adequate internal control over financial reporting as defined in Rules 13a-15(f)
+and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The
+Company's internal control over financial reporting is designed to provide
+reasonable assurance regarding the reliability of financial reporting and the
+preparation of financial statements for external purposes in accordance with
+generally accepted accounting principles. The Company's internal control over
+financial reporting includes those policies and procedures that:
+(i) pertain to the maintenance of records that, in reasonable detail,
+accurately and fairly reflect the transactions and dispositions of the
+assets of the Company;
+(ii) provide reasonable assurance that transactions are recorded as
+necessary to permit preparation of financial statements in accordance
+with generally accepted accounting principles, and that receipts and
+58
+expenditures of the Company are being made only in accordance with
+authorizations of management and directors of the Company; and
+(iii) provide reasonable assurance regarding prevention or timely detection
+of unauthorized acquisition, use or disposition of the Company's
+assets that could have a material effect on the financial statements.
+Because of the inherent limitations, internal control over financial
+reporting may not prevent or detect misstatements. Also, projections of any
+evaluation of effectiveness to future periods are subject to the risk that
+controls may become inadequate because of changes in conditions, or that the
+degree of compliance with the policies or procedures may deteriorate.
+Management assessed the effectiveness of the Company's internal control
+over financial reporting as of December 31, 2004. In making this assessment,
+management used the criteria set forth by the Committee of Sponsoring
+Organizations of the Treadway Commission in Internal Control-Integrated
+Framework.
+Based on our assessment and those criteria, management believes that the
+Company maintained effective internal control over financial reporting as of
+December 31, 2004.
+The Company's independent auditors have issued an attestation report on
+management's assessment of the Company's internal controls over financial
+reporting. That report immediately follows this report.
+/S/ MARK A. HELLERSTEIN /S/ DAVID W. HONEYFIELD
+----------------------- -----------------------
+Mark A. Hellerstein David W. Honeyfield
+Chairman, CEO and President Vice President-Finance, Secretary &
+February 23, 2005 Treasurer
+February 23, 2005
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
+To the Board of Directors and Stockholders of
+St. Mary Land & Exploration Company and Subsidiaries
+We have audited management's assessment, included in the accompanying
+Management's Report on Internal Control over Financial Reporting, that St. Mary
+Land & Exploration Company and subsidiaries (the "Company") maintained
+effective internal control over financial reporting as of December 31, 2004,
+based on criteria established in Internal Control--Integrated Framework issued
+by the Committee of Sponsoring Organizations of the Treadway Commission. The
+Company's management is responsible for maintaining effective internal control
+over financial reporting and for its assessment of the effectiveness of internal
+control over financial reporting. Our responsibility is to express an opinion on
+management's assessment and an opinion on the effectiveness of the Company's
+internal control over financial reporting based on our audit.
+We conducted our audit in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). Those standards require that we plan
+and perform the audit to obtain reasonable assurance about whether effective
+internal control over financial reporting was maintained in all material
+respects. Our audit included obtaining an understanding of internal control over
+59
+financial reporting, evaluating management's assessment, testing and evaluating
+the design and operating effectiveness of internal control, and performing such
+other procedures as we considered necessary in the circumstances. We believe
+that our audit provides a reasonable basis for our opinions.
+A company's internal control over financial reporting is a process designed by,
+or under the supervision of, the company's principal executive and principal
+financial officers, or persons performing similar functions, and effected by the
+company's board of directors, management, and other personnel to provide
+reasonable assurance regarding the reliability of financial reporting and the
+preparation of financial statements for external purposes in accordance with
+generally accepted accounting principles. A company's internal control over
+financial reporting includes those policies and procedures that (1) pertain to
+the maintenance of records that, in reasonable detail, accurately and fairly
+reflect the transactions and dispositions of the assets of the company; (2)
+provide reasonable assurance that transactions are recorded as necessary to
+permit preparation of financial statements in accordance with generally accepted
+accounting principles, and that receipts and expenditures of the company are
+being made only in accordance with authorizations of management and directors of
+the company; and (3) provide reasonable assurance regarding prevention or timely
+detection of unauthorized acquisition, use, or disposition of the company's
+assets that could have a material effect on the financial statements.
+Because of the inherent limitations of internal control over financial
+reporting, including the possibility of collusion or improper management
+override of controls, material misstatements due to error or fraud may not be
+prevented or detected on a timely basis. Also, projections of any evaluation of
+the effectiveness of the internal control over financial reporting to future
+periods are subject to the risk that the controls may become inadequate because
+of changes in conditions, or that the degree of compliance with the policies or
+procedures may deteriorate.
+In our opinion, management's assessment that the Company maintained effective
+internal control over financial reporting as of December 31, 2004, is fairly
+stated, in all material respects, based on the criteria established in Internal
+Control--Integrated Framework issued by the Committee of Sponsoring
+Organizations of the Treadway Commission. Also in our opinion, the Company
+maintained, in all material respects, effective internal control over financial
+reporting as of December 31, 2004, based on the criteria established in Internal
+Control--Integrated Framework issued by the Committee of Sponsoring
+Organizations of the Treadway Commission.
+We have also audited, in accordance with the standards of the Public Company
+Accounting Oversight Board (United States), the consolidated financial
+statements as of and for the year ended December 31, 2004, of the Company, and
+our report dated February 23, 2005, expressed an unqualified opinion on those
+financial statements.
+/S/ DELOITTE & TOUCHE LLP
+Denver, Colorado
+February 23, 2005
+60
+PART III
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
+The information required by this Item concerning St. Mary's Directors
+is incorporated by reference to the information provided under the captions
+"Election of Directors" and "Nominees for Election of Directors" in St. Mary's
+definitive proxy statement for the 2005 annual meeting of stockholders to be
+filed within 120 days from December 31, 2004. The information required by this
+Item concerning St. Mary's executive officers is incorporated by reference to
+the information provided in Part I--Item 4A--EXECUTIVE OFFICERS OF THE
+REGISTRANT, included in this Form 10-K.
+The information required by this Item concerning compliance with
+Section 16(a) of the Securities Exchange Act of 1934 is incorporated by
+reference to the information provided under the caption "Section 16(a)
+Beneficial Ownership Reporting Compliance" in St. Mary's definitive proxy
+statement for the 2005 annual meeting of stockholders to be filed within 120
+days from December 31, 2004.
+ITEM 11. EXECUTIVE COMPENSATION
+The information required by this Item is incorporated by reference to
+the information provided under the captions, "Director Compensation," "Executive
+Compensation," "Report of the Compensation Committee on Executive Compensation,"
+"Retirement Plans," "Performance Graph," and "Employee Agreements and
+Termination of Employment and Change-in-Control Arrangements" in St. Mary's
+definitive proxy statement for the 2005 annual meeting of stockholders to be
+filed within 120 days from December 31, 2004.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
+RELATED STOCKHOLDER MATTERS
+The information required by this Item concerning security ownership of
+certain beneficial owners and management is incorporated by reference to the
+information provided under the caption "Security Ownership of Certain Beneficial
+Owners and Management" in St. Mary's definitive proxy statement for the 2005
+annual meeting of stockholders to be filed within 120 days from December 31,
+2004.
+The information required by this Item concerning securities authorized
+for issuance under equity compensation plans is incorporated by reference to the
+information provided under the caption "Equity Compensation Plans" in Part II -
+Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters,
+included in this Form 10-K.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+The information required by this Item is incorporated by reference to
+the information provided under the caption "Certain Relationships and Related
+Transactions" in St. Mary's definitive proxy statement for the 2005 annual
+meeting of stockholders to be filed within 120 days from December 31, 2004.
+ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
+The information required by this Item is incorporated by reference to
+the information provided under the caption "Independent Accountants" in St.
+Mary's definitive proxy statement for the 2005 annual meeting of stockholders to
+be filed within 120 days from December 31, 2004.
+61
+PART IV
+ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
+(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:
+Audit Report of Independent Registered
+Public Accounting Firm.................................... F-1
+Consolidated Balance Sheets...................................... F-2
+Consolidated Statements of Operations............................ F-3
+Consolidated Statements of Stockholders'
+Equity and Comprehensive Income........................... F-4
+Consolidated Statements of Cash Flows............................ F-5
+Notes to Consolidated Financial Statements....................... F-7
+All other schedules are omitted because the required information is not
+applicable or is not present in amounts sufficient to require submission of the
+schedule or because the information required is included in the Consolidated
+Financial Statements and Notes thereto.
+(b) Exhibits. The following exhibits are filed with or incorporated by
+reference into this report on Form 10-K:
+Exhibit
+Number Description
+------ -----------
+3.1 Restated Certificate of Incorporation of St. Mary Land &
+Exploration Company as amended in May 2001 (filed as Exhibit
+3.1 to the registrant's Quarterly Report on Form 10-Q for the
+quarter ended September 30, 2001 and incorporated herein by
+reference)
+3.2 Restated By-Laws of St. Mary Land & Exploration Company as
+amended on March 27, 2003 (filed as Exhibit 3.2 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended March 31, 2003 and incorporated herein by reference)
+4.1 St. Mary Land & Exploration Company Shareholder Rights
+Plan adopted on July 15, 1999 (filed as Exhibit 4.1 to the
+registrant's Quarterly Report on Form 10-Q/A for the quarter
+ended June 30, 1999 and incorporated herein by reference)
+4.2 First Amendment to Shareholders Rights Plan dated March 15,
+2002 as adopted by the Board of Directors on July 19, 2001
+(filed as Exhibit 4.2 to the registrant's Annual Report on
+Form 10-K for the year ended December 31, 2001 and
+incorporated herein by reference)
+10.1 St. Mary Land & Exploration Company Stock Option Plan, As
+Amended on May 22, 2003 (filed as Exhibit 99.1 to the
+registrant's Registration Statement on Form S-8 (Registration
+No. 333-106438) and incorporated herein by reference)
+10.2 St. Mary Land & Exploration Company Incentive Stock Option
+Plan, As Amended on March 25, 1999, January 27, 2000, March
+29, 2001, March 27, 2003 and May 22, 2003 (filed as Exhibit
+99.2 to registrant's Registration Statement on Form S-8
+(Registration No. 333-106438) and incorporated herein by
+reference)
+10.3 Cash Bonus Plan (filed as Exhibit 10.5 to the registrant's
+Registration Statement on Form S-1 (Registration No.
+33-53512) and incorporated herein by reference)
+10.4 Summary Plan Description/Pension Plan dated December 30, 1994
+(filed as Exhibit 10.35 to the registrant's Annual Report on
+Form 10-K for the year ended December 31, 1994 and
+incorporated herein by reference)
+10.5 Non-qualified Unfunded Supplemental Retirement Plan, as
+amended (filed as Exhibit 10.8 to the registrant's
+Registration Statement on Form S-1 (Registration No. 33-53512)
+and incorporated herein by reference)
+62
+Exhibit
+Number Description
+------ -----------
+10.6 St. Mary Land & Exploration Company Employee Stock
+Purchase Plan (filed as Exhibit 10.48 filed to the
+registrant's Annual Report on Form 10-K (for the year ended
+December 31, 1997 and incorporated herein by reference)
+10.7 First Amendment to St. Mary Land & Exploration Company
+Employee Stock Purchase Plan dated February 27, 2001 (filed
+as Exhibit 10.1 to the registrant's Quarterly Report on Form
+10-Q for the quarter ended June 30, 2001 and
+incorporated herein by reference)
+10.8 Form of Change of Control Severance Agreements (filed as
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
+for the quarter ended September 30, 2001 and incorporated
+herein by reference)
+10.9 Employment Agreement between Registrant and Mark A.
+Hellerstein (filed as Exhibit 10.15 to the registrant's
+Registration Statement on Form S-1 (Registration No. 33-53512)
+and incorporated herein by reference)
+10.10 Registration Rights Agreement between St. Mary Land &
+Exploration Company and Bear, Stearns & Co. Inc., et al
+dated March 13, 2002 (filed as Exhibit 10.25 to the
+registrant's Annual Report on Form 10-K for the year ended
+December 31, 2001 and incorporated herein by reference)
+10.11 St. Mary Land & Exploration Company 5.75% Senior
+Convertible Notes Due 2002 Indenture dated March 13, 2002
+(filed as Exhibit 10.26 to the registrant's Annual Report on
+Form 10-K for the year ended December 31, 2001 and
+incorporated herein by reference)
+10.12 Purchase and Sale Agreement dated October 1, 2002, effective
+as of July 1, 2002, between Burlington Resources Oil & Gas
+Company LP and The Louisiana Land and Exploration Company and
+Nance Petroleum Corporation (filed as Exhibit to the
+registrant's Current Report on Form 8-K filed on December 12,
+2002 and incorporated herein by reference)
+10.13 Purchase and Sale Agreement dated as of December 13, 2002
+among Flying J Oil & Gas Inc., Big West Oil & Gas
+Inc., NPC Inc. and St. Mary Land & Exploration Company
+(filed as Exhibit 10.1 to the registrant's Current Report on
+Form 8-K filed on February 13, 2003 and incorporated herein by
+reference)
+10.14 Addendum dated January 29, 2003 to Purchase and Sale Agreement
+dated December 13, 2002 (filed as Exhibit 10.2 to the
+registrant's Current Report on Form 8-K filed on February 13,
+2003 and incorporated herein by reference)
+10.15 Nonrecourse Secured Promissory Note dated January 29, 2003 by
+Flying J Oil & Gas Inc. and Big West Oil & Gas Inc.
+(filed as Exhibit 10.3 to the registrant's Current Report on
+Form 8-K filed on February 13, 2003 and incorporated
+herein by reference)
+10.16 Stock Pledge Agreement from Flying J Oil & Gas Inc. and
+Big West Oil & Gas Inc. to St. Mary Land & Exploration
+Company executed as of January 29, 2003 (filed as Exhibit
+10.4 to the registrant's Current Report on Form 8-K filed
+on February 13, 2003 and incorporated herein by reference)
+10.17 Registration Rights Agreement dated as of January 29, 2003
+among St. Mary Land & Exploration Company, Flying J Oil
+& Gas Inc. and Big West Oil & Gas Inc. (filed as
+Exhibit 10.5 to the registrant's Current Report on Form 8-K
+filed on February 13, 2003 and incorporated herein by
+reference)
+10.18 Put and Call Option Agreement dated as of January 29, 2003
+among St. Mary Land & Exploration Company, Flying J Oil
+& Gas Inc. and Big West Oil & Gas Inc. (filed as
+Exhibit 10.6 to the registrant's Current Report on Form 8-K
+filed on February 13, 2003 and incorporated herein by
+reference)
+63
+Exhibit
+Number Description
+------ -----------
+10.19 Standstill Agreement dated as of January 29, 2003 among St.
+Mary Land & Exploration Company, Flying J Oil & Gas
+Inc. and Big West Oil & Gas Inc. (filed as Exhibit 10.7 to
+the registrant's Current Report on Form 8-K filed on
+February 13, 2003 and incorporated herein by reference)
+10.20 Share Transfer Restriction Agreement dated as of January 29,
+2003 among St. Mary Land & Exploration Company, Flying
+J Oil & Gas Inc. and Big West Oil & Gas Inc. (filed as
+Exhibit 10.8 to the registrant's Current Report on Form 8-K
+filed on February 13, 2003 and incorporated herein by
+reference)
+10.21 Indemnity Guarantee Agreement dated January 29, 2003 between
+NPC Inc. and Flying J Inc. (filed as Exhibit 10.9 to
+the registrant's Current Report on Form 8-K filed on February
+13, 2003 and incorporated herein by reference)
+10.22 Security Agreement made as of May 1, 2002 by St. Mary Land
+& Exploration Company, St. Mary Operating Company, St.
+Mary Energy Company, Nance Petroleum Corporation, St. Mary
+Minerals Inc., Parish Corporation, Four Winds Marketing LLC,
+and Roswell LLC, in favor of Bank of America, N.A. (filed as
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
+for the quarter ended June 30, 2002 and incorporated
+herein by reference)
+10.23 Stock Pledge Agreement made as of May 1, 2002 by St. Mary Land
+& Exploration Company in favor of Bank of America, N.A.
+(filed as Exhibit 10.2 to the registrant's Quarterly Report on
+Form 10-Q for the quarter ended June 30, 2002 and incorporated
+herein by reference)
+10.24 LLC Pledge Agreement made as of May 1, 2002 by St. Mary Land
+& Exploration Company in favor of Bank of America, N.A.
+(filed as Exhibit 10.3 to the registrant's Quarterly Report on
+Form 10-Q for the quarter ended June 30, 2002 and incorporated
+herein by reference)
+10.25 Guaranty made as of May 1, 2002 by St. Mary Operating Company,
+St. Mary Energy Company, Nance Petroleum Corporation, St. Mary
+Minerals, Inc., Parish Corporation, Four Winds Marketing LLC
+and Roswell LLC in favor of Bank of America, N.A. (filed as
+Exhibit 10.4 to the registrant's Quarterly Report on Form 10-Q
+for the quarter ended June 30, 2002 and incorporated herein by
+reference)
+10.26 Credit Agreement dated as of January 27, 2003 among St. Mary
+Land & Exploration Company, Wachovia Bank, National
+Association of Administrative Agent, and the Lenders party
+thereto (filed as Exhibit 10.44 to the registrant's Annual
+Report on Form 10-K for the year ended December 31, 2003 and
+incorporated herein by reference)
+10.27 Amendment to and Extension of Office Lease dated as of
+December 14, 2001 (filed as Exhibit 10.45 to the registrant's
+Annual Report on Form 10-K for the year ended December 31,
+2003 and incorporated herein by reference)
+10.28 St. Mary Land & Exploration Company Non-Employee Director
+Stock Compensation Plan as adopted on March 27, 2003 (filed as
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
+for the quarter ended June 30, 2003 and incorporated herein by
+reference)
+10.29 Guaranty Agreement by St. Mary Energy Company in favor of
+Wachovia Bank, National Association, as Administrative Agent,
+dated January 27, 2003 (filed as Exhibit 10.4 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+10.30 Guaranty Agreement by St. Mary Operating Company in favor of
+Wachovia Bank, National Association, as Administrative Agent,
+dated January 27, 2003 (filed as Exhibit 10.5 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+64
+Exhibit
+Number Description
+------ -----------
+10.31 Guaranty Agreement by Nance Petroleum Corporation in favor of
+Wachovia Bank, National Association, as Administrative Agent,
+dated January 27, 2003 (filed as Exhibit 10.6 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+10.32 Guaranty Agreement by NPC Inc. in favor of Wachovia Bank,
+National Association, as Administrative Agent, dated January
+27, 2003 (filed as Exhibit 10.7 to the registrant's Quarterly
+Report on Form 10-Q for the quarter ended June 30, 2003 and
+incorporated herein by reference)
+10.33 Pledge and Security Agreement between St. Mary Land &
+Exploration Company and Wachovia Bank, National Association,
+as Administrative Agent, dated January 27, 2003 (filed as
+Exhibit 10.8 to the registrant's Quarterly Report on Form 10-Q
+for the quarter ended June 30, 2003 and incorporated herein by
+reference)
+10.34 Pledge and Security Agreement between Nance Petroleum
+Corporation and Wachovia Bank, National Association, as
+Administrative Agent, dated January 27, 2003 (filed as Exhibit
+10.9 to the registrant's Quarterly Report on Form 10-Q for the
+quarter ended June 30, 2003 and incorporated herein by
+reference)
+10.35 First Supplement and Amendment to Deed of Trust, Mortgage,
+Line of Credit Mortgage, Assignment, Security Agreement,
+Fixture Filing and Financing Statement for the benefit of
+Wachovia Bank, National Association, as Administrative Agent,
+dated effective as of January 27, 2003 (filed as Exhibit 10.10
+to the registrant's Quarterly Report on Form 10-Q for the
+quarter ended June 30, 2003 and incorporated herein by
+reference)
+10.36 Deed of Trust - St. Mary Land & Exploration to Wachovia
+Bank, National Association, as Administrative Agent, dated
+effective as of January 27, 2003 (filed as Exhibit 10.11 to
+the registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+10.37 Deed of Trust (CO, NV, SD) to Wachovia Bank, National
+Association, as Administrative Agent, dated effective as of
+April 2003 (filed as Exhibit 10.12 to the registrant's
+Quarterly Report on Form 10-Q for the quarter ended June 30,
+2003 and incorporated herein by reference)
+10.38 Deed of Trust (LA, MT, ND, NM, OK, TX, UT, WY) to Wachovia
+Bank, National Association, as Administrative Agent, dated
+effective as of April 2003 (filed as Exhibit 10.13 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+10.39 First Supplement and Amendment to Deed of Trust, Mortgage,
+Line of Credit Mortgage, Assignment, Security Agreement,
+Fixture Filing and Financing Statement for the benefit of
+Wachovia Bank, National Association, as Administrative Agent,
+dated effective as of April 2003 (filed as Exhibit 10.14 to
+the registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+10.40 Second Supplement and Amendment to Deed of Trust, Mortgage,
+Line of Credit Mortgage, Assignment, Security Agreement,
+Fixture Filing and Financing Statement for the benefit of
+Wachovia Bank, National Association, as Administrative Agent,
+dated effective as of April 2003 (filed as Exhibit 10.15 to
+the registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 and incorporated herein by reference)
+65
+Exhibit
+Number Description
+------ -----------
+10.41 First Amendment to Credit Agreement dated January 27, 2003
+among St. Mary Land & Exploration Company, Wachovia Bank,
+National Association as Issuing Bank and Administrative Agent,
+and the Lenders party thereto (filed as Exhibit 10.41 to the
+registrant's Annual Report on Form 10-K for the year ended
+December 31, 2003 and incorporated herein by reference)
+10.42 Net Profits Interest Bonus Plan, As Amended on February 3,
+2004 (filed as Exhibit 10.42 to the registrant's Annual Report
+on Form 10-K for the year ended December 31, 2003 and
+incorporated herein by reference)
+10.43 St. Mary Land & Exploration Company Restricted Stock Plan
+as adopted on April 18, 2004 (filed as Exhibit 10.1 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2004 and incorporated herein by reference)
+10.44 Second Amendment to Credit Agreement dated September 20, 2004
+among St. Mary Land & Exploration Company, Wachovia Bank,
+National Association as Issuing Bank and Administrative Agent,
+and the Lenders party thereto (filed as Exhibit 10.1 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended September 30, 2004 and incorporated herein by reference)
+10.45 Third Amendment to Credit Agreement dated October 20, 2004
+among St. Mary Land & Exploration Company, Wachovia Bank,
+National Association as Issuing Bank and Administrative Agent,
+and the Lenders party thereto (filed as Exhibit 10.2 to the
+registrant's Quarterly Report on Form 10-Q for the quarter
+ended September 30, 2004 and incorporated herein by reference)
+10.46 Form of Restricted Stock Unit Award Memorandum under the St.
+Mary Land & Exploration Company Restricted Stock Plan
+(filed as Exhibit 10.3 to the registrant's Quarterly Report on
+Form 10-Q for the quarter ended September 30, 2004 and
+incorporated herein by reference)
+10.47* Attachment A to Form of Change of Control Severance Agreement
+10.48* Second Amendment to the St. Mary Land & Exploration
+Employee Stock Puchase Plan dated February 18, 2005
+12.1* Computation of Ratio of Earnings to Fixed Charges
+14.1 Code of Business Conduct and Ethics
+21.1* Subsidiaries of Registrant
+23.1* Consent of Deloitte & Touche LLP
+23.2* Consent of Ryder Scott Company, L.P.
+23.3* Consent of Netherland, Sewell & Associates, Inc.
+24.1* Power of Attorney (included in signature page hereof)
+31.1* Certification of Chief Executive Officer pursuant to Section
+302 of the Sarbanes - Oxley Act of 2002
+31.2* Certification of Vice President - Finance pursuant to Section
+302 of the Sarbanes - Oxley Act of 2002
+32.1* Certification pursuant to U.S.C. Section 1350 as adopted
+pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
+----------------------------
+* Filed with this Form 10-K.
+(c) Financial Statement Schedules. See Item 15(a) above.
+66
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
+To the Board of Directors and Stockholders of
+St. Mary Land & Exploration Company and Subsidiaries
+We have audited the accompanying consolidated balance sheets of St. Mary Land
+& Exploration Company and subsidiaries (the "Company") as of December 31,
+2004 and 2003, and the related consolidated statements of operations,
+stockholders' equity and comprehensive income, and cash flows for each of the
+three years in the period ended December 31, 2004. These financial statements
+are the responsibility of the Company's management. Our responsibility is to
+express an opinion on these financial statements based on our audits.
+We conducted our audits in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). Those standards require that we plan
+and perform the audit to obtain reasonable assurance about whether the financial
+statements are free of material misstatement. An audit includes examining, on a
+test basis, evidence supporting the amounts and disclosures in the financial
+statements. An audit also includes assessing the accounting principles used and
+significant estimates made by management, as well as evaluating the overall
+financial statement presentation. We believe that our audits provide a
+reasonable basis for our opinion.
+In our opinion, such consolidated financial statements present fairly, in all
+material respects, the financial position of St. Mary Land & Exploration
+Company and subsidiaries as of December 31, 2004 and 2003, and the results of
+their operations and their cash flows for each of the three years in the period
+ended December 31, 2004, in conformity with accounting principles generally
+accepted in the United States of America.
+As discussed in Note 9 to the consolidated financial statements, the Company
+changed its method of accounting for asset retirement obligations in 2003 with
+the implementation of Statement of Financial Accounting Standards No. 143
+"Accounting for Asset Retirement Obligations".
+We have also audited, in accordance with the standards of the Public Company
+Accounting Oversight Board (United States), the effectiveness of the Company's
+internal control over financial reporting as of December 31, 2004, based on the
+criteria established in Internal Control--Integrated Framework issued by the
+Committee of Sponsoring Organizations of the Treadway Commission, and our report
+dated February 23, 2005, expressed an unqualified opinion on management's
+assessment of the effectiveness of the Company's internal control over financial
+reporting and an unqualified opinion on the effectiveness of the Company's
+internal control over financial reporting.
+/S/ DELOITTE & TOUCHE LLP
+Denver, Colorado
+February 23, 2005
+F-1
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED BALANCE SHEETS
+(In thousands, except share amounts)
+December 31,
+------------------------------
+ASSETS 2004 2003
+------------ ------------
+Current assets:
+Cash and cash equivalents $ 6,418 $ 14,827
+Short-term investments 1,412 12,509
+Accounts receivable 104,964 64,540
+Prepaid expenses and other 5,863 6,564
+Deferred income taxes - 8,872
+Accrued derivative asset 8,270 157
+Other - 454
+------------ ------------
+Total current assets 126,927 107,923
+------------ ------------
+Property and equipment (successful efforts method), at cost:
+Proved oil and gas properties 1,124,810 858,246
+Less - accumulated depletion, depreciation and amortization (399,013) (312,719)
+Unproved oil and gas properties, net of impairment allowance
+of $9,867 in 2004 and $10,776 in 2003 41,969 36,793
+Wells in progress 35,515 24,691
+Other property and equipment, net of accumulated depreciation
+of $6,459 in 2004 and $4,656 in 2003 5,244 4,276
+------------ ------------
+808,525 611,287
+------------ ------------
+------------ ------------
+Other noncurrent assets 10,008 16,644
+------------ ------------
+------------ ------------
+Total Assets $ 945,460 $ 735,854
+============ ============
+LIABILITIES AND STOCKHOLDERS' EQUITY
+Current liabilities:
+Accounts payable and accrued expenses $ 110,117 $ 81,217
+Accrued derivative liability 2,502 23,605
+Deferred income taxes 2,273 -
+------------ ------------
+Total current liabilities 114,892 104,822
+------------ ------------
+Noncurrent liabilities:
+Long-term credit facility 37,000 11,000
+Convertible notes 99,791 99,696
+Asset retirement obligation 40,911 25,485
+Net Profits Plan liability 30,561 6,163
+Deferred income taxes 129,830 90,947
+Other noncurrent liabilities 8,020 7,088
+------------ ------------
+Total noncurrent liabilities 346,113 240,379
+------------ ------------
+Commitments and contingencies (Note 6):
+Temporary equity (Note 3):
+Common stock subject to put and call options, $0.01 par value;
+issued and outstanding: -0- shares in 2004 and 3,380,818 shares
+in 2003 - 71,594
+Note receivable from Flying J - (71,594)
+------------ ------------
+Total temporary equity - -
+------------ ------------
+Stockholders' equity:
+Common stock, $0.01 par value: authorized - 100,000,000 shares;
+issued: 28,729,123 shares in 2004 and 29,245,123 shares in 2003;
+outstanding, net of treasury shares: 28,479,123 shares in 2004
+and 28,242,423 shares in 2003 287 292
+Additional paid-in capital 127,661 146,362
+Treasury stock, at cost: 250,000 shares in 2004 and 1,002,700
+shares in 2003 (5,295) (16,057)
+Deferred stock-based compensation (5,039) -
+Retained earnings 364,567 274,937
+Accumulated other comprehensive income (loss) 2,274 (14,881)
+------------ ------------
+Total stockholders' equity 484,455 390,653
+------------ ------------
+------------ ------------
+Total Liabilities and Stockholders' Equity $ 945,460 $ 735,854
+============ ============
+The accompanying notes are an integral part to these
+consolidated financial statements.
+F-2
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED STATEMENTS OF OPERATIONS
+(In thousands, except share amounts)
+For the Years Ended December 31,
+--------------------------------------------------
+2004 2003 2002
+-------------- -------------- --------------
+Operating revenues:
+Oil and gas production $ 463,617 $ 387,553 $ 187,905
+Oil and gas hedge loss (50,299) (22,439) (2,235)
+Gain(loss) on sale of proved properties 1,803 7,278 (2,633)
+Marketed gas revenue 15,551 13,438 8,399
+Other oil and gas revenue 2,342 3,538 682
+Derivative gain - - 3,188
+Other revenue 85 4,340 999
+-------------- -------------- --------------
+Total operating revenues 433,099 393,708 196,305
+-------------- -------------- --------------
+Operating expenses:
+Oil and gas production 95,518 88,509 50,839
+Depletion, depreciation, amortization
+and abandonment liability accretion 92,223 81,960 54,432
+Exploration 28,560 25,318 19,271
+Impairment of proved properties 494 185 -
+Abandonment and impairment of unproved properties 1,420 3,796 2,446
+General and administrative 22,004 21,197 13,683
+Change in Net Profits Plan liability 24,398 5,317 846
+Marketed gas system operating expense 14,230 12,229 7,982
+Derivative loss 260 310 -
+Other 2,077 1,576 1,117
+-------------- -------------- --------------
+Total operating expenses 281,184 240,397 150,616
+-------------- -------------- --------------
+Income from operations 151,915 153,311 45,689
+Nonoperating income(expense):
+Interest income 557 717 758
+Interest expense (6,244) (7,958) (3,868)
+Income before income taxes and cumulative effect
+of change in accounting principle 146,228 146,070 42,579
+Income tax expense (53,749) (55,930) (15,019)
+-------------- -------------- --------------
+Income before cumulative effect of change in accounting principle 92,479 90,140 27,560
+Cumulative effect of change in accounting principle,
+net of income tax - 5,435 -
+-------------- -------------- --------------
+Net income $ 92,479 $ 95,575 $ 27,560
+============== ============== ==============
+Basic weighted-average common shares outstanding 28,851 31,233 27,856
+Diluted weighted-average common shares outstanding 33,447 35,534 28,391
+Basic earnings per common share:
+Income before cumulative effect of change in accounting principle $ 3.21 $ 2.89 $ 0.99
+Cumulative effect of change in accounting
+principle, net of income tax - 0.17 -
+-------------- ------------- --------------
+Basic net income per common share $ 3.21 $ 3.06 $ 0.99
+============== ============= ==============
+Diluted earnings per common share:
+Income before cumulative effect of change in accounting principle $ 2.88 $ 2.65 $ 0.97
+Cumulative effect of change in accounting
+principle, net of income tax - 0.15 -
+-------------- -------------- --------------
+Diluted net income per common share $ 2.88 $ 2.80 $ 0.97
+============== ============== ==============
+Cash dividends declared per common share $ 0.10 $ 0.10 $ 0.10
+============== ============== ==============
+The accompanying notes are an integral part to these
+consolidated financial statements.
+F-3
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
+(In thousands, except share amounts)
+Accumulated
+Common Stock Additional Treasury Stock Deferred Other Total
+----------------- Paid-in --------------------- Stock-Based Retained Comprehensive Stockholders'
+Shares Amount Capital Shares Amount Compensation Earnings Income (Loss) Equity
+---------- ------ --------- ----------- --------- ------------ -------- ------------- -------------
+Balances, December 31, 2001 28,779,808 $ 288 $137,384 (1,009,900) $(16,210) $ - $157,739 $ 6,916 $ 286,117
+Comprehensive income:
+Net income - - - - - - 27,560 - 27,560
+Unrealized net loss on
+marketable equity
+securities available
+for sale - - - - - - - (725) (725)
+Change in derivative
+instrument fair value - - - - - - - (14,644) (14,644)
+Reclassification to earnings - - - - - - - 1,447 1,447
+Minimum pension liability
+adjustment - - - - - - - (761) (761)
+-------------
+Total comprehensive income 12,877
+-------------
+Cash dividends declared, $ 0.10
+per share - - - - - - (2,787) - (2,787)
+Issuance of common stock
+under Employee Stock
+Purchase Plan 18,217 - 344 - - - - - 344
+ESPP disqualified distribution - - 21 - - - - - 21
+Sale of common stock, including
+income tax benefit of
+stock option exercises 177,085 2 2,743 - - - - - 2,745
+Accelerated vesting of retiring
+director's options - - 52 - - - - - 52
+Directors' stock compensation 8,000 - 144 - - - - - 144
+---------- ------ --------- ----------- --------- ------------ -------- ------------- -------------
+Balances, December 31, 2002 28,983,110 $ 290 $140,688 (1,009,900) $(16,210) $ - $182,512 $ (7,767) $ 299,513
+Comprehensive income:
+Net income - - - - - - 95,575 - 95,575
+Unrealized net
+gain on marketable
+equity securities
+available for sale - - - - - - - 716 716
+Change in derivative
+instrument fair value - - - - - - - (21,873) (21,873)
+Reclassification to earnings - - - - - - - 13,846 13,846
+Minimum pension liability
+adjustment - - - - - - - 197 197
+-------------
+Total comprehensive income 88,461
+-------------
+Cash dividends declared, $ 0.10
+per share - - - - - - (3,150) - (3,150)
+Issuance of common stock
+under Employee Stock
+Purchase Plan 16,994 - 375 - - - - - 375
+Value of option right granted
+to Flying J - - 995 - - - - - 995
+Sale of common stock, including
+income tax benefit of
+stock option exercises 245,019 2 4,304 - - - - - 4,306
+Directors' stock compensation - - - 7,200 153 - - - 153
+---------- ------ --------- ----------- --------- ------------ -------- ------------- -------------
+Balances, December 31, 2003 29,245,123 $ 292 $146,362 (1,002,700) $(16,057) $ - $274,937 $ (14,881) $ 390,653
+Comprehensive income:
+Net income - - - - - - 92,479 - 92,479
+Change in derivative
+instrument fair value - - - - - - - (14,795) (14,795)
+Reclassification to earnings - - - - - - - 31,849 31,849
+Minimum pension liability
+adjustment - - - - - - - 101 101
+-------------
+Total comprehensive income 109,634
+-------------
+Cash dividends declared, $ 0.10
+per share - - - - - - (2,849) - (2,849)
+Repurchase of common stock from
+Flying J - - (19,406) - - - - - (19,406)
+Treasury stock purchases - - - (489,300) (16,336) - - - (16,336)
+Retirement of treasury stock (1,229,400) (12) (26,737) 1,229,400 26,749 - - - -
+Issuance of common stock
+under Employee Stock
+Purchase Plan 13,874 - 375 - - - - - 375
+Sale of common stock, including
+income tax benefit of
+stock option exercises 699,526 7 17,839 - - - - - 17,846
+Deferred compensation related to
+issued restricted stock
+unit awards - - 8,122 - - (8,122) - - -
+Accrued stock-based compensation - - 1,106 - - - - - 1,106
+Amortization of deferred
+stock-based compensation - - - - - 3,083 - - 3,083
+Directors' stock compensation - - - 12,600 349 - - - 349
+---------- ------ --------- ----------- --------- ------------ -------- ------------- -------------
+Balances, December 31, 2004 28,729,123 $ 287 $127,661 (250,000) $ (5,295) $ (5,039) $364,567 $ 2,274 $ 484,455
+========== ====== ========= =========== ========= ============ ======== ============= =============
+The accompanying notes are an integral part to these
+consolidated financial statements.
+F-4
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED STATEMENTS OF CASH FLOWS
+(In thousands)
+For the Years Ended December 31,
+--------------------------------------------------
+2004 2003 2002
+-------------- -------------- --------------
+Reconciliation of net income to net cash provided by operating activities:
+Net income $ 92,479 $ 95,575 $ 27,560
+Adjustments to reconcile net income to net cash
+provided by operating activities:
+(Gain) loss on sale of proved properties (1,803) (7,278) 2,633
+Depletion, depreciation, amortization
+and abandonment liability accretion 92,223 81,960 54,432
+Exploratory dry hole expense 4,162 8,482 7,677
+Impairment of proved properties 494 185 -
+Abandonment and impairment of unproved properties 1,420 3,796 2,446
+Unrealized derivative loss 260 310 373
+Change in Net Profits Plan liability 24,398 5,317 846
+Deferred and accrued stock-based compensation 4,189 - -
+Income tax benefit from the exercise of stock options 3,816 1,151 719
+Deferred income taxes 39,573 20,536 13,914
+Other (1,948) 2,088 (1,642)
+Cumulative effect of change in accounting principle, net of tax - (5,435) -
+Changes in current assets and liabilities:
+Accounts receivable (39,880) (29,685) 11,085
+Prepaid expenses and other 157 490 (4,173)
+Accounts payable and accrued expenses 17,622 26,827 25,839
+-------------- -------------- --------------
+Net cash provided by operating activities 237,162 204,319 141,709
+-------------- -------------- --------------
+Cash flows from investing activities:
+Proceeds from sale of oil and gas properties 2,829 23,497 1,624
+Capital expenditures (199,385) (123,823) (97,257)
+Acquisition of oil and gas properties, including related
+$71,594 loan to Flying J in 2003 (68,805) (76,413) (87,466)
+Deposits to short-term investments available-for-sale (1,470) (12,529) (13,523)
+Receipts from short-term investments available-for-sale 12,500 2,450 12,538
+Receipts from restricted cash 10,353 11,500 -
+Deposits to restricted cash - (21,853) -
+Other (3,028) 232 3,153
+-------------- -------------- --------------
+Net cash used in investing activities (247,006) (196,939) (180,931)
+-------------- -------------- --------------
+Cash flows from financing activities:
+Proceeds from credit facility 181,497 140,933 37,400
+Repayment of credit facility (155,500) (145,020) (87,400)
+Proceeds from issuanace of convertible debt - - 96,657
+Proceeds from sale of common stock for exercise of stock options 14,030 3,530 2,390
+Repurchase of common stock (35,743) - -
+Dividends paid (2,849) (3,150) (2,787)
+-------------- -------------- --------------
+Net cash provided by (used in) financing activities 1,435 (3,707) 46,260
+-------------- -------------- --------------
+Net change in cash and cash equivalents (8,409) 3,673 7,038
+Cash and cash equivalents at beginning of period 14,827 11,154 4,116
+-------------- -------------- --------------
+Cash and cash equivalents at end of period $ 6,418 $ 14,827 $ 11,154
+============== ============== ==============
+The accompanying notes are an integral part to these
+consolidated financial statements.
+F-5
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
+(In thousands)
+Supplemental schedule of additional cash flow information and noncash investing
+and financing activities:
+For the Years Ended December 31,
+--------------------------------------------------
+2004 2003 2002
+-------------- -------------- --------------
+(in thousands)
+Cash paid for interest, including amounts capitalized $ 8,859 $ 7,555 $ 2,498
+Cash paid (refunded) for income taxes 14,787 28,858 (550)
+In August 2004 the Company closed a transaction whereby it exchanged oil and gas
+properties valued at $1.4 million together with $769,000 of cash for oil and gas
+properties valued at $2.2 million.
+In June 2004 the Company issued 232,861 restricted stock units pursuant to the
+Company's restricted stock plan. The total value of the grant was $8.3 million,
+which as of December 31, 2004 has been reduced by $178,000 for forfeitures. The
+Company has recorded compensation expense related to the 2004 grant of $3.1
+million for the year ended December 30, 2004.
+In January 2004 and May 2004 the Company issued 4,200 shares and 8,400 shares,
+respectively, of common stock from treasury to its non-employee directors
+pursuant to the Company's non-employee director stock compensation plan. The
+Company recorded compensation expense of $349,000 for year ended December 31,
+2004.
+In January 2003 the Company issued 7,200 shares of common stock from treasury to
+its non-employee directors and recorded compensation expense of $153,000.
+In January 2003 the Company issued 3,380,818 restricted shares of common stock
+to Flying J Oil & Gas Inc. and Big West Oil & Gas Inc. (collectively,
+"Flying J") and entered into a put and call option agreement, valued at $995,000
+for financial reporting purposes, with Flying J with respect to those shares in
+connection with the acquisition of oil and gas properties and related assets and
+liabilities.
+In June 2002 the Company issued 800 shares of common stock to a non-employee
+director and recorded compensation expense of $14,763.
+In April 2002 the Company accepted 9,472,562 shares of common stock in
+Constellation Copper Corporation ("Constellation", formerly known as Summo
+Minerals Corporation) in lieu of cash payment for the relief of a $1,400,000
+loan and $15,311 in interest due to the Company.
+In January 2002 the Company issued 7,200 shares of common stock to its
+non-employee directors and recorded compensation expense of $129,683.
+The accompanying notes are an integral part to these
+consolidated financial statements.
+F-6
+ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+DECEMBER 31, 2004
+Note 1 - Summary of Significant Accounting Policies
+Description of Operations
+St. Mary Land & Exploration Company ("St. Mary" or the "Company")
+is an independent energy company engaged in the exploration, exploitation,
+development, acquisition and production of natural gas and crude oil. The
+Company's operations are conducted entirely in the continental United States.
+Basis of Presentation
+The consolidated financial statements include the accounts of the
+Company and its wholly owned subsidiaries. Subsidiaries that are not wholly
+owned are accounted for using full consolidation with minority interest or by
+the equity or cost method as appropriate. Equity method investments are included
+in other noncurrent assets, and minority interest is included in other
+noncurrent liabilities in the accompanying consolidated balance sheets. All
+significant intercompany accounts and transactions have been eliminated
+Certain amounts in 2003 and 2002 financial statements have been
+reclassified to conform to the 2004 financial statement presentation. The
+non-cash portion of Net Profits Interest Bonus Plan (the "Net Profits Plan")
+expense and the corresponding liability have been reclassified as separate line
+items in the accompanying financial statements for all periods presented. As a
+result, prior period general and administrative expense, exploration expense and
+other non-current liabilities have been reclassified to conform to the current
+presentation. Additionally, wells in progress have been classified as a separate
+line item in the consolidated balance sheets for all periods presented. As a
+result, prior period unproved oil and gas properties, net of impairment
+allowance, have been reclassified to conform to the current presentation.
+Use of Estimates in the Preparation of Financial Statements
+The preparation of financial statements in conformity with accounting
+principles generally accepted in the United States requires management to make
+estimates and assumptions that affect the reported amounts of oil and gas
+reserves, assets and liabilities and disclosure of contingent assets and
+liabilities at the date of the financial statements and the reported amounts of
+revenues and expenses during the reporting period. Actual results could differ
+from those estimates
+Cash and Cash Equivalents
+The Company considers all liquid investments purchased with an initial
+maturity of three months or less to be cash equivalents. The carrying value of
+cash and cash equivalents approximates fair value due to the short-term nature
+of these instruments.
+F-7
+Short-term Investments
+The Company's short-term investments consist primarily of
+investment-grade marketable debt, which is classified as available-for-sale.
+Securities that have been categorized as available-for-sale are stated at fair
+value based on quoted market prices. The following table summarizes the
+estimated fair value of the components of the Company's available-for-sale
+short-term investments:
+As of December 31,
+----------------------------------------
+2004 2003
+----------------- ----------------
+(in thousands)
+Corporate debt securities $ 1,412 $ 1,009
+Escrowed cash $ - $ 11,500
+----------------- ----------------
+Total $ 1,412 $ 12,509
+================= ================
+Concentration of Credit Risk
+Substantially all of the Company's receivables are within the oil and
+gas industry, primarily from purchasers of oil and gas and from joint interest
+owners. Although diversified among many companies, collectability is dependent
+upon the financial wherewithal of each individual company as well as the general
+economic conditions of the industry. The receivables are not collateralized. To
+date the Company has had minimal bad debts.
+The Company has accounts with separate banks in Denver, Colorado;
+Shreveport, Louisiana; Tulsa, Oklahoma; Houston, Texas; and Billings, Montana.
+At December 31, 2004, 2003 and 2002, the Company had $22.2 million, $23.5
+million, and $4.9 million respectively, invested in money market funds
+(including margin accounts) consisting of corporate commercial paper, repurchase
+agreements and U.S. Treasury obligations. The difference between the investment
+amount and the cash and cash equivalents amount on the consolidated balance
+sheets, represents uncleared disbursements. The Company's policy is to invest in
+highly rated instruments and to limit the amount of credit exposure at each
+individual institution.
+Oil and Gas Producing Activities
+The Company follows the successful efforts method of accounting for its
+oil and gas properties. Under this method of accounting, all property
+acquisition costs and costs of exploratory and development wells are capitalized
+when incurred, pending determination of whether the well has found proved
+reserves. If an exploratory well does not find proved reserves, the costs of
+drilling the well are charged to expense. Exploratory dry hole costs are
+included in cash flows from investing activities as part of capital expenditures
+within the consolidated statements of cash flows. The costs of development wells
+are capitalized whether productive or nonproductive. The Company had no
+exploratory well costs that had been suspended for one year or more as of
+December 31, 2004 or 2003.
+Geological and geophysical costs and the costs of carrying and
+retaining unproved properties are expensed as incurred. Depletion, depreciation
+and amortization ("DD&A") of capitalized costs of proved oil and gas
+properties is provided on a field-by-field basis using the units of production
+method based upon proved reserves. The computation of DD&A takes into
+consideration restoration, dismantlement and abandonment costs and the
+anticipated proceeds from equipment salvage. As of December 31, 2004, the
+Company's capitalized proved oil and gas properties included $51.2 million of
+estimated salvage value, which is excluded from the Company's DD&A
+calculation. On January 1, 2003, the Company adopted the provisions of Statement
+of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset
+Retirement Obligations," which provides guidance on accounting for dismantlement
+and abandonment costs (see Note 9 - Asset Retirement Obligations).
+F-8
+The Company reviews its long-lived assets for impairments when events
+or changes in circumstances indicate that an impairment may have occurred. The
+impairment test for proved properties compares the expected undiscounted future
+net revenues on a field-by-field basis with the related net capitalized costs at
+the end of each period. Expected future cash flows are calculated on all proved
+reserves using a discount rate and price forecasts selected by the Company's
+management. The discount rate is a rate that management believes is
+representative of current market conditions. The price forecast is based on
+NYMEX strip pricing for the first three years and is then escalated to specified
+maximum prices. Operating costs are escalated in these estimates. When the net
+capitalized costs exceed the undiscounted future net revenues of a field, the
+cost of the field is reduced to fair value, which is determined using discounted
+future net revenues. An impairment allowance is provided on unproved property
+when the Company determines that the property will not be developed or that the
+carrying value is not realizable.
+Sales of Proved and Unproved Properties
+The sale of a partial interest in a proved property is accounted for as
+normal retirement, and no gain or loss is recognized as long as this treatment
+does not significantly affect the units-of-production depletion rate. A gain or
+loss is recognized for all other sales of producing properties and is included
+in the results of operations.
+The sale of a partial interest in an unproved property is accounted for
+as a recovery of cost when substantial uncertainty exists as to recovery of the
+cost applicable to the interest retained. A gain on the sale is recognized to
+the extent that the sales price exceeds the carrying amount of the unproved
+property. A gain or loss is recognized for all other sales of nonproducing
+properties and is included in the results of operations.
+Other Property and Equipment
+Other property and equipment such as office furniture and equipment,
+automobiles and computer hardware and software is recorded at cost. Costs of
+renewals and improvements that substantially extend the useful lives of the
+assets are capitalized. Maintenance and repairs are expensed when incurred.
+Depreciation is provided using the straight-line method over the estimated
+useful lives of the assets from three to 15 years. When other property and
+equipment is sold or retired, the capitalized costs and related accumulated
+depreciation are removed from the accounts.
+Gas Balancing
+The Company uses the sales method to account for gas imbalances. Under
+this method, revenue is recorded based on gas actually sold by the Company. The
+Company records revenue for its share of gas sold by other owners that cannot be
+volumetrically balanced in the future due to insufficient remaining reserves.
+Related receivables totaling $1.5 million at December 31, 2004, and $1.2 million
+at December 31, 2003, are included in other noncurrent assets in the
+accompanying consolidated balance sheets. The Company also reduces revenue for
+gas sold by the Company that cannot be volumetrically balanced in the future due
+to insufficient remaining reserves. Related payables totaling $726,000 at
+December 31, 2004, and $500,000 at December 31, 2003, are included in other
+noncurrent liabilities in the accompanying consolidated balance sheets.
+Receivables and payables are valued based on prices used in recent settlements
+between the Company and its imbalance counterparties, and receivables are
+recorded net of collection allowance. The Company's remaining overproduced and
+underproduced gas balancing positions are considered in the Company's proved oil
+and gas reserves (see Note 12 - Disclosures about Oil and Gas Producing
+Activities).
+F-9
+Derivative Financial Instruments
+The Company seeks to protect its rate of return on acquisitions of
+producing properties, and other production by hedging cash flows. The Company
+intends for derivative instruments used for this purpose to be designated as,
+and to qualify as, cash flow hedging instruments under SFAS No. 133, "Accounting
+for Derivative Instruments and Hedging Activities," and related pronouncements.
+The Company generally limits its aggregate hedge position to no more than 50
+percent of its total production but will hedge larger percentages of total
+production in certain circumstances. The Company seeks to minimize basis risk
+and indexes the majority of its oil hedges to NYMEX prices and the majority of
+its gas hedges to various regional index prices associated with pipelines in
+proximity to the Company's areas of gas production.
+The Company's hedge positions are diversified with various
+counterparties, and the Company requires that such counterparties have clear
+indications of current financial strength. See Note 10 - Derivative Financial
+Instruments for additional discussion of derivatives.
+Fair Value of Financial Instruments
+The Company's financial instruments including cash and cash
+equivalents, restricted cash, accounts receivable and accounts payable are
+carried at cost, which approximates fair value due to the short-term maturity of
+these instruments. The recorded value of the Company's credit facility
+approximates its fair value as it bears interest at a floating rate. The
+Company's interest rate swaps are recorded at fair value as discussed in Note 10
+- Derivative Financial Instruments. The Company's 5.75% Senior Convertible Notes
+Due 2022 (the "Convertible Notes") are recorded at cost, and the fair value is
+disclosed in Note 5 - Long-Term Debt. The Company's other financial instruments
+and investments in available-for-sale securities are marked to market with
+changes in fair value being recorded in accumulated other comprehensive income.
+Since considerable judgment is required to develop estimates of fair value, the
+estimates provided are not necessarily indicative of the amounts the Company
+could realize upon the sale or refinancing of such instruments.
+Net Profits Plan
+The Company records the estimated liability of future payments under
+its Net Profits Plan because it is a vested employee benefit. The estimated
+liability is calculated based on a number of assumptions, including estimates of
+oil and gas reserves, recurring and workover lease operating expense, tax rates,
+present value discount factors and certain pricing assumptions. The estimates
+the Company uses in calculating the liability are modified from period to period
+based on new information attributable to the underlying assumptions. Changes in
+the estimated liability of future payments associated with the Net Profits Plan
+are recorded as increases or decreases to expense in the current period as a
+separate line item in the consolidated statements of operations. The estimated
+Net Profits Plan liability is recorded separately as a noncurrent liability in
+the accompanying consolidated balance sheets.
+The amounts due and payable under the Net Profits Plan as cash
+compensation related to the current period operations are recognized as
+compensation expense and are included within general and administrative expense
+and exploration expense. The corresponding current liability is included in
+accounts payable and accrued expenses in the accompanying consolidated balance
+sheets. This treatment provides for a consistent matching of cash expense with
+net cash flows from the oil and gas properties in each respective pool of the
+Net Profits Plan.
+Income Taxes
+Deferred income taxes are provided on the difference between the tax
+basis of an asset or liability and its carrying amount in the financial
+statements. This difference will result in taxable income or deductions in
+future years when the reported amount of the asset or liability is recovered or
+settled, respectively.
+F-10
+Earnings Per Share
+Basic net income per common share of stock is calculated by dividing
+net income available to common stockholders by the weighted-average of common
+shares outstanding during each period.
+During the first quarter of 2003, the Company issued 3,380,818 shares
+of common stock as part of an acquisition. On February 9, 2004, the Company
+repurchased and retired these shares (see Note 11-Repurchase of St. Mary Common
+Stock). These shares were considered outstanding from January 29, 2003, to
+February 9, 2004, for purposes of calculating basic and diluted net income per
+common share and were weighted accordingly in the calculation of common shares
+outstanding. The shares were included in the temporary equity section of the
+consolidated balance sheet as of December 31, 2003.
+Diluted net income per common share of stock is calculated by dividing
+adjusted net income by the weighted-average of common shares outstanding,
+including the effect of other dilutive securities. Adjusted net income is used
+for the if-converted method and is derived by adding interest expense paid on
+the Convertible Notes back to net income and then adjusting for nondiscretionary
+items that are based on income and that would have changed had the Convertible
+Notes been converted at the beginning of the period. Potentially dilutive
+securities of the Company consist of in-the-money outstanding options to
+purchase the Company's common stock, shares into which the Convertible Notes may
+be converted and unvested restricted stock units.
+The shares underlying the grants of restricted stock units are excluded
+from basic and diluted earnings per share until the measurement date for grants
+made under the Restricted Stock Plan. Upon measurement, all unvested shares
+attributable to the restricted stock unit grant are included in the diluted
+share calculation. Vested shares are included in both basic and diluted earnings
+per share.
+The treasury stock method is used to measure the dilutive impact of
+stock options. The following table details the weighted-average dilutive and
+anti-dilutive securities related to stock options for the periods presented:
+For the Years Ended December 31,
+------------------------------------------------------------
+2004 2003 2002
+---------------- --------------- ---------------
+Dilutive 749,644 455,055 534,610
+Anti-dilutive 93 713,382 1,539,227
+The dilutive effect of stock options and unvested restricted stock
+units is considered in the detailed calculation below. There were no
+anti-dilutive securities related to restricted stock units for any periods
+presented.
+Shares associated with the conversion feature of the Convertible Notes
+are accounted for using the if-converted method as described above. A total of
+3,846,153 potentially dilutive shares related to the Convertible Notes were
+included in the calculation of diluted net income per common share for the years
+ended December 31, 2004 and 2003. A total of 3,076,922 potentially dilutive
+shares related to the Convertible Notes were excluded from the 2002 calculation
+of diluted net income per share because they were not dilutive. The Convertible
+Notes were issued in March 2002.
+F-11
+The following table sets forth the calculation of basic and diluted
+earnings per share:
+For the Years Ended December 31,
+------------------------------------------------
+2004 2003 2002
+-------------- ------------- -------------
+(In thousands, except per share amounts)
+Income before cumulative effect of change in accounting
+principle $ 92,479 $ 90,140 $ 27,560
+Cumulative effect of change in accounting principle, net
+of income tax - 5,435 -
+------------- ------------- -------------
+Net income 92,479 95,575 27,560
+------------- ------------- -------------
+Adjustments to net income for dilution:
+Add: interest expense avoided if Convertible Notes
+converted to equity 6,354 6,337 -
+Less: other adjustments (64) (63) -
+Less: income tax effect of dilution items (2,312) (2,403) -
+------------- ------------- -------------
+Net income adjusted for the effect of dilution $ 96,457 $ 99,446 $ 27,560
+============= ============= =============
+Basic weighted-average common shares outstanding 28,851 31,233 27,856
+Add: dilutive effect of stock options 750 455 535
+Add: dilutive effect of Convertible Notes using the
+if-converted method 3,846 3,846 -
+------------- ------------- -------------
+Diluted weighted-average common shares outstanding 33,447 35,534 28,391
+============= ============= =============
+Basic earnings per common share:
+Income before cumulative effect of change in
+accounting principle $ 3.21 $ 2.89 $ 0.99
+Cumulative effect of change in accounting principle - 0.17 -
+------------- ------------- -------------
+Total $ 3.21 $ 3.06 $ 0.99
+============= ============= =============
+Diluted earnings per common share:
+Income before cumulative effect of change in
+accounting principle $ 2.88 $ 2.65 $ 0.97
+Cumulative effect of change in accounting principle - 0.15 -
+------------- ------------- -------------
+Total $ 2.88 $ 2.80 $ 0.97
+============= ============= =============
+Stock-Based Compensation
+At December 31, 2004, the Company had stock-based employee compensation
+plans that included restricted stock units and stock options issued to employees
+and non-employee directors as more fully described in Note 7 - Compensation
+Plans. The Company accounts for stock-based compensation using the intrinsic
+value recognition and measurement principles prescribed in Accounting Principles
+Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB No. 25")
+and related interpretations. No compensation expense is reflected in net income
+for stock options as all stock options had an exercise price equal to the market
+value of the underlying common stock on the date of grant. The total measured
+expense for restricted stock unit ("RSU") grants is initially recorded as
+deferred stock-based compensation and is charged to compensation expense based
+on the vesting schedule. The portion of the estimated future RSU grant related
+to current year performance that will vest immediately upon grant is recorded to
+compensation expense in the current year. The following table illustrates the
+pro forma effect on net income and earnings per share if the Company had applied
+the fair value recognition provisions of SFAS No. 123, "Accounting for
+Stock-Based Compensation," to stock-based employee compensation:
+F-12
+For the Years Ended December 31,
+----------------------------------------------
+2004 2003 2002
+------------- ------------ -------------
+(In thousands, except per share amounts)
+Net income -
+As reported: $ 92,479 $ 95,575 $ 27,560
+Add: stock-based employee compensation
+expense included in reported net income,
+net of related tax effects 2,650 - -
+Less: stock-based employee compensation
+expense determined under fair value
+method for all awards, net of
+related income tax effects (6,062) (5,853) (4,666)
+------------- ------------ -------------
+Pro forma $ 89,067 $ 89,722 $ 22,894
+============= ============ =============
+Pro forma basic earnings per share -
+-------------------------------------
+Income before cumulative effect of change in
+accounting principle $ 3.09 $ 2.70 $ 0.82
+Cumulative effect of change in accounting principle - 0.17 -
+------------- ------------ -------------
+Total $ 3.09 $ 2.87 $ 0.82
+============= ============ =============
+Pro forma diluted earnings per share -
+---------------------------------------
+Income before cumulative effect of change in
+accounting principle $ 2.78 $ 2.48 $ 0.81
+Cumulative effect of change in accounting principle - 0.15 -
+------------- ------------ -------------
+Total $ 2.78 $ 2.63 $ 0.81
+============= ============ =============
+For purposes of pro forma disclosures, the estimated fair values of the
+options are amortized to expense over the options' vesting periods. The effects
+of applying SFAS No. 123 in the pro forma disclosure are not necessarily
+indicative of actual future amounts.
+In December 2004 the Financial Accounting Standards Board ("FASB")
+issued SFAS No. 123 (Revised 2004), "Shared-Based Payment". This statement
+provides for the accounting for transactions in which an entity exchanges equity
+instruments or incurs liabilities in exchange for goods or services. See Note 7
+- Compensation Plans for additional disclosures about stock-based compensation.
+Comprehensive Income
+Comprehensive income consists of net income, unrealized gains and
+losses on marketable equity securities held for sale, the effective portion of
+derivative instruments classified as cash flow hedges, and accrued pension
+benefit obligation in excess of plan assets. Comprehensive income is presented
+net of income taxes in the consolidated statements of stockholders' equity and
+comprehensive income.
+F-13
+The balances of after-tax components comprising accumulated other
+comprehensive income and loss are presented in the following table:
+Marketable Minimum Accumulated Other
+Equity Derivative Pension Comprehensive
+Securities Instruments Liability Income (Loss)
+------------- --------------- ------------ --------------------
+Balances, December 31, 2001 $ 9 $ 6,907 $ - $ 6,916
+Reclass to earnings - 1,447 - 1,447
+Other 2002 changes (725) (14,644) (761) (16,130)
+------------- --------------- ------------ --------------------
+Balances, December 31, 2002 (716) (6,290) (761) (7,767)
+Reclass to earnings 716 13,846 - 14,562
+Other 2003 changes - (21,873) 197 (21,676)
+------------- --------------- ------------ --------------------
+Balances, December 31, 2003 - (14,317) (564) (14,881)
+Reclass to earnings - (14,795) - (14,795)
+Other 2004 changes - 31,849 101 31,950
+------------- --------------- ------------ --------------------
+Balances, December 31, 2004 $ - $ 2,737 $ (463) $ 2,274
+============= =============== ============ ====================
+Tax effects allocated to each component of other comprehensive income:
+Marketable Minimum Other
+Equity Derivative Pension Comprehensive
+Securities Instruments Liability Income (Loss)
+------------- ---------------- ------------ ----------------
+For the period ending December 31, 2002
+Before tax amount $ (1,121) $ (18,067) $ (1,188) $ (20,376)
+Tax (expense) benefit 396 4,870 427 5,693
+------------- ---------------- ------------ ----------------
+After tax amount (725) (13,197) (761) (14,683)
+============= ================ ============ ================
+For the period ending December 31, 2003
+Before tax amount 1,160 (13,170) 274 (11,736)
+Tax (expense) benefit (444) 5,143 (77) 4,622
+------------- ---------------- ------------ ----------------
+After tax amount 716 (8,027) 197 (7,114)
+============= ================ ============ ================
+For the period ending December 31, 2004
+Before tax amount - 27,401 168 27,569
+Tax (expense) benefit - (10,347) (67) (10,414)
+------------- ---------------- ------------ ----------------
+After tax amount $ - $ 17,054 $ 101 $ 17,155
+============= ================ ============ ================
+F-14
+Major Customers
+During 2004 one customer individually accounted for 20 percent of the
+Company's total oil and gas production revenue. During 2003 three customers
+individually accounted for 14 percent, 13 percent and 11 percent of the
+Company's total oil and gas production revenue. During 2002 there were no sales
+to individual customers that accounted for more than 10 percent of total oil and
+gas production revenue.
+Industry Segment and Geographic Information
+The Company operates in one industry segment, which is the exploration,
+development and production of natural gas and crude oil, and all of the
+Company's operations are conducted in the continental United States.
+Consequently, the Company currently reports as a single industry segment.
+Note 2 - Accounts Receivable and Accounts Payable and Accrued Expenses
+Accounts receivable are comprised of the following:
+As of December 31,
+-------------------------------------------
+2004 2003
+------------------ -------------------
+(In thousands)
+Accrued oil and gas sales $ 79,107 $ 48,925
+Due from joint interest owners 20,587 12,554
+Other 5,270 3,061
+------------------ -------------------
+Total accounts receivable $ 104,964 $ 64,540
+================== ===================
+Accounts payable and accrued expenses are comprised of the following:
+As of December 31,
+---------------------------------------
+2004 2003
+------------------ ----------------
+(In thousands)
+Accrued drilling costs $ 34,446 $ 22,201
+Revenue payable 41,875 16,215
+Accrued lease operating expense 13,066 12,195
+Accrued cash bonus and net profit payments 4,264 8,026
+Trade payables 7,506 6,247
+Oil hedge accrual 3,027 1,400
+Other 5,933 14,933
+------------------ ----------------
+Total account payable and accrued expenses $ 110,117 $ 81,217
+================== ================
+F-15
+Note 3 - Acquisitions and Divestitures
+Goldmark Acquisition
+On November 1, 2004, the Company acquired Goldmark Engineering Inc.
+along with proved and unproved oil and gas properties from various other parties
+(collectively, "Goldmark") in exchange for $23.3 million of cash. The allocation
+of the purchase price was $29.4 million of proved reserves and unproved acreage,
+$1.2 million of cash, $753,000 of other assets, $446,000 of payables, a $2.8
+million asset retirement liability, and a $4.8 million deferred tax liability.
+The acquisition was accounted for using the purchase method of accounting and
+was funded with cash on hand and borrowings under the Company's existing credit
+facility. Operating results from the acquired properties have been included in
+the consolidated statements of operations only from the date of closing. The
+final purchase accounting allocations will be dependent on a determination of
+post closing adjustments incurred subsequent to the acquisition date.
+Border Acquisition (Previously referred to by the Company as the Nemours
+Acquisition)
+On December 15, 2004, the Company completed the acquisition of proved
+and unproved oil and gas properties from Border Company and other parties in
+exchange for $37.8 million in cash. The allocation of the purchase price was
+$38.5 million of proved reserves and unproved acreage and a $649,000 asset
+retirement obligation. The final purchase accounting allocations will be
+dependent on a determination of post closing adjustments incurred subsequent to
+the acquisition date. The Company utilized a portion of its existing credit
+facility to fund the acquisition, and the transaction was accounted for as a
+purchase.
+Agate Acquisition
+On January 5, 2005, the Company closed the acquisition of Agate
+Petroleum, Inc. for $39.6 million in cash. The estimated preliminary purchase
+accounting will result in the Company recording approximately $42.1 million to
+proved and unproved oil and gas properties, $3.0 million to working capital,
+$9.4 million to goodwill, a deferred income tax liability of $13.6 million and a
+$1.3 million asset retirement obligation. The final purchase accounting
+allocation will be dependent on the determination of working capital, tax basis
+and fair value of the oil and gas properties as of the date of closing. The
+goodwill and deferred income tax liability are a result of acquiring assets with
+tax basis that is lower than book basis because present value considerations
+cannot be applied to the amounts recorded for deferred income taxes.
+Flying J Acquisition
+On January 29, 2003, the Company acquired oil and gas properties and
+other assets and liabilities from Flying J Oil & Gas Inc. and Big West Oil
+& Gas Inc. (collectively, "Flying J"). As consideration for the properties,
+St. Mary issued 3,380,818 restricted shares of its common stock to Flying J. In
+addition, St. Mary made a non-recourse loan to Flying J of $71.6 million at the
+one-year LIBOR plus 2 percent for up to a 39-month period. The loan was funded
+using cash on hand and borrowing under the credit facility in place at the time
+of the transaction. This loan was secured by a pledge of the shares of common
+stock issued to Flying J, with the final nine months of interest on that loan to
+be with recourse to Flying J. St. Mary also entered into a put and call option
+agreement with Flying J whereby during the 39-month loan period Flying J could
+elect to put their shares of St. Mary common stock to the Company for $71.6
+million plus accrued interest on the loan during the first thirty months of the
+loan period, and St. Mary could elect to call the shares for $97.4 million, with
+the proceeds from the exercise of either the put option or the call option to be
+applied to the repayment of the loan plus accrued and unpaid interest. The
+shares issued were restricted for a period of two years, and Flying J was
+prohibited from selling the shares during that period. If neither Flying J nor
+St. Mary exercised their respective option rights, the loan plus accrued
+interest was to be repaid prior to the release of the security interest in the
+shares.
+F-16
+For financial reporting purposes, the effect of the above arrangements
+is that the Company acquired oil and gas properties and other assets and
+liabilities in exchange for $71.6 million of cash plus a net option to Flying J
+valued at $995,000 resulting in a total valuation of $72.6 million. The
+allocation of the purchase price for the net assets acquired was $72.4 million
+of proved reserves and unproved acreage, $445,000 of other assets, a $1.9
+million asset retirement liability, a $2.0 million hedge liability, and $3.7
+million in net cash received for purchase price adjustments. The acquisition was
+accounted for using the purchase method of accounting. Operating results from
+the acquired properties have been included in the consolidated statements of
+operations only from the date of closing.
+The shares of common stock that were issued in this transaction were
+recorded as temporary equity since they were subject to the put option whereby
+the Company could have been required to repurchase these shares. The shares of
+common stock were considered outstanding for basic and diluted earnings per
+share calculations. The loan arising from this transaction was considered a
+contra-temporary equity item on the 2003 consolidated balance sheet, as opposed
+to an asset, since the loan was non-recourse to Flying J except with respect to
+interest accrued after the first thirty months and was secured by the restricted
+common stock issued as part of this transaction. Interest was not accrued for
+financial reporting purposes because of the non-recourse nature of the note.
+As described more fully in Note 11 - Repurchase of St. Mary Common
+Stock, the Company entered into a separately negotiated transaction in February
+2004 with Flying J to repurchase the 3,380,818 restricted shares issued in the
+acquisition.
+Sales of Properties
+Throughout 2004 the Company sold interests in certain non-core
+properties. The Company received cash proceeds of $2.8 million and recognized a
+gain of approximately $1.8 million from these sales. For property sales that
+occurred in the fourth quarter of 2004, the final proceeds and gain amounts are
+subject to the resolution of final post-closing adjustments and settlements.
+Throughout 2003 the Company sold interests in certain non-core properties
+primarily in Texas and Wyoming. The Company received $23.5 million in net
+proceeds and recognized a gain of approximately $7.3 million from these sales.
+Note 4 - Income Taxes
+The provision for income taxes consists of the following:
+For the Years Ended December 31,
+------------------------------------------
+2004 2003 2002
+-------------- ------------- -------------
+(In thousands)
+Current taxes:
+Federal $ 21,143 $ 29,582 $ 719
+State 1,389 2,656 569
+Deferred taxes 31,217 23,692 13,731
+-------------- ------------- -------------
+Total income tax expense $ 53,749 $ 55,930 $ 15,019
+============== ============= =============
+The above taxes from operations are net of alternative fuels credits
+(Internal Revenue Code Section 29) of $167,000 in 2002. Current federal tax
+expense does not reflect the tax benefit of $3.8 million in 2004, $1.2 million
+in 2003 and $719,000 in 2002 for deductions from stock option exercises.
+F-17
+The components of the net deferred tax liability are as follows:
+December 31,
+-----------------------------------
+2004 2003
+----------------- ----------------
+(In thousands)
+Deferred tax liabilities:
+Oil and gas properties $ 146,427 $ 100,103
+Interest on Convertible Notes 4,192 2,791
+Amounts included in accumulated other comprehensive income 2,246 -
+Derivative instruments and other 435 41
+----------------- ----------------
+Total deferred tax liabilities 153,300 102,935
+----------------- ----------------
+Deferred tax assets:
+Net Profits Plan liability 11,598 2,358
+State tax net operating loss carryforward or carryback 2,981 2,094
+Federal net operating loss carryforward or carryback 2,882 2,900
+Stock compensation 1,590 -
+State and federal income tax benefit 1,100 1,002
+Deferred capital loss 758 1,840
+Amounts included in accumulated other comprehensive income 1,033 9,222
+Other, primarily employee benefits 969 2,286
+----------------- ----------------
+Total deferred tax assets 22,911 21,702
+Valuation allowance (1,714) (842)
+----------------- ----------------
+Net deferred tax assets 21,197 20,860
+----------------- ----------------
+Total net deferred tax liabilities 132,103 82,075
+Less: current deferred income tax liabilities (2,357) -
+Add: current deferred income tax assets 84 8,872
+----------------- ----------------
+Non-current net deferred tax liabilities $ 129,830 $ 90,947
+================= ================
+Current federal refundable income tax $ - $ 454
+Current federal income tax payable $ 939 $ -
+Current state refundable income tax $ 139 $ -
+Current state income tax payable $ - $ 1,334
+At December 31, 2004, the Company had state net operating loss
+carryforwards of approximately $42.8 million and state tax credits of $93,000,
+which expire between 2005 and 2023. The Company's valuation allowance relates to
+those state net operating loss carryforwards and state tax credits that the
+Company anticipates will expire before they can be utilized. The Company has
+concluded that permanent items included in the calculation of income tax for
+certain states may impact its ability to deduct net operating losses incurred in
+those states and has adjusted its valuation allowances accordingly.
+F-18
+Federal income tax expense and benefit differs from the amount that
+would be provided by applying the statutory U.S. Federal income tax rate to
+income before income taxes for the following reasons:
+For the Years Ended December 31,
+-------------------------------------------------
+2004 2003 2002
+--------------- ---------------- ----------------
+(In thousands)
+Federal statutory taxes $ 51,180 $ 49,668 $ 14,477
+Increase (reduction) in taxes resulting from:
+State taxes (net of federal benefit) 2,586 5,812 2,092
+Statutory depletion (224) (224) (218)
+Alternative fuel credits (Section 29) - - (167)
+Change in valuation allowance 872 115 (1,202)
+Other (665) 559 37
+--------------- ---------------- ----------------
+Income tax expense from operations $ 53,749 $ 55,930 $ 15,019
+=============== ================ ================
+Acquisitions, drilling and basis differentials impacting the prices
+received for crude oil and natural gas impact the apportionment of taxable
+income to the states where the Company owns properties. As these factors change,
+the Company's state income tax rate changes. This change applied to the
+Company's total temporary differences will impact the total income tax reported
+in the current year and is reflected in state taxes in the table above. These
+impacts are evaluated upon completion of the prior year income tax return, after
+significant acquisitions are closed and at the end of the year.
+Note 5 - Long-term Debt
+Revolving Credit Facility
+The Company has a revolving credit facility with a group of banks. The
+credit facility specifies a maximum loan amount of $300.0 million and has a
+maturity date of January 27, 2006. Borrowings under the facility are secured by
+a pledge of collateral that includes the majority of the Company's oil and gas
+properties and the common stock of the material subsidiaries of the Company. The
+bank group authorized a borrowing base of $325.0 million in October 2004 under
+its normal semi-annual redetermination. The borrowing base redetermination
+process considers the value of St. Mary's oil and gas properties, using oil and
+gas pricing criteria specified by the bank syndicate, and other assets as
+determined by the bank syndicate. Although the borrowing base exceeds the
+maximum loan amount, the most that the Company could borrow under the facility
+is limited to the maximum loan amount. The Company has elected an aggregate
+commitment amount of $150.0 million. The Company must comply with certain
+financial and non-financial covenants including the limitation of our annual
+dividend rate to no more than $0.20 per share. The Company is in compliance with
+all of the covenants. Interest and commitment fees are accrued based on the
+borrowing base utilization percentage table below. Eurodollar loans accrue
+interest at LIBOR plus the applicable margin from the utilization table, and
+Alternative Base Rate (ABR) loans accrue interest at Prime plus the applicable
+margin from the utilization table. Commitment fees are accrued on the unused
+portion of the aggregate commitment amount and are included in interest expense
+in the consolidated statements of operations.
+Borrowing base
+utilization percentage <50% =>50%<75% =>75%<90% >90%
+-------------------------------------------------------------------------------
+Eurodollar Loans 1.25% 1.50% 1.75% 2.00%
+ABR Loans 0.00% 0.25% 0.50% 0.75%
+Commitment Fee Rate 0.30% 0.38% 0.38% 0.50%
+At December 31, 2004, the Company's borrowing base utilization
+percentage as defined under the credit agreement was 24.7 percent. The Company
+had $10.0 million in ABR borrowings and $27.0 million in LIBOR based loans
+outstanding under its revolving credit agreement as of December 31, 2004. As of
+F-19
+February 15, 2005, the Company had an outstanding ABR balance of $2 million and
+an outstanding balance of $44 million under its LIBOR alternative.
+5.75% Senior Convertible Notes Due 2022
+As of December 31, 2004, the Company also had $100.0 million in
+outstanding borrowings under the Convertible Notes. The Convertible Notes
+provide for the payment of contingent interest of up to an additional 0.5
+percent during six-month interest periods based on the Convertible Note market
+price before the beginning of the particular six-month period. Under that
+provision, interest was accrued at a total rate of 6.25 percent for 2004. Based
+on the trading price of the Convertible Notes over the determination period, the
+Company will be subject to the contingent interest payments for the period from
+September 16, 2004, to March 15, 2005.
+The Convertible Notes are general unsecured obligations and rank on
+parity in right of payment with all existing and future unsecured senior
+indebtedness and other general unsecured obligations. They are senior in right
+of payment to all future subordinated indebtedness. The Convertible Notes are
+convertible into the Company's common stock at a conversion price of $26.00 per
+share, subject to adjustment. The Company can redeem the Convertible Notes with
+cash in whole or in part at a repurchase price of 100 percent of the principal
+amount plus accrued and unpaid interest (including contingent interest)
+beginning on March 20, 2007. The note holders have the option of requiring the
+Company to repurchase the Convertible Notes for cash at 100 percent of the
+principal amount plus accrued and unpaid interest (including contingent
+interest) upon (1) a change in control of St. Mary or (2) on March 20, 2007,
+March 15, 2012, and March 15, 2017. If the note holders require repurchase on
+March 20, 2007, the Company may elect to pay the repurchase price with cash,
+shares of its common stock valued at a discount at the time of repurchase, or
+any combination of cash and its discounted common stock. The shares of common
+stock used in any repurchase will be discounted at 95 percent of market price if
+33 percent or less of the repurchase price is in shares of our common stock;
+otherwise, the stock will be discounted at 93 percent of market value. St. Mary
+is not restricted from paying dividends, incurring debt, or issuing or
+repurchasing its securities under the indenture for the Convertible Notes. There
+are no financial covenants in the indenture. Based on the market price of the
+Convertible Notes, the estimated fair value of the Convertible Notes was
+approximately $171.8 million as of December 31, 2004, and approximately $135.3
+million as of December 31, 2003.
+Weighted-Average Interest Rate Paid and Capitalized Interest
+The weighted-average interest rate paid in 2004 was 7.1 percent
+including commitment fees paid on the unused portion of the credit facility
+aggregate commitment, amortization of deferred financing costs, amortization of
+the contingent interest embedded derivative and the effect of interest rate
+swaps. The impact of these items over a lower average outstanding loan balance
+results in a higher weighted-average interest rate despite lower LIBOR interest
+rates than in previous periods. The company capitalized interest costs of $1.4
+million, $780,000, and $427,000 for the years ended December 31, 2004, 2003 and
+2002, respectively.
+Note 6 - Commitments and Contingencies
+The Company leases office space under various operating leases with
+terms extending as far as May 31, 2012. Rent expense, net of sublease income,
+was $1.5 million, $1.3 million, and $1.1 million in 2004, 2003 and 2002,
+respectively. The Company also leases office equipment under various operating
+leases. The Company has a non-cancelable sublease of approximately $1.3 million
+through 2012. The annual minimum lease payments for the next five years and
+thereafter are presented below:
+F-20
+Years Ending December 31, (In thousands)
+----------------------------- -------------------
+2005 $ 2,440
+2006 1,814
+2007 1,306
+2008 1,193
+2009 1,065
+Thereafter 2,876
+------------------
+Total $ 10,694
+==================
+The Company is subject to litigation and claims that have arisen in the
+ordinary course of business. The Company accrues for such items when a liability
+is both probable and the amount can be reasonably estimated. In the opinion of
+management, the results of such litigation and claims will not have a material
+effect on the results of operations or the financial position of the Company.
+Management believes it has sufficiently provided for such items in the
+consolidated balance sheets.
+Note 7 - Compensation Plans
+Cash Bonus Plan
+The Company has a cash bonus plan that normally allows participants to
+receive up to 50 percent, but in special situations to receive up to 100 percent
+of their aggregate base salary. Any awards under the cash bonus plans are based
+on a combination of Company and individual performance. The Company accrued $2.0
+million for cash bonuses in 2004 that will be paid in 2005, and $5.4 million for
+cash bonuses in 2003 that were paid in 2004.
+Net Profits Plan
+Under the Company's Net Profits Plan, oil and gas wells that are
+completed or acquired during a year are designated within a specific pool. Key
+employees designated as participants by the Company's Compensation Committee of
+the Board of Directors and employed by the Company on the last day of that year
+vest and become entitled to bonus payments after the Company has received net
+cash flows returning 100 percent of all costs and expenses associated with that
+pool. Thereafter, 10 percent of future cash flows generated by the pool are
+allocated among the participants and distributed at least annually. The
+percentage of cash flows from the pool to be allocated among the participants
+increases to 20 percent after the Company has recovered 200 percent of the total
+costs and expenses for the pool, including payments made under the Net Profits
+Plan at the 10 percent level.
+Expense related to current distributions made under the Net Profits
+Plan in 2004, 2003 and 2002 were $8.0 million, $8.9 million, and $4.8 million,
+respectively. These amounts relate to current realized results from oil and gas
+operations in the respective periods.
+The Company records the estimated liability for the Net Profits Plan
+based on the discounted value of estimated future payments associated with each
+individual pool. The following table presents the changes in the estimated
+liability attributable to the Net Profits Plan:
+F-21
+As of December 31,
+----------------------------------------------
+2004 2003
+--------------------- ---------------------
+(In thousands)
+Beginning liability for Net Profits Plan $ 6,163 $ 846
+Change in liability for accretion and change
+in estimates 32,410 14,235
+Reduction in liability for cash payments made or
+accrued and recognized as compensation expense
+under the Net Profits Plan (8,012) (8,918)
+--------------------- ---------------------
+Ending liability for Net Profits Plan $ 30,561 $ 6,163
+===================== =====================
+The Company records the expense associated with changes in the present
+value of estimated future payments under the Net Profits Plan as a separate item
+in the consolidated statements of operations. The change in the estimated
+liability is recorded as an increase or decrease to expense in the current
+period. The amount recorded as an increase or decrease to expense associated
+with the change in the estimated liability is not allocated to general and
+administrative costs or exploration costs because the adjustment of the
+liability is associated with the future net cash flows from oil and gas
+properties in the respective pools rather than current period performance. The
+table below presents the estimated allocation of the change in the liability if
+the Company did allocate the adjustment to these specific line items:
+For the Years Ended December 31,
+------------------------------------------------------------
+2004 2003 2002
+--------------- ------------------ ------------------
+(In thousands)
+General and administrative expense $ 14,609 $ 3,982 $ 616
+Exploration expense 9,789 1,335 230
+--------------- --- ------------------ -- ------------------
+Total $ 24,398 $ 5,317 $ 846
+=============== === ================== == ==================
+401(k) Plan
+The Company has a defined contribution pension plan (the "401(k) Plan")
+that is subject to the Employee Retirement Income Security Act of 1974. The
+401(k) Plan allows eligible employees to contribute up to 60 percent of their
+base salaries. The Company matches each employee's contributions up to 6 percent
+of the employee's base salary and may also make additional contributions at its
+discretion. The Company's contributions to the 401(k) Plan were $834,000,
+$746,000, and $621,000 for the years ended December 31, 2004, 2003, and 2002,
+respectively. No discretionary contributions were made by the Company to the
+401(k) Plan in any of these three years.
+Employee Stock Purchase Plan
+Under the St. Mary Land & Exploration Company Employee Stock
+Purchase Plan ("the ESPP"), eligible employees may purchase shares of the
+Company's common stock through payroll deductions of up to 15 percent of
+eligible compensation. The purchase price of the stock is 85 percent of the
+lower of the fair market value of the stock on the first or last day of the
+purchase period, and shares issued under the ESPP are restricted for a period of
+18 months from the date issued. The ESPP is intended to qualify under Section
+423 of the Internal Revenue Code. The Company has set aside 1,000,000 shares of
+its common stock to be available for issuance under the ESPP. Shares issued
+under the ESPP totaled 13,874 in 2004, 16,994 in 2003, and 18,217 in 2002. Total
+proceeds to the Company for the issuance of these shares were $375,000 in 2004,
+$375,000 in 2003, and $344,000 in 2002. The Company recorded compensation
+expense of $21,000 in 2002 due to nonqualified dispositions of stock acquired by
+employees under the ESPP. No compensation expense has been recorded under the
+ESPP after 2002 since all shares issued under the ESPP after July 1, 2001 were
+issued as restricted shares and are not subject to disqualified disposition.
+F-22
+Stock Option Plans
+The Company has a Stock Option Plan and an Incentive Stock Option Plan
+(collectively, the "Option Plans"). The Option Plans grant options to purchase
+shares of the Company's common stock to eligible employees, contractors, and
+current and former members of the Board of Directors. There are 5,600,000 shares
+of the Company's common stock reserved for issuance under the Option Plans. This
+number is reduced to the extent that restricted stock or restricted stock units
+are granted under the Restricted Stock Plan. All options granted to date under
+the Option Plans have been granted at exercise prices equal to the respective
+market prices of the Company's common stock on the grant dates. There were
+869,862 shares available for grant under the Option Plans (including the
+Restricted Stock Plan, as described later) as of December 31, 2004.
+A summary of activity associated with the Company's Option Plans during
+the last three years follows:
+For the Years Ended December 31,
+---------------------------------------------------------------------------------
+2004 2003 2002
+-------------------------- --------------------------- --------------------------
+Weighted- Weighted- Weighted-
+Average Average Average
+Exercise Exercise Exercise
+Shares Price Shares Price Shares Price
+------------- ------------ ------------- ------------- ------------- ------------
+Outstanding, start of year 3,525,128 $ 23.10 3,061,566 $ 21.34 2,151,675 $ 19.42
+Granted 58,678 37.79 858,431 26.70 1,109,541 23.55
+Exercised (699,526) 20.06 (245,019) 12.88 (177,085) 11.44
+Forfeited (58,605) 24.99 (149,850) 24.00 (22,565) 25.08
+------------- ------------- -------------
+Outstanding, end of year 2,825,675 24.12 3,525,128 23.10 3,061,566 21.34
+============= ============= =============
+Exercisable, end of year 2,220,681 23.51 2,441,246 22.36 1,944,382 19.79
+Weighted-average fair
+value of options granted
+granted
+during the year $ 16.87 $ 12.28 $ 10.77
+F-23
+A summary of additional information related to options outstanding as
+of December 31, 2004, follows:
+Options Outstanding Options Exercisable
+----------------------------------------------- ----------------------------
+Weighted-
+Average Weighted- Weighted-
+Remaining Average Average
+Range of Number Contractual Exercise Number Exercise
+Exercise Prices Outstanding Life Price Exercisable Price
+------------------------ --------------- -------------- -------------- ------------- -------------
+$ 9.25 - $ 12.52 389,204 4.4 years $ 11.50 389,204 $ 11.50
+12.53 - 16.69 120,077 6.4 years 15.82 120,077 15.82
+16.70 - 20.87 47,209 3.0 years 17.50 47,209 17.50
+20.88 - 25.04 1,000,032 7.5 years 23.22 757,885 23.10
+25.05 - 29.21 733,671 8.7 years 26.73 413,354 26.65
+29.22 - 33.39 482,530 6.0 years 33.31 482,530 33.31
+33.40 - 37.56 18,750 9.2 years 33.43 1,875 33.43
+37.57 - 41.74 34,202 10 years 41.74 8,547 41.74
+--------------- -------------
+Total 2,825,675 7.0 years 24.12 2,220,681 23.51
+=============== =============
+SFAS No. 123 establishes a fair value method of accounting for
+stock-based compensation plans through either recognition or disclosure. The
+Company accounts for stock-based compensation under the intrinsic value method
+pursuant to APB No. 25 and has elected to adopt SFAS No. 123 through compliance
+with the disclosure requirements set forth in the Statement. Because the
+exercise price of the Company's stock options equals the market price of the
+underlying stock on the date of grant, no compensation expense is recognized
+under APB No. 25. Pro forma information regarding net income and earnings per
+share is required by SFAS No. 123 and has been determined as if the Company had
+accounted for its employee stock options under the fair value method of that
+Statement. This pro forma information is prominently disclosed in Note 1-Summary
+of Significant Accounting Policies.
+The fair value of options is measured at the date of grant using the
+Black-Scholes option-pricing model. The fair values of options granted were
+estimated using the following weighted-average assumptions:
+For the Years Ended December 31,
+----------------------------------------------
+2004 2003 2002
+--------------- -------------- --------------
+Risk free interest rate:
+Stock options 4.1% 3.6% 3.8%
+Employee stock purchase plan 3.1% 3.7% 3.5%
+Dividend yield:
+Stock options 0.3% 0.4% 0.4%
+Employee stock purchase plan 0.3% 0.4% 0.4%
+Volatility factor of the expected market
+price of the Company's common stock:
+Stock options 35.9% 39.9% 48.0%
+Employee stock purchase plan 23.8% 20.2% 30.1%
+Expected life of the options (in years)
+Stock options 9.0 7.0 5.9
+Employee stock purchase plan 0.5 0.5 0.5
+The Black-Scholes option valuation model was developed for use in
+estimating the fair value of traded options that have no vesting restrictions
+and are fully transferable. In addition, option valuation models require the
+input of highly subjective assumptions including the expected stock price
+volatility. The Company's stock options have characteristics significantly
+F-24
+different from those of traded options, and because changes in the subjective
+input assumptions can materially affect the fair value estimate, it is
+management's opinion that the valuations afforded by the existing models are
+different from the value that the options would realize if traded in the market.
+Restricted Stock Plan
+In May 2004 the Restricted Stock Plan was approved by the Company's
+stockholders, establishing a long-term incentive program whereby grants of
+restricted stock or restricted stock units may be awarded to eligible employees,
+consultants, and members of the Board of Directors. Restrictions and vesting
+periods for the awards are determined at the discretion of the Board of
+Directors and are set forth in the award agreements. The total number of shares
+of the Company's common stock reserved for issuance under the Restricted Stock
+Plan is 5,600,000. This number is reduced to the extent that stock options are
+granted under the Company's Option Plans.
+St. Mary made grants of 232,861 RSUs in June 2004. The total expense
+associated with these grants was $8.3 million as measured on the date of the
+grant and has been reduced by $178,000 for forfeitures as of December 31, 2004.
+The total measured expense was initially recorded as deferred stock-based
+compensation and is being charged to compensation expense based on the vesting
+schedule. The RSU grants vest 25 percent immediately upon issuance and 25
+percent on each of the first three anniversary dates. The vested shares
+underlying the RSU grants will be issued on the third anniversary of the grants,
+at which time the shares carry no further restrictions. As of December 31, 2004,
+there were 169,616 unvested RSUs, which included the total of the 2004 grants
+less the vested portion of the grants and units forfeited due to employee
+terminations prior to vesting. Compensation expense for the year ended December
+31, 2004, related to the 2004 grants totaled $3.1 million. In addition, the
+Company recorded $1.1 million of compensation expense for the year ended
+December 31, 2004, related to the expected 25 percent immediate vesting of the
+estimated 2005 RSU grants.
+Non -Employee Director Stock Compensation Plan
+In May 2003, stockholders approved a Non-Employee Director Stock
+Compensation Plan to authorize the issuance of up to 30,000 shares of St. Mary
+common stock to non-employee directors as part of their compensation over an
+anticipated period of up to five years. The purpose of the plan is to attract,
+retain, and motivate non-employee directors. As of December 31, 2004, 12,600
+shares have been issued under this plan.
+Note 8 - Pension Benefits
+The Company's employees participate in a non-contributory pension plan
+covering substantially all employees who meet age and service requirements (the
+"Qualified Pension Plan"). The Company also has a supplemental non-contributory
+pension plan covering certain management employees (the "Nonqualified Pension
+Plan").
+F-25
+Obligations and Funded Status
+For the Years Ended December 31,
+-------------------------------------------------
+2004 2003 2002
+------------- -------------- -------------
+(In thousands)
+Change in benefit obligations:
+Projected benefit obligation at beginning of year $ 8,048 $ 6,330 $ 5,098
+Service cost 1,139 963 442
+Interest cost 489 428 358
+Amendments - - (46)
+Actuarial loss 1,236 620 503
+Benefits paid (738) (293) (25)
+------------- -------------- -------------
+Projected benefit obligation at end of year $ 10,174 $ 8,048 $ 6,330
+============= ============== =============
+Change in plan assets:
+Fair value of plan assets at beginning of year $ 3,694 $ 2,478 $ 2,042
+Actual return on plan assets 434 608 (255)
+Employer contribution 1,285 901 716
+Benefits paid (738) (293) (25)
+------------- -------------- -------------
+Fair value of plan assets at end of year $ 4,675 $ 3,694 $ 2,478
+============= ============== =============
+Funded status: $ (5,499) $ (4,354) $ (3,758)
+Unrecognized net loss 3,754 2,874 2,925
+Unrecognized prior service cost - (15) (41)
+------------- -------------- -------------
+Accrued benefit cost $ (1,745) $ (1,495) $ (874)
+============= ============== =============
+Amounts Recognized in the Consolidated Balance Sheets
+As of December 31,
+----------------------------------------------
+2004 2003
+--------------------- ---------------------
+(In thousands)
+Accrued benefit cost $ 1,745 $ 1,495
+Accumulated other comprehensive income 746 914
+--------------------- ---------------------
+Net amount recognized $ 2,491 $ 2,409
+===================== =====================
+Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
+As of December 31,
+-----------------------------------------
+2004 2003
+------------------- -----------------
+(In thousands)
+Projected benefit obligation $ 10,174 $ 8,048
+Accumulated benefit obligation $ 7,143 $ 6,058
+Fair value of plan assets $ 4,675 $ 3,694
+The Company's accumulated benefit obligation for the Qualified Pension
+Plan was $5.9 million at December 31, 2004, and $4.8 million at December 31,
+2003. The accumulated benefit obligation exceeds plan assets by $1.2 million.
+The tax-adjusted liability of $463,000 was recorded in other comprehensive
+income at December 31, 2004.
+F-26
+The Company's accumulated benefit obligation for the Nonqualified
+Pension Plan was $1.2 million at December 31, 2004, and $1.2 million at December
+31, 2003. There are no plan assets in the Nonqualified Pension Plan due to the
+nature of the plan.
+Components of Net Periodic Benefit Cost
+For the Years Ended December 31,
+---------------------------------------------
+2004 2003 2002
+------------- -------------- --------------
+(In thousands)
+Components of net periodic benefit cost:
+Service cost $ 1,139 $ 963 $ 442
+Interest cost 489 428 358
+Expected return on plan assets (295) (172) (146)
+Amortization of prior service cost (16) (25) (25)
+Amortization of net actuarial loss 218 329 211
+------------- -------------- --------------
+Net periodic benefit cost $ 1,535 $ 1,523 $ 840
+============= ============== ==============
+Prior service costs are amortized on a straight-line basis over the
+average remaining service period of active participants. Gains and losses in
+excess of 10 percent of the greater of the benefit obligation and the
+market-related value of assets are amortized over the average remaining service
+period of active participants.
+Additional Information
+The minimum liability included in other accumulated comprehensive
+income, net of taxes, decreased by $101,000 and $197,000 for the years ended
+December 31, 2004 and 2003, respectively, and increased by $761,000 for the year
+ended December 31, 2002.
+Assumptions
+Weighted-average assumptions to measure the Company's projected benefit
+obligation and net periodic benefit cost are as follows:
+As of December 31,
+--------------------------------------
+2004 2003
+---------------- ----------------
+Projected benefit obligation
+----------------------------
+Discount rate 5.75% 6.25%
+Expected return on plan assets 8.00% 8.00%
+Rate of compensation increase 4.00% 3.50%
+Net periodic benefit cost
+-------------------------
+Discount rate 6.25% 6.50%
+Expected return on plan assets 8.00% 8.00%
+Rate of compensation increase 3.50% 3.75%
+F-27
+Plan Assets
+The Company's weighted-average asset allocation for the Qualified Plan
+is as follows:
+As of December 31,
+Target -----------------------------------
+Asset Category 2005 2004 2003
+--------------------- ---------------- ---------------- ---------------
+Equity securities 60.0% 63.0% 61.4%
+Debt securities 40.0% 34.7% 38.0%
+Other 0% 2.3% 0.6%
+---------------- ---------------- ---------------
+Total 100.0% 100.0% 100.0%
+================ ================ ===============
+Equity securities do not include any shares of the Company's common
+stock for any period presented. There is no asset allocation for the
+Nonqualified Pension Plan since that plan does not have its own assets. An
+expected return on plan assets of eight percent was used to calculate the
+Company's obligation under the Qualified Plan. Factors considered in determining
+the expected return include the 60 percent equity and 40 percent debt securities
+mix of investment for plan assets and the long-term historical rate of return
+provided by the equity and debt securities markets. The estimated rate of return
+on plan assets was 11.7 percent for 2004 and 24.6 percent for 2003. The
+difference in investment income using the projected rate of return compared to
+the actual rates of return for the past two years was not material and will not
+have a material effect on the statements of operation or on cash flows from
+operating activities in future years.
+Contributions
+The Company contributed $1.3 million, $901,000, and $716,000 to the
+pension plans in the years ended December 31, 2004, 2003, and 2002,
+respectively. St. Mary expects to contribute approximately $1.1 million to the
+pension plans in 2005.
+Benefit Payments
+The Company made actual benefit payments of $738,000, $293,000, and
+$25,000 in the years ended December 31, 2004, 2003 and 2002, respectively.
+Expected benefit payments over the next ten years follows:
+Years Ended December 31, (in thousands)
+----------------------------------- ---------------
+2005 $ 368
+2006 $ 371
+2007 $ 469
+2008 $ 597
+2009 $ 837
+2010 through 2014 $ 11,752
+F-28
+Note 9 - Asset Retirement Obligations
+As of January 1, 2003, the Company adopted the provisions of SFAS No.
+143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally
+applies to legal obligations associated with the retirement of long-lived assets
+that result from the acquisition, construction, development and/or the normal
+operation of a long-lived asset. SFAS No. 143 requires the Company to recognize
+an estimated liability for future costs associated with the abandonment of its
+oil and gas properties. A liability for the fair value of an asset retirement
+obligation and a corresponding increase to the carrying value of the related
+long-lived asset is recorded at the time a well is completed or acquired. The
+increase in carrying value is included in proved oil and gas properties on the
+consolidated balance sheets. The Company depletes the amount added to proved oil
+and gas property costs and recognizes accretion expense in connection with the
+discounted liability over the remaining estimated economic lives of the
+respective oil and gas properties. Prior to the adoption of SFAS No. 143, the
+Company had recognized an abandonment liability for its offshore wells. These
+offshore liabilities were reversed upon adoption of SFAS No. 143, and the
+methodology described above was used to determine the liability associated with
+abandoning all wells, including those offshore.
+The estimated liability is based on historical experience in abandoning
+wells, estimated economic lives, external estimates as to the cost to abandon
+the wells in the future and federal, and state regulatory requirements. The
+liability is discounted using a credit-adjusted risk-free rate estimated at the
+time the liability is incurred or revised. The credit-adjusted risk-free rates
+used to discount the Company's abandonment liabilities range from 6.50 percent
+to 7.25 percent. Revisions to the liability could occur due to changes in
+estimated abandonment costs or well economic lives, or if federal or state
+regulators enact new requirements regarding the abandonment of wells.
+Upon adoption of SFAS No. 143, the Company recorded a discounted
+liability of $21.4 million, reversed the existing offshore abandonment liability
+of $9.1 million, increased property and equipment by $12.8 million, decreased
+accumulated DD&A by $8.3 million and recognized a one-time cumulative effect
+gain of $5.4 million (net of deferred tax benefit of $3.4 million).
+A reconciliation of the Company's asset retirement obligation liability
+is as follows:
+As of December 31,
+---------------------------------
+2004 2003
+-------------- ---------------
+(In thousands)
+Beginning asset retirement obligation $ 25,485 $ -
+Liability from SFAS 143 adoption - 21,403
+Liabilities incurred 7,187 4,395
+Liabilities settled (620) (3,169)
+Accretion expense 1,984 1,719
+Revision to estimated cash flows 6,875 1,137
+-------------- ---------------
+Ending asset retirement obligation $ 40,911 $ 25,485
+============== ===============
+F-29
+The following tables illustrate the effect on the asset retirement
+obligation liability, net income and earnings per share if the Company had
+adopted the provisions of SFAS No. 143 on January 1, 2002. The pro forma amounts
+are calculated using current information, assumptions and interest rates as of
+January 1, 2003 (in thousands, except per share amounts).
+As of December 31,
+--------------------------------
+2002
+--------------------------------
+Asset retirement obligation liability $ 21,829
+Year Ended December 31,
+------------------------------
+2002
+------------------------------
+Net income
+As reported $ 27,560
+Pro forma $ 26,622
+Basic earnings per share
+As reported $ 0.99
+Pro forma $ 0.96
+Diluted earnings per share
+As reported $ 0.97
+Pro forma $ 0.94
+Note 10 - Derivative Financial Instruments
+The Company realized a net loss of $50.6 million from its derivative
+contracts for the year ended December 31, 2004, a net loss of $22.7 million for
+the year ended December 31, 2003, and a net gain of $953,000 for the year ended
+December 31, 2002.
+The following table summarizes derivative instrument gain (loss)
+activity (in thousands):
+For the Years Ended December 31,
+---------------------------------------------
+2004 2003 2002
+--------------- -------------- ------------
+Derivative contract settlements included
+in oil and gas hedge loss $ (50,299) $ (22,439) $ (2,235)
+Ineffective portion of hedges qualifying
+for hedge accounting included in
+derivative gain (loss) 113 (246) (32)
+Non-qualified derivative contracts included
+in derivative gain (loss) (373) (64) 3,220
+--------------- -------------- ------------
+Total gain (loss) $ (50,559) $ (22,749) $ 953
+=============== ============== ============
+Oil and Gas Commodity Hedges
+The Company has in place derivative contracts for the sale of oil and
+natural gas. The Company attempts to qualify these instruments as cash flow
+hedges for accounting purposes. The table below describes the volumes and
+average contract prices of hedges currently in place. The Company's oil and
+natural gas derivative contracts include swap and collar arrangements. Gas
+contracts are indexed to a variety of regional indexes, and the oil contracts
+are NYMEX based.
+F-30
+Swaps Gas (per MMBtu) Oil (per Bbl)
+-----
+------------------------------------------- ------------------------------------------
+Weighted-Average Weighted-Average
+Contract Contract Price Contract Price
+Period Volumes (Regional Index) Volumes (NYMEX)
+--------------- ----------------------- --------------- -----------------------
+2005
+----
+Quarter Ending:
+March 31, 2,297,800 $ 7.16 242,452 $ 40.19
+June 30, 2,026,600 $ 6.16 184,214 $ 42.56
+September 30, 1,605,000 $ 6.24 188,980 $ 41.61
+December 31, 1,590,000 $ 6.54 138,770 $ 40.80
+--------------- ---------------
+Total 2005 7,519,400 $ 6.56 754,416 $ 41.24
+--------------- ---------------
+2006
+----
+Quarter Ending:
+March 31, 720,000 $ 6.49 103,366 $ 38.93
+June 30, 710,000 $ 5.51 99,976 $ 38.15
+September 30, 690,000 $ 5.49 100,372 $ 37.47
+December 31, 270,000 $ 5.55 77,686 $ 36.42
+--------------- ---------------
+Total 2006 2,390,000 $ 5.80 381,400 $ 37.83
+--------------- ---------------
+2007
+----
+Quarter Ending:
+March 31, - $ - 63,410 $ 35.63
+June 30, - $ - 61,072 $ 35.35
+September 30, - $ - 62,684 $ 35.10
+December 31, - $ - 60,620 $ 34.79
+--------------- ---------------
+Total 2007 - $ - 247,786 $ 35.22
+--------------- ---------------
+All Contracts 9,909,400 $ 6.38 1,383,602 $ 39.22
+=============== ===============
+Collars Gas (per MMBtu)
+-------
+---------------------------------------------------------------------
+Weighted- Weighted-
+Average Average
+Contract Floor Ceiling
+Period Price Price Volumes Index
+----- ----- ------- -----
+2005
+----
+Quarter Ending:
+March 31, $ 6.62 $ 8.08 540,000 IF ANR OK
+June 30, $ 5.73 $ 7.20 540,000 IF ANR OK
+September 30, $ 5.75 $ 7.30 415,000 IF ANR OK
+December 31, $ 6.00 $ 7.63 390,000 IF ANR OK
+---------------------
+All Contracts $ 6.05 $ 7.57 1,885,000
+=====================
+F-31
+The Company seeks to minimize basis risk and indexes its oil contracts
+to NYMEX prices and its gas contracts to various regional index prices
+associated with pipelines in proximity to the Company's areas of gas production.
+Swap natural gas volumes associated with specific Inside FERC ("IF") regional
+indexes are as follows:
+Regional Index MMBtu
+--------------
+IF ANR OK 4,679,400
+IF Reliant N/S 2,920,000
+IF PEPL 2,310,000
+--------------
+Total 9,909,400
+==============
+Derivative gain (loss) in the consolidated statements of operations for
+the year ended December 31, 2004, and 2003, include a net gain of $113,000 and a
+net loss of $246,000 from ineffectiveness related to oil and natural gas
+derivative contracts, respectively. On December 31, 2004, the estimated fair
+value of oil and natural gas derivative contracts designated and qualifying as
+cash flow hedges under SFAS No. 133 was a net asset of $4.2 million. If prices
+remain unchanged from year end levels, the Company would reclassify this amount
+to oil and gas hedge gain included in operating revenue as the hedged production
+quantity is produced. As of December 31, 2004, the net amount of unrealized gain
+net of deferred income taxes to be reclassified from accumulated other
+comprehensive income to oil and gas production operating revenues in the next
+twelve months was $5.0 million. The Company anticipates that all original
+forecasted transactions will occur by the end of their originally specified
+periods.
+Interest Rate Derivative Contracts
+In October 2003 the Company entered into fixed-to-floating interest
+rate swaps for a total notional amount of $50.0 million through March 20, 2007.
+Under the swaps, St. Mary will be paid a fixed interest rate of 5.75 percent and
+will pay a variable interest rate of 235 basis points above the six-month LIBOR
+rate as determined on the semi-annual settlement date. The payment dates of the
+swaps match the interest payment dates of the Convertible Notes. The six-month
+LIBOR rate on December 31, 2004, was 2.78 percent. Realized gains included in
+interest expense on these swaps were $795,000 in 2004. Derivative gain (loss) in
+the consolidated statements of operations for the year ended December 31, 2004,
+and 2003, includes a $328,000 and $104,000 net loss, respectively, from
+mark-to-market adjustments for this derivative. The fair value of the swaps was
+a liability of $432,000 and $104,000 as of December 31, 2004, and 2003,
+respectively.
+Included in the consolidated statements of operations in 2002 is a net
+realized gain of $3.6 million included in derivative gain. This gain was
+generated from the settlement of a fixed-to-floating interest rate swap contract
+entered into in March 2002 on $50.0 million of the Convertible Notes. This swap
+did not qualify for fair value hedge treatment under SFAS No. 133 and related
+pronouncements. This contract was closed out on December 3, 2002.
+Convertible Note Derivative Instrument
+The Company's Convertible Notes contain a provision for payment of
+contingent interest if certain conditions are met. Under SFAS No. 133 this
+provision is considered an embedded equity-related derivative that is not
+clearly and closely related to the fair value of an equity interest and
+therefore must be treated as a separate derivative instrument. The value of the
+derivative at issuance of the Convertible Notes in March 2002 was $474,000. This
+amount was recorded as a decrease to the Convertible Notes payable in the
+consolidated balance sheets. Of this amount, $95,000, $95,000 and $75,000 have
+been amortized through interest expense for the years ended December 31, 2004,
+2003, and 2002, respectively. Derivative gain (loss) in the consolidated
+statements of operations for the years ended December 31, 2004, 2003, and 2002,
+includes a $45,000 net loss, a $40,000 net gain and a $341,000 net loss,
+respectively, from mark-to-market adjustments for this derivative. The fair
+value of this derivative at December 31, 2004 and 2003, was a liability of
+$820,000 and $775,000, respectively.
+F-32
+Note 11 - Repurchase of St. Mary Common Stock
+Flying J Repurchase Transaction
+On February 9, 2004, the Company repurchased from Flying J 3,380,818
+restricted shares of St. Mary common stock for a total of $91.0 million. These
+shares were originally issued by St. Mary to Flying J on January 29, 2003, in
+connection with St. Mary's acquisition of oil and gas properties. In addition to
+issuing the shares in the acquisition, St. Mary loaned Flying J $71.6 million.
+Flying J used the proceeds to repay their outstanding loan balance to St. Mary
+of $71.6 million. Accrued interest, which was not recorded by the Company for
+financial reporting purposes due to the non-recourse nature of the loan, was
+forgiven. The net $19.4 million cash outlay was funded from the Company's
+existing cash balances and borrowings under its credit facility.
+Stock Repurchase Program
+In August 2004 the Company's Board of Directors approved an
+increase in the number of shares that may be repurchased under the original
+authorization approved in August of 1998 to 3,000,000 as of the effective date
+of the resolution. St. Mary had not made any repurchases under the program since
+2001. The shares may be repurchased from time to time in open market
+transactions or privately negotiated transactions, subject to market conditions
+and other factors, including certain provisions of St. Mary's existing credit
+facility agreement and compliance with securities laws. Stock repurchases may be
+funded with existing cash balances, internal cash flow and borrowings under the
+credit facility. The stock repurchase program may be suspended or discontinued
+at any time. As of December 31, 2004, a total of 1,499,200 shares of the
+Company's common stock had been repurchased under the plan. The company
+repurchased 489,300 and -0- shares in 2004 and 2003, respectively. In September
+2004 the Company retired from treasury the 489,300 shares repurchased in 2004
+together with 740,100 shares repurchased in prior years.
+Note 12 - Disclosures about Oil and Gas Producing Activities
+Costs Incurred in Oil and Gas Producing Activities:
+Costs incurred in oil and gas property acquisition, exploration and
+development activities, whether capitalized or expensed, are summarized as
+follows. The 2004 and 2003 amounts include $14.1 million and $5.5 million,
+respectively, of capitalized costs associated with asset retirement obligations.
+For the Years Ended December 31,
+-----------------------------------------------------
+2004 2003 2002
+--------------- --------------- ---------------
+(In thousands)
+Development costs $ 190,829 $ 111,908 $ 74,376
+Exploration 37,977 33,296 22,548
+Acquisitions:
+Proved 69,054 73,989 85,559
+Unproved 7,646 8,942 2,147
+Leasing activity 7,877 7,480 8,128
+--------------- --------------- ---------------
+Total $ 313,383 $ 235,615 $ 192,758
+=============== =============== ===============
+Oil and Gas Reserve Quantities (Unaudited):
+For all years presented the reserve information for greater than 80
+percent of the PV-10 value was prepared by Ryder Scott Company L.P. and/or
+Netherland, Sewell and Associates, Inc. ("NSAI"). The Company engaged NSAI for
+the first time in 2004. St. Mary prepared the reserve estimates for the
+remainder of all properties. The Company emphasizes that reserve estimates are
+inherently imprecise and that estimates of new discoveries and undeveloped
+locations are more imprecise than estimates of established proved producing oil
+and gas properties. Accordingly, these estimates are expected to change as
+future information becomes available.
+F-33
+Proved oil and gas reserves are the estimated quantities of crude oil,
+natural gas and natural gas liquids that geological and engineering data
+demonstrate with reasonable certainty to be recoverable in future years from
+known reservoirs under existing economic and operating conditions. Proved
+developed oil and gas reserves are those expected to be recovered through
+existing wells with existing equipment and operating methods. All of the
+Company's proved reserves are located in the United States.
+Presented below is a summary of the changes in estimated reserves of
+the Company:
+For the Years Ended December 31,
+-------------------------------------------------------------------------------------------
+2004 2003 2002
+---------------------------- --------------------------- ----------------------------
+Oil or Oil or Oil or
+Condensate Gas Condensate Gas Condensate Gas
+-------------- ----------- ------------ ----------- ------------- -----------
+(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
+Developed and undeveloped:
+Beginning of year 47,787 307,024 36,119 274,172 23,669 241,231
+Revisions of previous estimate 1,994 (21,885) 2,856 3,904 3,611 4,696
+Discoveries and extensions 6,306 63,185 3,681 69,189 1,250 32,813
+Purchases of minerals in place 5,773 17,635 11,952 41,335 10,578 38,118
+Sales of reserves (487) (165) (2,280) (31,913) (174) (4,522)
+Production (4,799) (46,598) (4,541) (49,663) (2,815) (38,164)
+-------------- ----------- ------------ ----------- ------------- -----------
+End of year (a) 56,574 319,196 47,787 307,024 36,119 274,172
+============== =========== ============ =========== ============= ===========
+Proved developed reserves:
+Beginning of year 43,693 264,140 33,580 228,973 20,679 205,637
+============== =========== ============ =========== ============= ===========
+End of year 47,992 272,295 43,693 264,140 33,580 228,973
+============== =========== ============ =========== ============= ===========
+-------------------
+(a) At December 31, 2004, 2003, and 2002 amounts include approximately
+480, 1,119, and 1,151 MMcf, respectively, representing the
+Company's net underproduced gas balancing position.
+Standardized Measure of Discounted Future Net Cash Flows (Unaudited):
+SFAS No. 69, "Disclosures about Oil and Gas Producing Activities,"
+prescribes guidelines for computing a standardized measure of future net cash
+flows and changes therein relating to estimated proved reserves. The Company has
+followed these guidelines, which are briefly discussed below.
+Future cash inflows and future production and development costs are
+determined by applying benchmark prices and costs, including transportation,
+quality and basis differentials, in effect at year-end to the year-end estimated
+quantities of oil and gas to be produced in the future. Each property the
+Company operates is also charged with field-level overhead in the estimated
+reserve calculation. Estimated future income taxes are computed using current
+statutory income tax rates, including consideration for estimated future
+statutory depletion. The resulting future net cash flows are reduced to present
+value amounts by applying a 10 percent annual discount factor.
+Future operating costs are determined based on estimates of
+expenditures to be incurred in developing and producing the proved oil and gas
+reserves in place at the end of the period, using year-end costs and assuming
+continuation of existing economic conditions, plus Company overhead incurred by
+the central administrative office attributable to operating activities.
+F-34
+The assumptions used to compute the standardized measure are those
+prescribed by the FASB and the Securities and Exchange Commission. These
+assumptions do not necessarily reflect the Company's expectations of actual
+revenues to be derived from those reserves, nor their present value. The
+limitations inherent in the reserve quantity estimation process, as discussed
+previously, are equally applicable to the standardized measure computations
+since these estimates are the basis for the valuation process. The following
+prices, adjusted for transportation, quality and basis differentials, were used
+in the calculation of the standardized measure:
+2004 2003 2002
+----------- ---------- ----------
+Gas (per Mcf) $ 5.80 $ 5.70 $ 4.21
+Oil (per Bbl) $ 40.06 $ 31.01 $ 29.31
+The following summary sets forth the Company's future net cash flows
+relating to proved oil and gas reserves based on the standardized measure
+prescribed in SFAS No. 69:
+As of December 31,
+------------------------------------------------------
+2004 2003 2002
+--------------- ---------------- ----------------
+(In thousands)
+Future cash inflows $ 4,118,188 $ 3,232,605 $ 2,238,513
+Future production costs (1,349,380) (963,226) (696,132)
+Future development costs (164,797) (101,935) (87,859)
+Future income taxes (827,368) (735,947) (429,618)
+--------------- ---------------- ----------------
+Future net cash flows 1,776,643 1,431,497 1,024,904
+10 percent annual discount (742,705) (571,541) (443,042)
+--------------- ---------------- ----------------
+Standardized measure of discounted
+future net cash flows $ 1,033,938 $ 859,956 $ 581,862
+=============== ================ ================
+The principle sources of change in the standardized measure of
+discounted future net cash flows are:
+For the Years Ended December 31,
+-------------------------------------------------------
+2004 2003 2002
+----------------- ---------------- --------------
+(In thousands)
+Standard measure, beginning of year $ 859,956 $ 581,862 $ 281,877
+Sales of oil and gas produced, net of
+production costs and hedging (368,099) (299,044) (137,066)
+Net changes in prices and production costs 166,826 168,661 298,079
+Extensions, discoveries and other, net of
+production costs 279,763 226,181 92,227
+Purchase of minerals in place 73,875 178,264 160,089
+Development costs incurred during the year 46,156 22,763 23,802
+Changes in estimated future development costs (17,489) 11,175 4,265
+Revisions of previous quantity estimates (24,271) 45,551 49,892
+Accretion of discount 125,175 78,869 34,749
+Sales of reserves in place (3,906) (47,270) (708)
+Net change in income taxes (75,389) (211,381) (177,335)
+Changes in timing and other (28,659) 104,325 (48,009)
+----------------- ---------------- --------------
+Standardized measure, end of year $ 1,033,938 $ 859,956 $ 581,862
+================= ================ ==============
+F-35
+Note 13 - Quarterly Financial Information (Unaudited)
+The Company's quarterly financial information for fiscal 2004 and 2003
+is as follows (in thousands, except per share amounts):
+First Second Third Fourth
+Quarter Quarter Quarter Quarter
+------------- -------------- -------------- --------------
+Year Ended December 31, 2004
+----------------------------
+Total revenue $ 96,482 $ 102,151 $ 108,078 $ 126,388
+Less: costs and expenses 60,603 65,566 71,575 83,440
+------------- -------------- -------------- --------------
+Income from operations $ 35,879 $ 36,585 $ 36,503 $ 42,948
+Income before income taxes $ 34,535 $ 35,262 $ 35,125 $ 41,306
+Net income $ 21,449 $ 21,836 $ 22,565 $ 26,629
+Basic net income per common share $ 0.72 $ 0.76 $ 0.79 $ 0.94
+Diluted net income per common share $ 0.66 $ 0.69 $ 0.71 $ 0.83
+Dividends declared per common share $ - $ 0.05 $ 0.05 -
+Year Ended December 31, 2003
+----------------------------
+Total revenue $ 101,155 $ 103,628 $ 90,935 $ 97,990
+Less: costs and expenses 54,736 61,619 66,624 57,418
+------------- -------------- -------------- --------------
+Income from operations $ 46,419 $ 42,009 $ 24,311 $ 40,572
+Income before income taxes and cumulative effect
+of accounting principle $ 44,433 $ 39,986 $ 22,551 $ 39,100
+Net income $ 32,797 $ 24,317 $ 13,786 $ 24,675
+Basic earnings per common share:
+Income before cumulative effect of
+change in accounting principle $ 0.90 $ 0.77 $ 0.44 $ 0.78
+Cumulative effect of change in
+accounting principle 0.18 - - -
+------------- -------------- -------------- --------------
+Basic net income per common share $ 1.08 $ 0.77 $ 0.44 $ 0.78
+============= ============== ============== ==============
+Diluted earnings per common share:
+Income before cumulative effect of
+change in accounting principle $ 0.81 $ 0.71 $ 0.41 $ 0.72
+Cumulative effect of change in
+accounting principle 0.16 - - -
+------------- -------------- -------------- --------------
+Diluted net income per common share $ 0.97 $ 0.71 $ 0.41 $ 0.72
+============= ============== ============== ==============
+Dividends declared per common share $ - $ 0.05 $ - $ 0.05
+F-36
+SIGNATURES
+Pursuant to the requirements of Section 13 or 15(d) of the Securities
+Exchange Act of 1934, the registrant has duly caused this report to be signed on
+its behalf by the undersigned, thereunto duly authorized.
+ST. MARY LAND & EXPLORATION COMPANY
+---------------------------------------
+(Registrant)
+Date: February 25, 2005 By: /S/ MARK A HELLERSTEIN
+-----------------------
+Mark A. Hellerstein
+Chairman of the Board of Directors, President
+and Chief Executive Officer
+POWER OF ATTORNEY
+KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature
+appears below constitutes and appoints each of Mark A. Hellerstein and David W.
+Honeyfield his or her true and lawful attorney-in-fact and agent with full power
+of substitution and resubstitution, and each with full power to act alone, for
+the undersigned and in his or her name, place and stead, in any and all
+capacities, to sign any amendments to this Annual Report on Form 10-K for the
+fiscal year ended December 31, 2004, and to file the same, with exhibits thereto
+and other documents in connection therewith, with the Securities and Exchange
+Commission, hereby ratifying and confirming all that each of said
+attorney-in-fact, or his substitute or substitutes, may do or cause to be done
+by virtue hereof.
+Pursuant to the requirements of the Securities Exchange Act of 1934,
+this report has been signed below by the following persons on behalf of the
+registrant and in the capacities and on the dates indicated.
+Signature Title Date
+--------- ----- ----
+/S/ MARK A. HELLERSTEIN
+-----------------------
+Mark A. Hellerstein Chairman of the Board February 25, 2005
+of Directors, President
+and Chief Executive Officer
+/S/ DAVID W. HONEYFIELD
+-----------------------
+David W. Honeyfield Vice President-Finance, February 25, 2005
+Secretary and Treasurer
+/S/ GARRY A. WILKENING
+----------------------
+Garry A. Wilkening Vice President-Administration February 25, 2005
+and Controller
+Signature Title Date
+--------- ----- ----
+/S/BARBARA M. BAUMANN
+---------------------
+Barbara M. Baumann Director February 25, 2005
+/S/ LARRY W. BICKLE
+-------------------
+Larry W. Bickle Director February 25, 2005
+/S/ RONALD D. BOONE
+-------------------
+Ronald D. Boone Director February 25, 2005
+/S/ THOMAS E. CONGDON
+---------------------
+Thomas E. Congdon Director February 25, 2005
+/S/ WILLIAM J. GARDINER
+-----------------------
+William J. Gardiner Director February 25, 2005
+/S/ WILLIAM D. SULLIVAN
+-----------------------
+William D. Sullivan Director February 25, 2005
+/S/ JOHN M. SEIDL
+-----------------
+John M. Seidl Director February 25, 2005
\ No newline at end of file
diff --git a/raw/filings/0000893538/2004/0000893538-05-000026/filing_metadata.csv b/raw/filings/0000893538/2004/0000893538-05-000026/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..20c1153eda89e4991bfc727013667e5d74b066cc
--- /dev/null
+++ b/raw/filings/0000893538/2004/0000893538-05-000026/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000893538,SM,SM Energy Co,10-K,2005-02-25,2004-12-31,2005-02-25T18:38:05.000Z,0000893538-05-000026,asci1204_10k.htm,10-K 12/31/04 ST MARY LAND & EXPLORATION,443522,0,0,https://www.sec.gov/Archives/edgar/data/893538/000089353805000026/asci1204_10k.htm,https://www.sec.gov/Archives/edgar/data/893538/000089353805000026/,2004,2004,1
diff --git a/raw/filings/0000893538/2004/0000893538-05-000026/item1.txt b/raw/filings/0000893538/2004/0000893538-05-000026/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..bff683fd48d596dfc0588ce35f71f8d356ccefb6
--- /dev/null
+++ b/raw/filings/0000893538/2004/0000893538-05-000026/item1.txt
@@ -0,0 +1,1002 @@
+ITEM 1. BUSINESS
+Background
+We are an independent oil and gas company engaged in the exploration,
+exploitation, development, acquisition and production of natural gas and crude
+oil. We were founded in 1908 and incorporated in Delaware in 1915. Our primary
+objective is to invest in oil and gas producing assets that result in a superior
+return on equity while preserving underlying capital, resulting in a return on
+equity to stockholders that reflects capital appreciation as well as the payment
+of cash dividends. Our operations are focused in the following five core
+operating areas in the United States:
+o the Mid-Continent region in western Arkansas, Oklahoma and
+northern Texas, primarily in the Anadarko and Arkoma basins,
+with significant activity in the Northeast Mayfield field;
+o the Rocky Mountain region consisting of the Williston Basin in
+eastern Montana and western North Dakota and the Powder River,
+Green River, Wind River and Big Horn basins in Wyoming. The
+most recent activity in the Rockies includes drilling in the
+Middle Bakken formations, continued exploration in the Red
+River formation, and the development of coalbed methane
+reserves in the Hanging Woman Basin;
+o the ArkLaTex region that spans northern Louisiana and southern
+Arkansas, Mississippi and eastern Texas, with the most recent
+activity drilling horizontal wells in the James and Pettet
+Limestones;
+o the Gulf Coast region, including the Judge Digby field and our
+fee property in St. Mary Parish, Louisiana;
+o the Permian Basin in eastern New Mexico and western Texas;
+included in this area is the Parkway Delaware Unit and the
+East Shugart Delaware Unit in New Mexico.
+As of December 31, 2004, we had estimated proved reserves of
+approximately 56.6 MMBbl of oil and 319.2 Bcf of natural gas, or a total of
+658.6 BCFE with a PV-10 value of $1.5 billion. Of these reserves, 85 percent
+were proved developed and 52 percent were crude oil. This represents an
+increase in reserve volumes of 11 percent and a 17 percent increase in PV-10
+value from a year earlier. For the year ended December 31, 2004, we produced
+75.4 BCFE representing average daily production of 206.0 MMCFE, a two percent
+decrease from 2003. Our reserve replacement in 2004 was 190 percent of
+production. Included in the proved reserve total at December 31, 2004 is 9.4
+BCFE in our coalbed methane projects in the Hanging Woman Basin and the Atlantic
+Rim field.
+We attempt to focus our resources in selected domestic basins where we
+believe our expertise in geology, geophysics and drilling and completion
+techniques provides us with competitive advantages. We have assembled a balanced
+program of low-to-medium-risk development and exploitation projects to provide
+1
+the foundation for steady growth, including non-conventional gas plays in the
+Rocky Mountain region. In 2004 we spent $228.8 million in capital expenditures
+related to drilling activities, $76.7 million on acquisition of oil and gas
+properties and $7.9 million on leasing activity.
+We measure and rank our investment decisions based on their
+risk-adjusted estimated internal rate of return and return on investment. In
+2004 all acquisitions were funded with available cash and funding from our
+revolving credit facility. When we issue stock for the acquisition of properties
+or a corporate entity, we base our investment decision primarily on the
+transaction's impact on net asset value per share.
+We divest selected non-core assets when market conditions and prices
+are attractive, and we will continue to evaluate such opportunities in the
+future. For example, in 2004 we sold certain oil and gas properties for total
+proceeds of approximately $2.8 million, resulting in a gain of $1.8 million.
+We seek to develop our existing property base and acquire acreage with
+additional potential in our core areas. From January 1, 2002, through December
+31, 2004, we participated in the drilling or recompletion of 777 gross wells
+with a success rate of 84 percent. During that same period we added estimated
+proved reserves of 537.0 BCFE at an average finding cost of $1.38 per MCFE. Our
+average annual production replacement was 259 percent during this three-year
+period, and our production has grown from an average daily rate of 150.8 MMCFE
+per day in 2002 to 206.0 MMCFE per day in 2004. Production in December 2004
+averaged 216.7 MMCFE per day.
+As of December 31, 2004, we had an acreage position of 1,969,808 gross
+(1,037,522 net) acres of which 1,184,086 gross (722,396 net) acres were
+undeveloped. Our current leasehold position represents a 2 percent decrease on a
+gross acre basis and a 5 percent decrease on a net acre basis from 2003. In
+addition to the leased acreage position, we own 24,914 net acres of fee
+properties in St. Mary Parish, Louisiana and mineral servitudes representing
+14,316 gross (9,514 net) acres in other portions of Louisiana.
+For 2005 we have budgeted capital expenditures of $293 million for
+ongoing development, exploitation and exploration programs in our core operating
+areas and $125 million for the acquisition of oil and gas properties.
+Our principal offices are located at 1776 Lincoln Street, Suite 700,
+Denver, Colorado 80203, and our telephone number is (303) 861-8140.
+Business Strategy
+Our objective is to build stockholder value through consistent economic
+growth in reserves and production that increase net asset value and earnings per
+share. The principal elements of our strategy are as follows:
+o Maintain Focused Geographic Operations. We focus on
+exploration, development and acquisition activities in five
+core operating areas where we have built a balanced portfolio
+of proved reserves, development drilling opportunities,
+leasehold, and non-conventional gas prospects. We believe that
+our significant leasehold position is a strategic asset. Our
+senior technical managers, each possessing over 15 years of
+industry experience, head up fully-staffed regional technical
+offices that are supported by centralized administration from
+our Denver office. We believe that our long-standing presence,
+our application of technology, our established networks of
+2
+local industry relationships and our acreage holdings in our
+core operating areas provide us with a competitive advantage.
+o Continue Exploitation and Development of Existing Properties.
+We use our comprehensive base of geological, geophysical,
+engineering and production experience in each of our core
+operating areas to source prospects for our ongoing
+low-to-medium-risk development and exploitation programs. We
+conduct detailed geologic studies and use an array of
+technologies and tools including 2-D and 3-D seismic imaging,
+hydraulic fracturing and reservoir stimulation techniques,
+horizontal drilling, secondary recovery and specialized
+logging tools to enhance the potential of our existing
+properties. In 2004 we participated in the drilling or
+recompletion of 368 gross wells with an 88 percent success
+rate.
+o Make Selective Acquisitions. We make selective acquisitions of
+oil and gas properties that complement our existing
+operations, offer economies of scale and provide further
+development, exploitation and exploration opportunities based
+on proprietary geologic concepts. We focus on relatively small
+transactions where we have specialized geologic knowledge or
+operating experience to enable us to acquire attractively
+priced properties. In addition, we pursue corporate
+acquisitions that we believe are accretive and capable of
+being integrated into the Company. In 2004, we acquired the
+stock of Goldmark Engineering, Inc., and in early 2005 we
+completed the acquisition of Agate Petroleum, Inc. Other
+examples of corporate acquisitions include our 1999 Nance
+Petroleum Corporation and King Ranch Energy, Inc.
+acquisitions, both of which were accomplished with the
+issuance of our common stock. The Flying J Oil & Gas Inc.
+et al. property acquisition transaction completed in 2003 was
+not a corporate acquisition. We used a combination of
+restricted stock, a loan to Flying J and options on our common
+stock to consummate this transaction. We have budgeted $125
+million for acquisitions in 2005.
+o Control Operations. We believe it is important to control
+geologic and operational decisions as well as the timing of
+those decisions. As of December 31, 2004, we operated 69
+percent of our properties on a reserve volume basis and 66
+percent on a PV-10 value basis. We are the operator of
+properties representing approximately 71 percent of our 2005
+capital budget.
+o Maintain Financial Flexibility. Conservative use of financial
+leverage has long been a critical element of our strategy. We
+believe that maintaining a strong balance sheet is a
+significant competitive advantage that enables us to pursue
+acquisition and other opportunities, especially in weaker
+price environments. It also provides us with the financial
+resources to weather periods of volatile commodity prices or
+escalating costs. Our debt to total capitalization ratio was
+22 percent at the end of December 2004.
+Significant Developments since December 31, 2003
+o 2004 Acquisition of Oil and Gas Properties. Our total
+acquisitions of proved and unproved oil and gas properties in
+2004 were $76.7 million. The two most significant acquisitions
+were the Goldmark Engineering, Inc. et al. acquisition that
+closed on November 1, 2004 for $23.3 million and the Border
+Company et al. acquisition that closed on December 15, 2004
+for $37.8 million. The primary asset acquired in the Goldmark
+transaction was the operations and majority ownership in the
+Fourbear Field, located in the Big Horn Basin of Wyoming. We
+anticipate that the development program in this field will be
+quite active in 2005 and will include infill drilling,
+recompletion of additional pay zones, workovers and the
+possible employment of enhanced recovery techniques. The
+3
+Border Company acquisition primarily included a non-operated
+interest in the very active Elm Grove Field, located in
+Northern Louisiana where we expect to participate in numerous
+development locations.
+o Coalbed Methane Development. We realized our first commercial
+production for the Hanging Woman Basin coalbed methane project
+in 2004. Our total proved reserves at Hanging Woman Basin at
+the end of 2004 were 8 BCFE. During 2004 we drilled and
+completed 57 wells. The non-operated pipeline and compression
+station connecting the wells to the main trunk line became
+operational in mid-December 2004. The 2005 capital program for
+the Hanging Woman Basin development is currently budgeted at
+$24 million. We also participated in a coalbed methane
+development project at Atlantic Rim in the Green River Basin
+of Wyoming.
+o Increase in 2004 Year-End Reserves. Proved reserves increased
+11 percent to 658.6 BCFE at December 31, 2004, from 593.7 BCFE
+at December 31, 2003. We added 52 BCFE through acquisitions,
+primarily in the Rocky Mountain and ArkLaTex regions, and 101
+BCFE from drilling activities. There were net downward
+revisions of previous reserves totaling 10 BCFE. These
+downward revisions were the combination of a 16 BCFE increase
+resulting from price adjustments and a 26 BCFE decrease due to
+performance revisions. The 11 percent increase in reserves
+over last year is net of current year sales of oil and gas
+properties of 3 BCFE.
+o Drilling Results. The majority of the reserve additions
+attributed to drilling operations came from our Rocky Mountain
+and Mid-Continent regions. The increase in the Rockies can be
+attributed primarily to continued development of the Middle
+Bakken play. This is one of the most active plays in the
+United States. Currently concentrated in Montana, the play is
+thought to extend into North Dakota. As of year end, we have
+approximately 181,000 net acres leased in Richland County,
+Montana, and McKenzie and Billings Counties, North Dakota, of
+which we believe approximately 74,000 net acres is in the
+primary trend. The Red River formation continues to result in
+reserve additions in the Rockies as we take full advantage of
+3-D seismic to identify multi-pay structures. Mid-Continent
+reserve additions were primarily from the continued
+exploitation and development of the Northeast Mayfield area,
+although the results were less significant than in the prior
+year. The finding costs resulting from the Mid-Continent area
+were higher than the Company average as a whole.
+o Repurchase of Common Stock. In February 2004, we repurchased
+3,380,818 shares of our common stock from Flying J for a total
+of $91.0 million. We originally issued these shares to Flying
+J on January 29, 2003, in connection with our acquisition of
+oil and gas properties. We also loaned Flying J $71.6 million
+in connection with the property acquisition. Flying J used the
+proceeds from the share repurchase to repay the outstanding
+loan balance. The net $19.4 million difference was funded from
+our available cash and from borrowings under our credit
+facility. The amount funded from borrowings under our credit
+facility was repaid during the second quarter of 2004. In the
+third quarter of 2004, we re-initiated our stock repurchase
+program. Since that time we have repurchased a total of
+489,300 shares of our common stock at an average cost of
+$33.39 per share. These repurchases were funded from available
+cash. As of December 31, 2004, the number of additional shares
+that may be repurchased under the program is 2,510,700.
+4
+Major Customers
+During 2004, sales to Tesoro Refining and Marketing accounted for 20
+percent of our total oil and gas production revenue. During 2003, sales to BP
+America Production Company accounted for 14 percent, sales to Midcoast Energy
+accounted for 13 percent and sales to Tesoro Refining and Marketing accounted
+for 11 percent of our total oil and gas production revenue. During 2002, there
+were no sales to individual customers that accounted for more than 10 percent of
+our total oil and gas production revenue.
+Employees and Office Space
+As of February 15, 2005, we had 256 full-time employees. None of our
+employees are subject to a collective bargaining agreement, and we consider our
+relations with our employees to be good. We lease approximately 47,400 square
+feet of office space in Denver, Colorado, for our executive and administrative
+offices, of which 9,500 square feet is subleased. We also lease approximately
+18,600 square feet of office space in Tulsa, Oklahoma; approximately 11,700
+square feet in Shreveport, Louisiana; approximately 13,700 square feet in
+Houston, Texas; and approximately 22,200 square feet in Billings, Montana.
+Title to Properties
+Substantially all of our working interests are held pursuant to leases
+from third parties. A title opinion is usually obtained prior to the
+commencement of drilling operations on properties. We have obtained title
+opinions or conducted a thorough title review on substantially all of our
+producing properties and believe that we have satisfactory title to such
+properties in accordance with standards generally accepted in the oil and gas
+industry. The majority of the value of our properties is subject to a mortgage
+under our credit facility, customary royalty interests, liens for current taxes,
+and other burdens that we believe do not materially interfere with the use of or
+affect the value of such properties. We perform only a minimal title
+investigation before acquiring undeveloped leasehold.
+Seasonality
+Generally, but not always, the demand and price levels for natural gas
+increase during the colder winter months and decrease during the warmer summer
+months. In addition, pipelines, utilities, local distribution companies and
+industrial users utilize natural gas storage facilities and purchase some of
+their anticipated winter requirements during the summer, which can lessen
+seasonal demand fluctuations. Crude oil and the demand for heating oil are also
+impacted with generally higher prices in the winter. Seasonal anomalies such as
+mild winters sometimes lessen these fluctuations.
+Competition
+The oil and gas industry is intensely competitive. This is particularly
+so in the acquisition of prospective oil and natural gas properties and oil and
+gas reserves. We believe that our leasehold position provides the foundation for
+a strong drilling program. Our competitive position also depends on our
+geological, geophysical and engineering expertise, and our financial resources.
+We believe that the location of our leasehold acreage, our exploration, drilling
+and production expertise and the experience and knowledge of our management and
+industry partners enable us to compete effectively in our core operating areas.
+Notwithstanding our talents and assets, we still face stiff competition from a
+substantial number of major and independent oil and gas companies that have
+larger technical staffs and greater financial and operational resources than we
+do. Many of these companies not only engage in the acquisition, exploration,
+development and production of oil and natural gas reserves, but also have
+5
+refining operations, market refined products and generate electricity. We also
+compete with other oil and natural gas companies in attempting to secure
+drilling rigs and other equipment necessary for drilling and completion of
+wells. Consequently, drilling equipment may be in short supply from time to
+time. Currently, access to incremental drilling equipment in certain regions is
+difficult.
+Government Regulations
+Our business is subject to various federal, state and local laws and
+governmental regulations that may be changed from time to time in response to
+economic or political conditions. Matters subject to regulation include
+discharge permits for drilling operations, drilling bonds, reports concerning
+operations, the spacing of wells, unitization and pooling of properties,
+taxation and environmental protection. From time to time, regulatory agencies
+have imposed price controls and limitations on production by restricting the
+rate of flow of oil and gas wells below actual production capacity in order to
+conserve supplies of oil and gas.
+Energy Regulations. Our sales of natural gas are affected by the
+availability, terms and cost of transportation. The price and terms of access to
+pipeline transportation are subject to extensive federal and state regulation.
+From 1985 to the present, several major regulatory changes have been implemented
+by Congress and the Federal Energy Regulatory Commission that affect the
+economics of natural gas production, transportation and sales. In addition, the
+FERC is continually proposing and implementing new rules and regulations
+affecting those segments of the natural gas industry that remain subject to the
+FERC's jurisdiction, most notably interstate natural gas transmission companies.
+These initiatives may also affect the intrastate transportation of gas under
+certain circumstances. The stated purpose of many of these regulatory changes is
+to promote competition among the various sectors of the natural gas industry.
+The ultimate impact of the complex rules and regulations issued by the
+FERC since 1985 cannot be predicted. In addition, many aspects of these
+regulatory developments have not become final but are still pending judicial and
+final FERC decisions. Regulations implemented by the FERC in recent years could
+result in an increase in the cost of transportation service on certain petroleum
+product pipelines. In addition, some of the FERC's more recent proposals may,
+however, adversely affect the availability and reliability of interruptible
+transportation service on interstate pipelines. Additional proposals and
+proceedings that might affect the natural gas industry are pending before
+Congress and the courts. The natural gas industry historically has been very
+heavily regulated, and there is no assurance that the less stringent regulatory
+approach recently pursued by the FERC and Congress will continue. We do not
+believe that we will be affected by any action taken that differs materially
+from other natural gas producers and marketers with whom we compete.
+Certain operations we conduct involve federal minerals that the
+Minerals Management Service administers. The MMS issues leases covering such
+lands through competitive bidding. These leases contain relatively standardized
+terms and require compliance with federal laws and detailed MMS regulations. For
+offshore operations, lessees must obtain MMS approval for exploration plans and
+development and production plans prior to the commencement of such operations.
+In addition to permits required from other agencies such as the Coast Guard, the
+Army Corps of Engineers and the Environmental Protection Agency, lessees must
+obtain a permit from the MMS prior to the commencement of drilling. Lessees must
+also comply with detailed MMS regulations governing, among other things:
+o engineering and construction specifications for offshore
+production facilities;
+o safety procedures;
+6
+o flaring of production;
+o plugging and abandonment of Outer Continental Shelf wells;
+o calculation of royalty payments and the valuation of
+production for this purpose; and
+o removal of facilities.
+To cover the various obligations of lessees on the OCS, the MMS
+generally requires that lessees post substantial bonds or other acceptable
+assurances that such obligations will be met. The cost of such bonds or other
+surety can be substantial, and we may not be able to continue to obtain bonds or
+other surety in all cases. Under certain circumstances the MMS may require our
+operations on federal leases to be suspended or terminated.
+Many of the states in which we conduct our oil and gas drilling and
+production activities regulate such activities by requiring, among other things,
+drilling permits and bonds and reports concerning operations. The laws of these
+states also govern a number of environmental and conservation matters, including
+the handling and disposing of waste material, plugging and abandonment of wells,
+restoration requirements, unitization and pooling of natural gas and oil
+properties and establishment of maximum rates of production from natural gas and
+oil wells. Some states prorate production to the market demand for oil and
+natural gas.
+Our anticipated coalbed methane gas production from the Hanging Woman
+Basin will be similar to our traditional natural gas production as to the
+physical producing facilities and the product produced. However, the subsurface
+mechanisms that allow the gas to move to the wellbore and the producing
+characteristics of coalbed methane wells are very different from traditional
+natural gas production. Unlike conventional gas wells, which require a porous
+and permeable reservoir, hydrocarbon migration and a natural structural and/or
+stratigraphic trap, the coalbed methane gas is trapped in the molecular
+structure of the coal itself until released by pressure changes resulting from
+the removal of in situ water. Frequently, coalbeds are partly or completely
+saturated with water. As the water is removed, internal pressures on the coal
+are decreased, allowing the gas to desorb from the coal and flow to the
+wellbore. Unlike traditional gas wells, new coalbed methane wells often produce
+water for several months and then, as the water production decreases, natural
+gas production increases as the coal seams de-water.
+Coalbed methane gas production in the Hanging Woman Basin requires
+state permits for the use of well-site pits and evaporation ponds for the
+disposal of produced water. Groundwater produced from the coal seams can
+generally be discharged into arroyos, surface waters, well-site pits and
+evaporation ponds without a permit if it does not exceed surface discharge
+permit levels, and meets state and federal primary drinking water standards. All
+of these disposal options require an extensive third-party water sampling and
+laboratory analysis program to ensure compliance with state permit standards.
+Where water of lesser quality is involved or the wells produce water in excess
+of the applicable volumetric permit limits, additional disposal wells would have
+to be drilled to re-inject the produced water back into deep underground rock
+formations.
+Environmental Regulations. Our operations are subject to numerous
+existing federal, state and local laws and regulations governing environmental
+quality and pollution control. These laws and regulations may require that
+permits be obtained before drilling commences, restrict the types, quantities
+and concentration of various substances that can be released into the
+environment in connection with drilling and production activities, and limit or
+prohibit drilling activities on certain lands lying within wilderness, wetlands
+and other protected areas, including areas containing endangered animal species.
+As a result, these laws and regulations may substantially increase the costs of
+7
+exploring, developing or producing oil and gas and may prevent or delay the
+commencement or continuation of a project. In addition, these laws and
+regulations may impose substantial clean-up, remediation and other obligations
+in the event of any discharges or emissions in violation of such laws and
+regulations.
+To date we have not experienced any material adverse effect on our
+financial condition or results of operations from obligations under
+environmental laws and regulations. We believe that we are in substantial
+compliance with currently applicable environmental laws and regulations and that
+continued compliance with existing requirements would not have a material
+adverse impact on us.
+Risk Factors
+In addition to the other information set forth elsewhere in this Form
+10-K, the following factors should be carefully considered when evaluating St.
+Mary.
+Risks Related to Our Business
+Oil and natural gas prices are volatile, and an extended decline in
+prices would hurt our profitability and financial condition.
+Our revenues, operating results, profitability, future rate of growth
+and the carrying value of our oil and gas properties depend heavily on
+prevailing market prices for oil and gas. Any substantial or extended decline in
+the price of oil or gas would have a material adverse effect on us. It could
+reduce our cash flow and borrowing capacity, as well as the value and the amount
+of our oil and gas reserves.
+Historically, the markets for oil and gas have been volatile, and they
+are likely to continue to be volatile. Wide fluctuations in oil and gas prices
+may result from relatively minor changes in the supply of and demand for oil and
+gas, market uncertainty and other factors that are beyond our control,
+including:
+o worldwide and domestic supplies of oil and natural gas;
+o the ability of the members of the Organization of Petroleum
+Exporting Countries to agree to and maintain oil price and
+production controls;
+o political instability or armed conflict in oil or gas
+producing regions;
+o worldwide economic conditions;
+o the availability of transportation facilities;
+o weather conditions; and
+o actions of governmental authorities.
+Declines in oil and gas prices would reduce our revenue and could also
+reduce the amount of oil and gas that we can produce economically and, as a
+result, could have a material adverse effect on us.
+8
+Our future success depends on our ability to replace reserves.
+Our future success depends on our ability to find, develop and acquire
+oil and gas reserves that are economically recoverable. Our properties produce
+at a declining rate over time. In order to maintain current production rates we
+must locate and develop or acquire new oil and gas reserves to replace those
+being depleted by production. We may do this even during periods of low oil and
+gas prices. In addition, competition for producing oil and gas properties is
+intense and many of our competitors have financial and other resources
+substantially greater than those available to us. Therefore, we may not be able
+to acquire oil and gas properties that contain economically recoverable reserves
+or we may not be able to acquire such properties at acceptable prices. Without
+successful exploration or acquisition activities, our reserves, production and
+revenues will decline rapidly.
+Our producing property acquisitions carry significant risks.
+Successful property acquisitions require an assessment of a number of
+factors beyond our control. These factors include recoverable reserves, future
+oil and gas prices, operating costs and potential environmental and other
+liabilities. These assessments are inexact and their accuracy is inherently
+uncertain. A customary review of subject properties will not necessarily reveal
+all existing or potential problems.
+In connection with our acquisitions, we may not be entitled to
+contractual indemnification for pre-closing liabilities, including environmental
+liabilities. Normally, we acquire interests in properties on an "as is" basis
+with limited remedies for breaches of representations and warranties.
+o Additionally, significant acquisitions can change the nature of our operations
+and business depending upon the character of the acquired properties if they
+have substantially different operating and geological characteristics or are in
+different geographic locations than our existing properties. To the extent that
+acquired properties are substantially different than our existing properties,
+our ability to efficiently realize the expected economic benefits of such
+transactions may be limited.
+We may not be able to successfully integrate future property or corporate
+acquisitions.
+Integrating acquired properties and businesses involves a number of
+special risks, including the possibility that management may be distracted from
+normal business concerns by the need to integrate operations and systems and in
+retaining and assimilating additional employees. Therefore, we may not be able
+to realize all of the anticipated benefits of the acquisitions.
+Substantial capital is required to replace and grow reserves.
+We make, and will continue to make, substantial expenditures to find,
+acquire, develop and produce oil and natural gas reserves. Our capital
+expenditures for oil and gas properties were $313 million for 2004, and we have
+budgeted total capital expenditures of $418 million in 2005. If oil and gas
+prices decrease or we encounter operating difficulties that result in our cash
+flow from operations being less than expected, we may have to reduce the capital
+we can spend unless we raise additional funds through debt or equity financing.
+Debt or equity financing, cash generated by operations or borrowing capacity may
+not be available to us in sufficient amounts or on acceptable terms to meet
+these requirements.
+9
+Future cash flows and the availability of financing will be subject to
+a number of variables, such as:
+o our success in locating and producing new reserves;
+o the level of production from existing wells; and
+o prices of oil and natural gas;
+Issuing equity securities to satisfy our financing requirements could
+cause substantial dilution to existing stockholders. Debt financing could lead
+to us being more vulnerable to competitive pressures and economic downturns.
+If our revenues were to decrease due to lower oil and natural gas
+prices, decreased production or other reasons, and if we could not obtain
+capital through our credit facility or otherwise, our ability to execute our
+development plans, replace our reserves or maintain production levels could be
+greatly limited.
+We could incur substantial additional loans, which could negatively impact our
+financial condition, results of operations and business prospects.
+As of December 31, 2004, we had $137 million in outstanding loans,
+including $100 million outstanding under our 5.75% Senior Convertible Notes due
+2022. Our level of debt could have important consequences on our operations,
+including:
+o requiring us to dedicate a substantial portion of our cash
+flow from operations to required payments on debt, thereby
+reducing the availability of cash flow for working capital,
+capital expenditures and other general business activities;
+o limiting our ability to obtain additional financing in the
+future for working capital, capital expenditures and other
+general business activities;
+o limiting our flexibility in planning for, or reacting to,
+changes in our business and the industry in which we operate;
+and
+o detracting from our ability to successfully withstand a
+downturn in our business or the economy generally.
+The occurrence of any one of these events could have a material adverse
+effect on our business, financial condition, results of operations and business
+prospects.
+We may incur additional debt, including secured debt under our credit
+facility or otherwise, in order to make future acquisitions or to develop our
+properties. We may not be able to generate sufficient cash flow to pay the
+interest on additional debt. Future working capital, borrowings or equity
+financing may not be available to pay or refinance such debt.
+In addition, our credit facility borrowing base is subject to periodic
+borrowing base redeterminations. We could be forced to repay a portion of our
+bank borrowings due to a downward redetermination of our borrowing base. We may
+not have sufficient funds to make such repayment. If we do not have sufficient
+funds and are otherwise unable to negotiate renewals of our borrowing or arrange
+new financing, we may have to sell significant assets. Any such sale could have
+a material adverse effect on our business and financial results.
+10
+We may not be able to obtain credit facility borrowing base redeterminations
+that adequately meet our anticipated financing needs.
+Our current long-term credit facility with a group of banks has a
+maximum loan amount of $300 million. The amount actually available from time to
+time depends on a borrowing base that the lenders periodically redetermine based
+on the value of our oil and gas properties and other assets. In October 2004 the
+banks conducted their normal semi-annual borrowing base redetermination that
+resulted in a borrowing base of $325 million. Since we pay commitment fees based
+on the unused portion of the borrowing base, we elected to retain a total loan
+commitment amount under the facility of $150 million to correspond with our
+projected funding requirements. Our next borrowing base redetermination is
+scheduled to occur by the end of April 2005. The banks may not agree to a
+borrowing base redetermination that is adequate for our planned financing
+requirements.
+Our long term credit facility is scheduled to expire in January 2006.
+We anticipate renegotiating the terms of our facility in the first quarter of
+2005 to ensure that we have a credit facility in place beyond the current
+expiry.
+If oil and gas prices decrease or exploration efforts are unsuccessful, we may
+be required to take additional writedowns.
+There is a risk that we will be required to write down the carrying
+value of our oil and gas properties. This could occur when oil and gas prices
+are low or if we have substantial downward adjustments to our estimated proved
+reserves, increases in our estimates of development costs or deterioration in
+our exploration results.
+We follow the successful efforts accounting method. All property
+acquisition costs and costs of exploratory and development wells are capitalized
+when incurred, pending the determination of whether proved reserves have been
+discovered. If proved reserves are not discovered with an exploratory well, the
+costs of drilling the well are expensed. All geological and geophysical costs on
+exploratory prospects and the costs of carrying and retaining unproved
+properties are expensed as incurred.
+The capitalized costs of our oil and gas properties, on a
+field-by-field basis, may not exceed the estimated future net cash flows of that
+field. If capitalized costs exceed future net revenues, we write down the costs
+of each such field to our estimate of fair market value. Unproved properties are
+evaluated at the lower of cost or fair market value. This type of charge will
+not affect our cash flow from operating activities, but it will reduce the book
+value of our stockholders' equity.
+We review the carrying value of our properties quarterly based on
+prices in effect as of the end of each quarter or as of the time of reporting
+our results. Once incurred, a writedown of oil and gas properties is not
+reversible at a later date even if oil or gas prices increase. St. Mary incurred
+impairment and abandonment charges on proved and unproved properties of $1.9
+million, $4.0 million and $2.4 million in 2004, 2003 and 2002, respectively.
+Estimates of oil and gas reserves are not precise.
+This report and other SEC filings by us contain estimates of our proved
+oil and gas reserves and the estimated future net revenues from those reserves.
+Actual results will likely vary from amounts estimated, and any significant
+negative variance could have a material adverse effect on our future results of
+operations.
+11
+Reserve estimates are based on various assumptions, including
+assumptions required by the SEC relating to oil and gas prices, drilling and
+operating expenses, capital expenditures, taxes and availability of funds. The
+process of estimating reserves is complex. This process requires significant
+decisions and assumptions in the evaluation of available geological,
+geophysical, engineering and economic data for each reservoir. These estimates
+are dependent on many variables and therefore changes often occur as these
+variables evolve and commodity prices fluctuate. However, the likelihood of
+recovery of these reserves is considered more likely than not.
+Actual future production, oil and gas prices, revenues, taxes,
+development expenditures, operating expenses and quantities of recoverable oil
+and gas reserves will most likely vary from those estimated. Any significant
+variance could materially affect the estimated quantities and present value of
+reserves disclosed by us. In addition, we may adjust estimates of proved
+reserves to reflect production history, results of exploration and development,
+prevailing oil and gas prices and other factors, many of which are beyond our
+control.
+As of December 31, 2004, approximately 15 percent of our estimated
+proved reserves were proved undeveloped. Estimation of proved undeveloped
+reserves and proved developed non-producing reserves is nearly always based on
+volumetric calculations rather than the performance data used to estimate
+producing reserves. Recovery of proved undeveloped reserves requires significant
+capital expenditures and successful drilling operations. Production revenues
+from proved developed non-producing reserves will not be realized until some
+time in the future. The reserve data assumes that we will make significant
+capital expenditures to develop our reserves. Although we have prepared
+estimates of our reserves and the costs associated with these reserves in
+accordance with industry standards, these estimated costs may not be accurate,
+development may not occur as scheduled and actual results may not occur as
+estimated.
+You should not construe the present value of future net reserves, or
+PV-10, as the current market value of the estimated oil and natural gas reserves
+attributable to our properties. Management has based the estimated discounted
+future net cash flows from proved reserves on prices and costs as of the date of
+the estimate, in accordance with applicable regulations, whereas actual future
+prices and costs may be materially higher or lower. For example, values of our
+reserves as of December 31, 2004, were estimated using a calculated weighted
+average sales price of $43.45 per barrel of oil (NYMEX) and $6.18 per Mcf of gas
+(Gulf Coast spot price). During 2004 our monthly average realized gas prices,
+excluding the effect of hedging, were as high as $7.27 per Mcf and as low as
+$4.90 per Mcf. For the same period our monthly average realized oil prices were
+as high as $51.21 per Bbl and as low as $32.26 per Bbl. Many factors will affect
+actual future net cash flows, including:
+o the amount and timing of actual production,
+o supply and demand for oil and natural gas,
+o curtailments or increases in consumption by oil and natural
+gas purchasers, and
+o changes in governmental regulations or taxation.
+The timing of the production of oil and natural gas properties and of
+the related expenses affects the timing of actual future net cash flows from
+proved reserves and thus their actual present value. In addition, the 10 percent
+discount factor, which we are required to use to calculate PV-10 for reporting
+purposes, is not necessarily the most appropriate discount factor given actual
+interest rates and risks to which our business or the oil and natural gas
+12
+industry in general are subject. As a result, our actual future net cash flows
+could be materially different from the estimates included in this report.
+Our industry is highly competitive.
+Major oil companies, independent producers, and institutional and
+individual investors are actively seeking oil and gas properties throughout the
+world, along with the equipment, labor and materials required to operate
+properties. Shortages for equipment, labor or materials may result in increased
+costs or the inability to obtain such resources as needed. Many of our
+competitors have financial and technological resources vastly exceeding those
+available to us. Many oil and gas properties are sold in a competitive bidding
+process in which we may lack technological information or expertise available to
+other bidders. We may not be successful in acquiring and developing profitable
+properties in the face of this competition.
+Exploration and development drilling may not result in commercially productive
+reserves.
+Oil and gas drilling and production activities are subject to numerous
+risks, including the risk that no commercially productive oil or natural gas
+will be found. The cost of drilling and completing wells is often uncertain, and
+oil and gas drilling and production activities may be shortened, delayed or
+canceled as a result of a variety of factors, many of which are beyond our
+control. These factors include:
+o unexpected drilling conditions;
+o pressure or irregularities in formations;
+o equipment failures or accidents; and
+o shortages or delays in the availability of drilling rigs and
+the delivery of equipment.
+The prevailing prices of oil and gas also affect the cost of and the
+demand for drilling rigs, production equipment and related services. The
+availability of drilling rigs can vary significantly from region to region at
+any particular time. Although land drilling rigs can be moved from one region to
+another in response to changes in levels of demand, an undersupply of rigs in
+any region may result in drilling delays and higher drilling costs for the rigs
+that are available in that region.
+Another significant risk inherent in our drilling plans is the need to
+obtain drilling permits from state, local and other governmental authorities.
+Delays in obtaining regulatory approvals and drilling permits, including delays
+which jeopardize our ability to realize the potential benefits from leased
+properties within the applicable lease periods, the failure to obtain a drilling
+permit for a well or the receipt of a permit with unreasonable conditions or
+costs could have a material adverse effect on our ability to explore on or
+develop our properties.
+The wells we drill may not be productive and we may not recover all or
+any portion of our investment in such wells. The seismic data and other
+technologies we use do not allow us to know conclusively prior to drilling a
+well that oil or gas is present or may be produced economically. The cost of
+drilling, completing and operating a well is often uncertain, and cost factors
+can adversely affect the economics of a project. Drilling activities can result
+in dry wells or wells that are productive but do not produce sufficient net
+revenues after operating and other costs to cover initial drilling costs.
+13
+Our future drilling activities may not be successful, nor can we be
+sure that our overall drilling success rate or our drilling success rate for
+activity within a particular area will not decline. Unsuccessful drilling
+activities could have a material adverse effect on our results of operations and
+financial condition. Also, we may not be able to obtain any options or lease
+rights in potential drilling locations that we identify. Although we have
+identified numerous potential drilling locations, we may not be able to
+economically produce oil or natural gas from all of them.
+Our business is subject to operating and environmental risks and hazards that
+could result in substantial losses.
+Oil and gas operations are subject to many risks, including well
+blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
+well fluids, fires, formations with abnormal pressures, pipeline ruptures or
+spills, pollution, releases of toxic gas and other environmental risks and
+hazards. If any of these types of events occurs, we could sustain substantial
+losses.
+Under certain limited circumstances we may be liable for environmental
+damage caused by previous owners or operators of properties that we own, lease
+or operate. As a result, we may incur substantial liabilities to third parties
+or governmental entities, which could reduce or eliminate funds available for
+exploration, development or acquisitions or cause us to incur losses.
+We maintain insurance against some, but not all, of these potential
+risks and losses. We have limited coverage for sudden environmental damages. We
+do not believe that insurance coverage for the full potential liability that
+could be caused by sudden environmental damages or insurance coverage for
+environmental damage that occurs over time is available at a reasonable cost. In
+addition, pollution and environmental risks generally are not fully insurable.
+Further, we may elect not to obtain other insurance coverage under circumstances
+where we believe that the cost of available insurance is excessive relative to
+the risks presented. Accordingly, we may be subject to liability or may lose
+substantial portions of certain properties in the event of environmental or
+other damages. If a significant accident or other event occurs and is not fully
+covered by insurance, it could have a material adverse effect on our financial
+condition and results of operations.
+Hedging transactions may limit our potential gains and involve other risks.
+To manage our exposure to price risks in the marketing of our oil and
+natural gas, we enter into commodity price risk management arrangements from
+time to time with respect to a portion of our current or future production.
+While intended to reduce the effects of volatile oil and natural gas prices,
+these transactions may limit our potential gains if oil or natural gas prices
+were to rise substantially over the price established by the hedge. In addition,
+such transactions may expose us to the risk of financial loss in certain
+circumstances, including instances in which:
+o our production is less than expected;
+o the counterparties to our futures contracts fail to perform
+under the contracts; or
+o a sudden, unexpected event materially impacts oil or natural
+gas prices.
+The terms of our hedging agreements may also require that we furnish
+cash collateral, letters of credit or other forms of performance assurance in
+the event that mark-to-market calculations result in settlement obligations by
+us to the counterparties, which would encumber our liquidity and capital
+resources.
+14
+In addition, hedging transactions using derivative instruments involve
+basis risk. Basis risk in a hedging contract occurs when the index upon which
+the contract is based is more or less variable than the index upon which the
+hedged asset is based, thereby making the hedge less effective. For example, a
+NYMEX index used for hedging certain volumes of production may have more or less
+variability than the regional price index used for the sale of that production.
+Our industry is heavily regulated.
+Federal, state and local authorities extensively regulate the oil and
+gas industry. Legislation and regulations affecting the industry are under
+constant review for amendment or expansion, raising the possibility of changes
+that may affect, among other things, the pricing or marketing of oil and gas
+production. Noncompliance with statutes and regulations may lead to substantial
+penalties, and the overall regulatory burden on the industry increases the cost
+of doing business and, in turn, decreases profitability. These authorities
+regulate various aspects of oil and gas drilling and production activities,
+including the drilling of wells (through permit and bonding requirements), the
+spacing of wells, the unitization or pooling of oil and gas properties,
+environmental matters, safety standards, the sharing of markets, production
+limitations, plugging and abandonment, and restoration. To cover the various
+obligations of leaseholders in federal waters, federal authorities generally
+require that leaseholders have substantial net worth or post bonds or other
+acceptable assurances that such obligations will be met. The cost of these bonds
+or other surety can be substantial, and we may not be able to obtain bonds or
+other surety in all cases. Under limited circumstances, federal authorities may
+require any of our operations on federal leases to be suspended or terminated.
+Any such suspension or termination could materially adversely affect our
+financial condition and results of operations.
+We must comply with complex environmental regulations.
+Our operations are subject to complex and constantly changing
+environmental laws and regulations adopted by federal, state and local
+governmental authorities where we are engaged in exploration or production
+operations. New laws or regulations, or changes to current requirements, could
+have a material adverse effect on our business. We will continue to be subject
+to uncertainty associated with new regulatory interpretations and inconsistent
+interpretations between state and federal agencies. We could face significant
+liabilities to the government and third parties for discharges of oil, natural
+gas or other pollutants into the air, soil or water, and we could have to spend
+substantial amounts on investigations, litigation and remediation. Existing
+environmental laws or regulations, as currently interpreted or enforced, or as
+they may be interpreted, enforced or altered in the future, may have a material
+adverse effect on our results of operations and financial condition. As a
+result, we may face material claims with respect to properties we own or have
+owned.
+Our business depends on transportation facilities owned by others.
+The marketability of our oil and gas production depends in part on the
+availability, proximity and capacity of pipeline systems owned by third parties.
+The unavailability of or lack of available capacity on these systems and
+facilities could result in the shutting-in of producing wells or the delay or
+discontinuance of development plans for properties. Although we have some
+contractual control over the transportation of our product, material changes in
+these business relationships could materially affect our operations. Federal and
+state regulation of oil and gas production and transportation, tax and energy
+policies, changes in supply and demand, pipeline pressures, damage to or
+destruction of pipelines and general economic conditions could adversely affect
+our ability to produce, gather and transport oil and natural gas.
+15
+We depend on key personnel.
+Our success will continue to depend on the continued services of our
+executive officers and a limited number of other senior management and technical
+personnel with extensive experience and expertise in evaluating and analyzing
+producing oil and gas properties and drilling prospects, maximizing production
+from oil and gas properties and marketing oil and gas production. Loss of the
+services of any of these people could have a material adverse effect on our
+operations.
+Ownership of working interests, royalty interests and other interests by a
+director and some of our officers may create conflicts of interest.
+As a result of their prior employment with another company with which
+St. Mary engaged in a number of transactions, Ronald D. Boone, a director of St.
+Mary, and two vice presidents of St. Mary own royalty interests in a number of
+St. Mary's properties, which were earned as part of the prior employer's
+employee benefit programs. Those persons have no royalty participation in any
+St. Mary properties acquired or developed subsequent to the beginning of their
+employment with St. Mary.
+Mr. Boone also owns 25 percent of Princeton Resources LLC, which owns
+the oil and gas working interests that he acquired as a result of his prior
+employment. Although Mr. Boone does not manage this entity, he may participate
+in any investment decisions made by it.
+As a result of these transactions and relationships, conflicts of
+interest may exist between these persons and us. Although these persons owe
+fiduciary duties to our stockholders and to us, conflicts of interest may not
+always be resolved in our favor.
+Risks Related to Our Common Stock
+The price of our common stock may fluctuate significantly, which may result in
+losses for investors.
+From January 1, 2003, to February 15, 2005, the last daily sale price
+of our common stock reported by the New York Stock Exchange ranged from a low of
+$23.83 per share to a high of $49.47 per share. We expect our stock to continue
+to be subject to fluctuations as a result of a variety of factors, including
+factors beyond our control. These include:
+o changes in oil and natural gas prices;
+o variations in quarterly drilling, recompletions, acquisitions
+and operating results;
+o changes in financial estimates by securities analysts;
+o changes in market valuations of comparable companies;
+o additions or departures of key personnel; and
+o future sales of our common stock.
+We may fail to meet expectations of our stockholders or of securities
+analysts at some time in the future, and our stock price could decline as a
+result.
+Our certificate of incorporation and bylaws have provisions that discourage
+corporate takeovers and could prevent shareholders from realizing a premium on
+their investment.
+16
+Our certificate of incorporation and bylaws contain provisions that may
+have the effect of delaying or preventing a change of control. These provisions,
+among other things, provide for non-cumulative voting in the election of the
+Board of Directors and impose procedural requirements on stockholders who wish
+to make nominations for the election of Directors or propose other actions at
+stockholders' meetings. These provisions, alone or in combination with each
+other and with the rights plan described below, may discourage transactions
+involving actual or potential changes of control, including transactions that
+otherwise could involve payment of a premium over prevailing market prices to
+shareholders for their common stock.
+Under our stockholder rights plan, if the Board of Directors determines
+that the terms of a potential acquisition do not reflect the long-term value of
+St. Mary, the Board of Directors could allow the holder of each outstanding
+share of our common stock other than those held by the potential acquirer to
+purchase one additional share of our common stock with a market value of twice
+the exercise price. This prospective dilution to a potential acquirer would make
+the acquisition impracticable unless the terms were improved to the satisfaction
+of the Board of Directors. The existence of the plan may impede a takeover not
+supported by our board even though such takeover may be desired by a majority of
+our stockholders or may involve a premium over the prevailing stock price.
+Our shares that are eligible for future sale may have an adverse effect on the
+price of our common stock.
+At February 15, 2005, we had 28,548,362 shares of common stock
+outstanding. Of the shares outstanding, approximately 28,234,000 shares were
+freely tradable without substantial restriction or the requirement of future
+registration under the Securities Act. Also as of that date, options to purchase
+2,756,436 shares of our common stock were outstanding, of which 2,152,871 were
+exercisable. These options are exercisable at prices ranging from $9.25 to
+$41.74 per share. In addition, restricted stock units providing for the issuance
+of up to a total of 227,831 shares of our common stock were outstanding. Sales
+of substantial amounts of common stock, or a perception that such sales could
+occur, and the existence of options or restricted stock units to issue shares of
+common stock at prices that may be below the then-current market price of the
+common stock could adversely affect the market price of the common stock and
+could impair our ability to raise capital through the sale of our equity
+securities.
+A director and his extended family may be able to control us.
+Thomas E. Congdon, a director and our former Chairman of the Board, and
+members of his extended family owned greater than 10 percent of the outstanding
+shares of our common stock as of February 15, 2005. While no formal arrangements
+exist, these extended family members could be inclined to act in concert with
+Mr. Congdon on matters related to control of St. Mary, including for example the
+election of Directors or response to an unsolicited bid to acquire St. Mary.
+Accordingly, Mr. Congdon and his family may be able to control or influence
+matters presented to our Board of Directors and stockholders.
+We may not always pay dividends on our common stock.
+The payment of future dividends remains in the discretion of the Board
+of Directors and will continue to depend on our earnings, capital requirements,
+financial condition and other factors. In addition, the payment of dividends is
+subject to covenants in our credit facility, including the requirement that we
+maintain certain levels of stockholder's equity. The Board of Directors may
+determine in the future to reduce the current annual dividend rate of $0.10 per
+17
+share or discontinue the payment of dividends altogether. Our credit facility
+limits the annual dividend rate that we may pay to $0.20 per share.
+Cautionary Statement about Forward-Looking Statements
+This Annual Report on Form 10-K includes certain statements that may be
+deemed to be "forward-looking statements" within the meaning of Section 27A of
+the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
+1934. All statements, other than statements of historical facts, included in
+this Form 10-K that address activities, events or developments that St. Mary's
+management expects, believes or anticipates will or may occur in the future are
+forward looking statements. Examples of forward-looking statements may include
+discussion of such matters as:
+o The amount and nature of future capital, development and
+exploration expenditures;
+o The drilling of wells;
+o Reserve estimates and the estimates of both future net
+revenues and the present value of future net revenues that are
+included in their calculation;
+o Future oil and gas production estimates;
+o Repayment of debt;
+o Business strategies;
+o Expansion and growth of operations; and
+o Other similar matters such as those discussed in Management's
+Discussion and Analysis of Financial Condition and Results of
+Operations.
+These statements are based on certain assumptions and analyses made by us in
+light of our experience and our perception of historical trends, current
+conditions, expected future developments and other factors we believe are
+appropriate in the circumstances. Such statements are subject to a number of
+assumptions, risks and uncertainties, including such factors as the volatility
+and level of oil and natural gas prices, uncertainties in cash flow, the
+uncertain nature of the expected benefits from the acquisition of oil and gas
+properties, production rates and reserve replacement, the imprecise nature of
+oil and gas reserve estimates, drilling and operating service availability,
+unexpected drilling conditions and results, the risks of various exploration
+strategies, competition, the availability of economically attractive exploration
+and development and property acquisition opportunities and any necessary
+financing, litigation, environmental matters, the potential impact of government
+regulations, and other matters discussed under the caption "Risk Factors", many
+of which are beyond our control. Readers are cautioned that forward-looking
+statements are not guarantees of future performance and that actual results or
+developments may differ materially from those expressed or implied in the
+forward-looking statements.
+Available Information
+Our Internet website address is www.stmaryland.com. Through our
+------------------
+website's financial information section we make available free of charge our
+annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on
+Form 8-K, and amendments to those reports filed with or furnished to the SEC
+under applicable securities laws. These materials are made available as soon as
+reasonably practical after we electronically file such material with, or furnish
+it to, the SEC.
+18
+We also make available through our website's corporate governance
+section our corporate governance guidelines, code of business conduct and
+ethics, and the charters for our Board of Directors' audit committee,
+compensation committee, executive committee and nominating and corporate
+governance committee. These documents are also available in print to any
+stockholder who requests them. Requests for these documents may be submitted to:
+St. Mary Land & Exploration Company
+Investor Relations
+1776 Lincoln Street, Suite 700
+Denver, Colorado 80203
+Telephone: (303) 863-4322
+Information on our website is not incorporated by reference into this
+Annual Report on Form 10-K and should not be considered part of this document.
+Glossary
+The terms defined in this section are used throughout this Annual
+Report on Form 10-K.
+2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a
+two-dimensional cross-section of the subsurface.
+3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a
+three-dimensional picture of the subsurface.
+Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
+reference to oil or other liquid hydrocarbons.
+Bcf. Billion cubic feet, used herein in reference to natural gas.
+BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using
+the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
+Behind pipe reserves. Estimated net proved reserves in a formation in which
+production casing has already been set in the wellbore but has not been
+perforated and production tested.
+BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio
+of six Mcf of gas (including gas liquids) to one Bbl of oil.
+Development well. A well drilled within the proved area of an oil or gas
+reservoir to the depth of a stratigraphic horizon known to be productive in an
+attempt to recover proved undeveloped reserves.
+Dry hole. A well found to be incapable of producing either oil or gas in
+sufficient quantities to justify completion as an oil or gas well.
+Estimated net proved reserves. The estimated quantities of oil, gas and gas
+liquids which geological and engineering data demonstrate with reasonable
+certainty to be recoverable in future years from known reservoirs under existing
+economic and operating conditions.
+Exploratory well. A well drilled to find and produce oil or gas in an unproved
+area, to find a new reservoir in a field previously found to be productive of
+oil or gas in another reservoir or to extend a known reservoir beyond its known
+horizon.
+19
+Fee land. The most extensive interest that can be owned in land, including
+surface and mineral (including oil and gas) rights.
+Finding cost. Expressed in dollars per BOE or MCFE. Finding costs are calculated
+by dividing the amount of total capital expenditures for oil and gas activities,
+including the effect of asset retirement obligations, by the amount of estimated
+net proved reserves added through revisions of previous estimates, discoveries
+and purchases during the same period. The information for this calculation will
+be found in the disclosures about oil and gas producing activities in Item 15 of
\ No newline at end of file
diff --git a/raw/filings/0000893538/2004/0000893538-05-000026/item13.txt b/raw/filings/0000893538/2004/0000893538-05-000026/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..f1cbaf3ae5d3ade315abd2e852c4a992b63b76be
--- /dev/null
+++ b/raw/filings/0000893538/2004/0000893538-05-000026/item13.txt
@@ -0,0 +1,5 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+The information required by this Item is incorporated by reference to
+the information provided under the caption "Certain Relationships and Related
+Transactions" in St. Mary's definitive proxy statement for the 2005 annual
+meeting of stockholders to be filed within 120 days from December 31, 2004.
\ No newline at end of file
diff --git a/raw/filings/0000893538/2004/0000893538-05-000026/item9a.txt b/raw/filings/0000893538/2004/0000893538-05-000026/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..bd7b5a6a635f47d2e82bcbf035968e5e716e8417
--- /dev/null
+++ b/raw/filings/0000893538/2004/0000893538-05-000026/item9a.txt
@@ -0,0 +1,131 @@
+ITEM 9A. CONTROLS AND PROCEDURES
+We maintain a system of disclosure controls and procedures that are
+designed to ensure that information required to be disclosed in our SEC reports
+is recorded, processed, summarized and reported within the time periods
+specified in the SEC's rules and forms, and to ensure that such information is
+accumulated and communicated to our management, including the Chief Executive
+Officer and the Vice-President - Finance, as appropriate to allow timely
+decisions regarding required disclosure.
+We carried out an evaluation, under the supervision and with the
+participation of our management, including the Chief Executive Officer and the
+Vice-President - Finance, of the effectiveness of the design and operation of
+our disclosure controls and procedures as of the end of the period covered by
+this Annual Report on Form 10-K. Based upon that evaluation, the Chief Executive
+Officer and the Vice-President - Finance concluded that our disclosure controls
+and procedures are effective for the purposes discussed above as of the end of
+the period covered by this Annual Report on Form 10-K. There was no significant
+change in our internal control over financial reporting that occurred during our
+most recent fiscal quarter that has materially affected, or is reasonably likely
+to materially affect, our internal control over financial reporting.
+MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
+To the Stockholders' of St. Mary Land & Exploration Company
+Management of the Company is responsible for establishing and maintaining
+adequate internal control over financial reporting as defined in Rules 13a-15(f)
+and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The
+Company's internal control over financial reporting is designed to provide
+reasonable assurance regarding the reliability of financial reporting and the
+preparation of financial statements for external purposes in accordance with
+generally accepted accounting principles. The Company's internal control over
+financial reporting includes those policies and procedures that:
+(i) pertain to the maintenance of records that, in reasonable detail,
+accurately and fairly reflect the transactions and dispositions of the
+assets of the Company;
+(ii) provide reasonable assurance that transactions are recorded as
+necessary to permit preparation of financial statements in accordance
+with generally accepted accounting principles, and that receipts and
+58
+expenditures of the Company are being made only in accordance with
+authorizations of management and directors of the Company; and
+(iii) provide reasonable assurance regarding prevention or timely detection
+of unauthorized acquisition, use or disposition of the Company's
+assets that could have a material effect on the financial statements.
+Because of the inherent limitations, internal control over financial
+reporting may not prevent or detect misstatements. Also, projections of any
+evaluation of effectiveness to future periods are subject to the risk that
+controls may become inadequate because of changes in conditions, or that the
+degree of compliance with the policies or procedures may deteriorate.
+Management assessed the effectiveness of the Company's internal control
+over financial reporting as of December 31, 2004. In making this assessment,
+management used the criteria set forth by the Committee of Sponsoring
+Organizations of the Treadway Commission in Internal Control-Integrated
+Framework.
+Based on our assessment and those criteria, management believes that the
+Company maintained effective internal control over financial reporting as of
+December 31, 2004.
+The Company's independent auditors have issued an attestation report on
+management's assessment of the Company's internal controls over financial
+reporting. That report immediately follows this report.
+/S/ MARK A. HELLERSTEIN /S/ DAVID W. HONEYFIELD
+----------------------- -----------------------
+Mark A. Hellerstein David W. Honeyfield
+Chairman, CEO and President Vice President-Finance, Secretary &
+February 23, 2005 Treasurer
+February 23, 2005
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
+To the Board of Directors and Stockholders of
+St. Mary Land & Exploration Company and Subsidiaries
+We have audited management's assessment, included in the accompanying
+Management's Report on Internal Control over Financial Reporting, that St. Mary
+Land & Exploration Company and subsidiaries (the "Company") maintained
+effective internal control over financial reporting as of December 31, 2004,
+based on criteria established in Internal Control--Integrated Framework issued
+by the Committee of Sponsoring Organizations of the Treadway Commission. The
+Company's management is responsible for maintaining effective internal control
+over financial reporting and for its assessment of the effectiveness of internal
+control over financial reporting. Our responsibility is to express an opinion on
+management's assessment and an opinion on the effectiveness of the Company's
+internal control over financial reporting based on our audit.
+We conducted our audit in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). Those standards require that we plan
+and perform the audit to obtain reasonable assurance about whether effective
+internal control over financial reporting was maintained in all material
+respects. Our audit included obtaining an understanding of internal control over
+59
+financial reporting, evaluating management's assessment, testing and evaluating
+the design and operating effectiveness of internal control, and performing such
+other procedures as we considered necessary in the circumstances. We believe
+that our audit provides a reasonable basis for our opinions.
+A company's internal control over financial reporting is a process designed by,
+or under the supervision of, the company's principal executive and principal
+financial officers, or persons performing similar functions, and effected by the
+company's board of directors, management, and other personnel to provide
+reasonable assurance regarding the reliability of financial reporting and the
+preparation of financial statements for external purposes in accordance with
+generally accepted accounting principles. A company's internal control over
+financial reporting includes those policies and procedures that (1) pertain to
+the maintenance of records that, in reasonable detail, accurately and fairly
+reflect the transactions and dispositions of the assets of the company; (2)
+provide reasonable assurance that transactions are recorded as necessary to
+permit preparation of financial statements in accordance with generally accepted
+accounting principles, and that receipts and expenditures of the company are
+being made only in accordance with authorizations of management and directors of
+the company; and (3) provide reasonable assurance regarding prevention or timely
+detection of unauthorized acquisition, use, or disposition of the company's
+assets that could have a material effect on the financial statements.
+Because of the inherent limitations of internal control over financial
+reporting, including the possibility of collusion or improper management
+override of controls, material misstatements due to error or fraud may not be
+prevented or detected on a timely basis. Also, projections of any evaluation of
+the effectiveness of the internal control over financial reporting to future
+periods are subject to the risk that the controls may become inadequate because
+of changes in conditions, or that the degree of compliance with the policies or
+procedures may deteriorate.
+In our opinion, management's assessment that the Company maintained effective
+internal control over financial reporting as of December 31, 2004, is fairly
+stated, in all material respects, based on the criteria established in Internal
+Control--Integrated Framework issued by the Committee of Sponsoring
+Organizations of the Treadway Commission. Also in our opinion, the Company
+maintained, in all material respects, effective internal control over financial
+reporting as of December 31, 2004, based on the criteria established in Internal
+Control--Integrated Framework issued by the Committee of Sponsoring
+Organizations of the Treadway Commission.
+We have also audited, in accordance with the standards of the Public Company
+Accounting Oversight Board (United States), the consolidated financial
+statements as of and for the year ended December 31, 2004, of the Company, and
+our report dated February 23, 2005, expressed an unqualified opinion on those
+financial statements.
+/S/ DELOITTE & TOUCHE LLP
+Denver, Colorado
+February 23, 2005
+60
+PART III
\ No newline at end of file
diff --git a/raw/filings/0000893538/2004/0000893538-05-000026/rp_note.txt b/raw/filings/0000893538/2004/0000893538-05-000026/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2004/0000893538-05-000026/rpt_disclosure.txt b/raw/filings/0000893538/2004/0000893538-05-000026/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..90ec2edcb79ac58e6202bc080bf485fcdd834a37
--- /dev/null
+++ b/raw/filings/0000893538/2004/0000893538-05-000026/rpt_disclosure.txt
@@ -0,0 +1,19 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+Set forth below is a description of transactions entered into between St. Mary and certain of its officers and directors during the last fiscal year. Some of
+these transactions will continue in effect and may result in conflicts of interest between St. Mary and these individuals. Although these persons owe 
+18 
+fiduciary
+duties to St. Mary and its stockholders, we cannot assure you that conflicts of interest will always be resolved in favor of St. Mary. 
+As
+a result of their prior employment with another company with which St. Mary engaged in a number of transactions, Ronald D. Boone, a director of St. Mary, and two vice presidents of
+St. Mary own royalty interests in certain of St. Mary's properties, which were earned as part of the prior employer's employee benefit programs. One vice president also owns certain working interests
+through participation in acquisitions made by his former employer. Those persons have no royalty participation or working interest in any new St. Mary properties. 
+Mr. Boone
+also owns 25% of Princeton Energy LLC, which owns the oil and gas working interests that he acquired as a result of his prior employment. Although Mr. Boone does
+not manage this entity, he may participate in any investment decisions made by them. 
+St.
+Mary's Bylaws provide that no director, officer or employee may pursue for his or her own account a business or investment opportunity if he or she has obtained knowledge of such
+opportunity through his or her affiliation with the Company. In addition, no officer or employee of St. Mary may pursue for his or her own account an oil and gas opportunity as to which his or her
+knowledge of the opportunity was not obtained through his or her affiliation with the Company unless (a) with respect to an officer of St. Mary, the officer's pursuit of the opportunity has
+been approved by the Board of Directors and (b) with respect to a non-officer of St. Mary, the employee's pursuit of the opportunity has been approved by a senior officer of St.
+Mary with full knowledge of such opportunity. These restrictions do not apply to the acquisition of less than one percent of the publicly traded stock of another company.
\ No newline at end of file
diff --git a/raw/filings/0000893538/2005/0001144204-06-007665/filing.txt b/raw/filings/0000893538/2005/0001144204-06-007665/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..1accf7c66d5275d593b10c44b94931b318846e13
--- /dev/null
+++ b/raw/filings/0000893538/2005/0001144204-06-007665/filing.txt
@@ -0,0 +1,12784 @@
+10-K
+1
+v036350_10k.htm
+Unassociated Document
+UNITED
+STATES 
+SECURITIES
+AND EXCHANGE COMMISSION 
+Washington,
+D.C. 20549 
+FORM
+10-K 
+x 
+Annual
+Report Pursuant to Section 13 or 15(d) of the Securities Exchange
+Act of
+1934 
+For
+the fiscal year ended December 31,
+2005 
+or 
+o 
+Transition
+Report Pursuant to Section 13 or 15(d) of the Securities Exchange
+Act of
+1934 
+Commission
+file number 001-31539 
+ST. MARY
+LAND & EXPLORATION COMPANY 
+(Exact
+name of registrant as specified in its charter) 
+Delaware 
+41-0518430 
+(State
+or other jurisdiction 
+(I.R.S.
+Employer Identification No.) 
+of
+incorporation or organization) 
+1776
+Lincoln Street, Suite 700, Denver, Colorado 80203 
+(Address
+of principal executive offices) (Zip Code) 
+(303)
+861-8140 
+(Registrant's
+telephone number, including area code) 
+Securities
+registered pursuant to Section 12(b) of the Act: 
+Title
+of each class 
+Name
+of each exchange on which registered 
+Common
+Stock, $.01 par value 
+New
+York Stock Exchange 
+Securities
+registered pursuant to Section 12(g) of the Act: None 
+Indicate
+by check mark if the registrant is a well-known seasoned issuer, as defined
+in
+Rule 405 of the Securities Act. Yes x 
+No o 
+Indicate
+by check mark if the registrant is not required to file reports pursuant to
+Section 13 or Section 15(d) of the Act. Yes o No
+x 
+Indicate
+by check mark whether the registrant (1) has filed all reports required to
+be
+filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
+the
+preceding 12 months (or for such shorter period that the registrant was required
+to file such reports), and (2) has been subject to such filing requirements
+for
+the past 90 days. Yes x 
+No o 
+Indicate
+by check mark if disclosure of delinquent filers pursuant to Item 405 of
+Regulation S-K is not contained herein, and will not be contained, to the best
+of registrant’s knowledge, in definitive proxy or information statements
+incorporated by reference in Part III of this Form 10-K or any amendment to
+this
+Form 10-K. o 
+Indicate
+by check mark whether the registrant is a large accelerated filer, an
+accelerated filer, or a non-accelerated filer. See definition of “accelerated
+filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check
+one): 
+Large
+accelerated filer x 
+Accelerated
+filer o 
+Non-accelerated
+filer o 
+Indicate
+by check mark whether the registrant is a shell company (as defined by Rule
+12b-2 of the Exchange Act). Yes o No x 
+The
+aggregate market value of 55,026,022 shares of voting stock held by
+non-affiliates of the registrant, based upon the closing sale price of the
+common stock on June 30, 2005, the last business day of the registrant’s most
+recently completed second fiscal quarter, of $28.98 per share as reported on
+the
+New York Stock Exchange was $1,594,654,118. Shares of common stock held by
+each
+director and executive officer and by each person who owns 10 percent or more
+of
+the outstanding common stock or who is otherwise believed by the Company to
+be
+in a control position have been excluded. This determination of affiliate status
+is not necessarily a conclusive determination for other purposes. 
+As
+of
+February 15, 2006, the registrant had 56,953,893 shares of common stock
+outstanding, net of 250,000 treasury shares held by the Company. 
+DOCUMENTS
+INCORPORATED BY REFERENCE 
+Certain
+information required by Items 10, 11, 12, 13 and 14 of Part III is incorporated
+by reference from portions of the registrant's definitive proxy statement
+relating to its 2006 annual meeting of stockholders to be filed within 120
+days
+after December 31, 2005. 
+TABLE
+OF CONTENTS 
+ITEM 
+PAGE 
+PART
+I 
+ITEM
+1. 
+BUSINESS 
+1 
+Background
+and Strategy 
+1 
+Significant
+Developments since December 31, 2004 
+3 
+Major
+Customers 
+4 
+Employees
+and Office Space 
+4 
+Title
+to Properties 
+4 
+Seasonality 
+5 
+Competition 
+5 
+Government
+Regulations 
+5 
+Cautionary
+Information about Forward-Looking Statements 
+7 
+Available
+Information 
+8 
+Glossary 
+9 
+ITEM
+1A. 
+RISK
+FACTORS 
+11 
+ITEM
+1B. 
+UNRESOLVED
+STAFF COMMENTS 
+19 
+ITEM
+2. 
+PROPERTIES 
+20 
+Operations 
+20 
+Acquisitions
+and Divestitures 
+23 
+Reserves 
+24 
+Production 
+25 
+Productive
+Wells 
+25 
+Drilling
+Activity 
+26 
+Acreage 
+27 
+ITEM
+3. 
+LEGAL
+PROCEEDINGS 
+28 
+ITEM
+4. 
+SUBMISSION
+OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+28 
+ITEM
+4A. 
+EXECUTIVE
+OFFICERS OF THE REGISTRANT 
+28 
+PART
+II 
+ITEM
+5. 
+MMARKET
+FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
+PURCHASES OF EQUITY SECURITIES 
+29 
+ITEM
+6. 
+SELECTED
+FINANCIAL DATA 
+32 
+i 
+TABLE
+OF
+CONTENTS 
+(Continued) 
+ITEM 
+PAGE 
+ITEM
+7. 
+MANAGEMENT'S
+DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
+OPERATIONS 
+34 
+Overview
+of the Company 
+34 
+Overview
+of Liquidity and Capital Resources 
+41 
+Critical
+Accounting Policies and Estimates 
+51 
+Additional
+Comparative Data in Tabular Format 
+55 
+Comparison
+of Financial Results and Trends Between 2005 and 2004 
+56 
+Comparison
+of Financial Results and Trends Between 2004 and 2003 
+58 
+Other
+Liquidity and Capital Resource Information 
+60 
+Accounting
+Matters 
+60 
+Environmental 
+60 
+ITEM
+7A. 
+QUANTITATIVE
+AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (included with the
+content
+of ITEM 7) 
+60 
+ITEM
+8. 
+FINANCIAL
+STATEMENTS AND SUPPLEMENTARY DATA 
+60 
+ITEM
+9. 
+CHANGES
+IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
+DISCLOSURE 
+61 
+ITEM
+9A. 
+CONTROLS
+AND PROCEDURES 
+61 
+ITEM
+9B. 
+OTHER
+INFORMATION 
+63 
+PART
+III 
+ITEM
+10. 
+DIRECTORS
+AND EXECUTIVE OFFICERS OF THE REGISTRANT 
+63 
+ITEM
+11. 
+EXECUTIVE
+COMPENSATION 
+63 
+ITEM
+12. 
+SECURITY
+OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
+STOCKHOLDER MATTERS 
+64 
+ITEM
+13. 
+CERTAIN
+RELATIONSHIPS AND RELATED TRANSACTIONS 
+64 
+ITEM
+14. 
+PRINCIPAL
+ACCOUNTANT FEES AND SERVICES 
+64 
+PART
+IV 
+ITEM
+15. 
+EXHIBITS,
+FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K 
+65 
+ii 
+PART
+I 
+When
+we
+use the terms “St. Mary,” “the Company,” “we,” “us” or “our,” we are
+referring to St. Mary Land & Exploration Company and its subsidiaries,
+unless the context otherwise requires. We have included technical terms
+important to an understanding of our business under “Glossary”. Throughout this
+document we make statements that are classified as “forward-looking”. Please
+refer to the “Cautionary Information about Forward-Looking Statements” section
+of this document for an explanation of these types of statements. 
+ITEM
+1. BUSINESS 
+Background
+and Strategy 
+We
+are an
+independent oil and gas company engaged in the exploration, exploitation,
+development, acquisition and production of natural gas and crude oil. We were
+founded in 1908 and incorporated in Delaware in 1915. Our principal offices
+are
+located at 1776 Lincoln Street, Suite 700, Denver, Colorado 80203, and our
+telephone number is (303) 861-8140. 
+Our
+objective is to build stockholder value through consistent economic growth
+in
+reserves and production that increase net asset value per share and earnings
+per
+share. We seek to invest in oil and gas producing assets that result in a
+superior return on equity while preserving underlying capital, resulting in
+a
+return on equity to stockholders that reflects capital appreciation as well
+as
+the payment of cash dividends. 
+Our
+operations are focused in the following five core operating areas in the United
+States: 
+· 
+the
+Rocky Mountain region consisting of the Williston Basin in eastern
+Montana
+and western North Dakota as well as basins in Wyoming. Recent activity
+in
+the northern Rockies includes drilling in the Middle Bakken formation,
+continued development in the Red River formation, and horizontal
+drilling
+prospects in the Mission Canyon and Ratcliffe formations. As a
+follow on to the acquisitions made in the last three years, the Company
+has increased its activity in Wyoming, with development of the Tensleep
+formation in the Big Horn Basin, development in the Wind River Basin
+and
+gas development in the Greater Green River Basin. Our development
+of
+coalbed methane reserves in the Hanging Woman Basin is included in
+our
+Rockies region; 
+· 
+the
+Mid-Continent region in Oklahoma and northern Texas, primarily in
+the
+Anadarko and Arkoma basins. The most significant activity is in the
+Northeast Mayfield area in Beckham and Roger Mills counties and the
+Centrahoma area in Coal County where we are pursuing development
+of a
+horizontal well program in the Wapanucka limestone, Cromwell sandstone
+and
+Woodford shale formations; 
+· 
+the
+ArkLaTex region spans northern Louisiana, southern Arkansas, Mississippi
+and eastern Texas. Recent activity includes the horizontal program
+in the
+James Lime formation at the Spider field. The ArkLaTex region is
+using its
+horizontal well expertise to expand into the limestones of the Glen
+Rose,
+James, Rodessa, and Pettet formations throughout the region. The
+ArkLaTex region manages our interest in a significant vertical well
+development effort at the Elm Grove field as well as our interest
+in the
+Cotten Valley interval at Terryville field; 
+· 
+the
+Gulf Coast region consists of onshore Texas and Louisiana properties
+and
+includes the Judge Digby field in Pointe Coupee Parish, our fee property
+in St. Mary Parish, Louisiana, and a presence in the offshore Gulf of
+Mexico. The region is using 3-D seismic to identify direct hydrocarbon
+indicators along the Gulf Coast and in the Gulf of Mexico;
+and 
+· 
+the
+Permian Basin in eastern New Mexico and western Texas, includes the
+waterflood projects at Parkway Delaware Unit and East Shugart Delaware
+Unit in New Mexico. 
+As
+of
+December 31, 2005, we had estimated proved reserves of 62.9 MMBbl of oil and
+417.1 Bcf of natural gas, or a total of 794.5 BCFE with a PV-10 value of $2.5
+billion. Of these reserves, 82 percent were proved developed and 53 percent
+were
+natural gas. This represents an increase in reserve volumes of 21 percent and
+a
+66 percent increase in PV-10 value from a year earlier. For the year ended
+December 31, 2005, we produced 87.4 BCFE, representing average daily production
+of 239.4 MMCFE, a 16 percent increase from 2004. Our reserve replacement
+percentage in 2005 was 256 percent of production. This percentage would not
+change if sales of reserves were included in the calculation. The proved reserve
+total at December 31, 2005, includes 25.2 Bcf of natural gas reserves associated
+with our coalbed methane project at Hanging Woman Basin. 
+1 
+Our
+reserve replacement percentage, excluding acquisitions and sales, was 199
+percent in 2005. This is a result of the overall strength of our drilling
+programs in the Bakken, at Northeast Mayfield and our participation in the
+Elm
+Grove field, as well as the exceptionally strong performance of our Paggi
+Broussard well in Jefferson County, Texas. The percentage of PUD reserves
+increased from 15 percent at the end of 2004 to 18 percent at December 31,
+2005.
+This increase is directly related to the continuing development of our Atoka
+and
+Granite Wash program in the Northeast Mayfield area and the Centrahoma area
+in the Mid-Continent region as well as recognition of proved reserves in the
+ArkLaTex region at Elm Grove. We believe that the use of the term, “reserve
+replacement percentage” is widely understood and utilized by those who are
+involved in and those who make investment decisions related to the exploration
+and production industry. Therefore, this measure provides a useful basis of
+comparison to other companies and provides a measure of growth. 
+We
+attempt to focus our resources in selected domestic basins where we believe
+our
+expertise in geology, geophysics and drilling and completion techniques provide
+us with competitive advantages. In 2005 we spent $319.3 million in capital
+expenditures related to drilling activities, $87.8 million on acquisition
+of oil and gas properties and $14.3 million on leasing activity.
+Our
+total
+capital budget for 2006 is $600 million. As a company, we are placing a greater
+emphasis on growth through the drill bit rather than from acquisitions. This
+is
+evidenced by our reserve replacement from the drill bit, and the fact that
+our
+2006 capital program contemplates $500 million of spending on drilling
+operations and $100 million on acquisitions. The increase in budgeted spending
+represents a 42 percent increase over 2005. This increase includes our estimate
+of drilling program inflation, but the majority relates to our activity level
+and prospect inventory. We have assembled a balanced program of
+low-to-medium-risk development and exploitation projects to provide the
+foundation for steady growth. We believe that the development of resource plays
+in the Bakken, Atoka and Granite Wash at Northeast Mayfield, the Wapanucka
+limestone, Cromwell sandstone, and Woodford shale at Centrahoma, the Cotton
+Valley and Hosston at Elm Grove, and coalbed methane in the Hanging Woman Basin
+help provide us with a core inventory of prospects for the future. We measure
+and rank our investment decisions based on their risk-adjusted estimated
+internal rate of return and return on investment. In 2005 all acquisitions
+were
+funded with cash flow generated from operations. Additionally, we were able
+to
+repay the $37 million of borrowings from our revolving credit facility that
+was outstanding at the beginning of the year. When we issue stock for the
+acquisition of properties or a corporate entity, we base our investment decision
+primarily on the impact to net asset value per share. 
+Although
+our acquisition budget is lower than in prior years on a percentage basis,
+we
+will continue to seek selective acquisitions of oil and gas properties that
+complement our existing operations, offer economies of scale and provide further
+development, exploitation and exploration opportunities based on proprietary
+geologic concepts. We will be focusing on areas where we have specialized
+geologic knowledge or operating experience to enable us to acquire attractively
+priced properties. In addition, we have and will pursue corporate acquisitions
+that we believe are accretive and that we are capable of integrating. In 2005
+we
+acquired the stock of Agate Petroleum, Inc. for cash. Other examples of
+corporate acquisitions include the acquisition of Goldmark Engineering in 2004
+for cash and the acquisitions of Nance Petroleum Corporation and King Ranch
+Energy, Inc. in 1999, both of which were accomplished with the issuance of
+our
+common stock. The Flying J Oil & Gas Inc. property acquisition transaction
+completed in 2003 was not a corporate acquisition, yet we used a combination
+of
+restricted stock, a loan to Flying J and options on our common stock for this
+transaction. 
+We
+divest
+selected non-core assets when market conditions and prices are attractive,
+and
+we will continue to evaluate such opportunities in the future as we believe
+it
+to be appropriate. During 2005 we sold properties with estimated proved reserves
+of 630 MMCFE, or less than one-tenth of one percent of our reserves as of the
+beginning of the year. 
+2 
+We
+seek
+to develop our existing property base and acquire acreage with additional
+potential in our core areas. From January 1, 2003 through December 31, 2005,
+we
+participated in the drilling or recompletion of 1,118 gross wells with a success
+rate of 89 percent. During the three-year period we added estimated proved
+reserves of 592.6 BCFE at an average finding cost of $1.64 per MCFE. These
+results represent a three-year average reserve replacement percentage of 247
+percent, not including the effect of sales. Production has grown from an average
+daily rate of 210.7 MMCFE per day in 2003 to 239.4 MMCFE per day in 2005.
+As
+of
+December 31, 2005, we had an acreage position of 2,106,884 gross (1,103,961
+net)
+acres of which 1,178,845 gross (712,323 net) acres were undeveloped. Our current
+leasehold position represents a seven percent increase on a gross acre basis
+and
+a six percent increase on a net acre basis from 2004. In addition to the leased
+acreage position, we own 24,914 net acres of fee properties in St. Mary
+Parish, Louisiana, and mineral servitudes representing 14,663 gross (9,868
+net)
+acres in other portions of Louisiana. We believe this lease position provides
+a
+competitive advantage in certain locations and is a strategic asset for the
+Company. 
+Our
+senior technical managers in each region possess from 15 to 40 years of industry
+experience and lead fully-staffed regional technical offices that are supported
+by centralized administration from our Denver office. We use our comprehensive
+base of geological, geophysical, engineering and production experience in each
+of our core operating areas to source prospects for our ongoing
+low-to-medium-risk development and exploitation programs. We conduct detailed
+geologic studies and use an array of technologies and tools including 2-D and
+3-D seismic imaging, hydraulic fracturing and reservoir stimulation techniques,
+horizontal drilling, secondary recovery and specialized logging tools to enhance
+the potential of our existing properties. 
+We
+believe it is important to control geologic and operational decisions as well
+as
+the timing of those decisions. As of December 31, 2005, we operated 67 percent
+of our properties on a reserve volume basis and 64 percent on a PV-10 value
+basis. We plan to operate approximately 73 percent of our 2006 exploration
+and
+development capital budget. 
+Conservative
+use of financial leverage has long been a critical element of our strategy.
+We
+believe that maintaining a strong balance sheet is a significant competitive
+advantage that enables us to pursue acquisition and other opportunities,
+especially in weaker price environments. It also provides us with the financial
+resources to weather periods of volatile commodity prices or escalating costs.
+Our debt to book capitalization ratio was 15 percent at the end of December
+2005. 
+In
+summary, we believe that our dedication to making decisions based on net asset
+value per share, our long-standing geologic and engineering experience in the
+regions in which we operate, our application of technology, our established
+networks of local industry relationships and our acreage holdings in our core
+operating areas provide us with our competitive advantages. 
+Significant
+Developments since December 31, 2004 
+· 
+2005
+Acquisition of Oil and Gas Properties .
+Our total acquisitions of proved and unproved oil and gas properties
+in
+2005 were $87.8 million. The two most significant acquisitions
+were the
+Agate Petroleum, Inc. corporate acquisition that closed on January
+5,
+2005, for $40.0 million in cash and the Wold Oil Properties, Inc.
+property
+acquisition that closed on August 1, 2005, for $37.1 million in
+cash.
+Assets acquired from Agate Petroleum, Inc. are located in the Williston
+and Arkoma Basins and the properties acquired from Wold Oil Properties,
+Inc., are located primarily in the Wind River and Powder River
+Basins.
+· 
+Coalbed
+Methane Development. 
+Our total proved reserves at Hanging Woman Basin at the end of
+2005 grew
+to 25.2 Bcf. During 2005 we drilled 131 wells, 114 of which we
+operate,
+and our total production was 0.5 Bcf. The 2006 capital program
+for the
+Hanging Woman Basin development is currently budgeted at $50 million
+for
+approximately 260 wells. Environmental and regulatory permitting
+issues
+may impact the timing of drilling approximately 60 wells located
+in
+Montana and 60 wells located in Wyoming. The potential Montana
+delays are
+a result of the necessary regulatory approval of our water development
+plan on state and fee acreage. Delays in Wyoming permitting could
+result from the scheduling of drilling in areas that are
+affected by stipulations associated with sage grouse.
+3 
+· 
+Increase
+in 2005 Year-End Reserves. Proved
+reserves increased 21 percent to 794.5 BCFE at December 31, 2005,
+from 658.6 BCFE at December 31, 2004. We added 140.1 BCFE from our
+drilling program, 49.8 BCFE from acquisitions, and 33.9 BCFE
+from upward
+reserve revisions. Included in the revision number is 23.1
+BCFE of upward
+revisions resulting from increases in oil and gas prices. We
+sold
+properties with reserves of less than one BCFE in
+2005. 
+· 
+Drilling
+Results. Reserve
+additions came principally from drilling results in the Rockies,
+Mid-Continent and ArkLaTex regions. The increase in the Rockies
+can be
+attributed primarily to continued development of the Middle Bakken
+play in
+Montana. The Red River formation continues to provide reserve
+additions in
+the Rockies as we take full advantage of 3-D seismic to identify
+multi-pay
+structures. Our Mid-Continent reserve additions were primarily
+from the
+continued development of the Northeast Mayfield area and the
+Centrahoma
+area. The Northeast Mayfield development has shifted to the Atoka
+and
+Granite Wash formations from the deeper Morrow sand that provided
+growth
+in earlier years. The Centrahoma play includes the start of a
+horizontal
+program in the Wapanucka limestone, Cromwell sandstone and Woodford
+shale
+formations. The ArkLaTex region grew from total proved reserves
+of 75.6
+BCFE at the end of 2004 to 111.3 BCFE this year end. This growth is a
+reflection of the value we are deriving from the Elm Grove field
+development at Bossier Parish, Louisiana. 
+· 
+Hedging
+of Oil and Natural Gas through 2011. Beginning in
+October 2005, we entered into financial derivative transactions
+to hedge
+oil and gas prices on a significant portion of our proved developed
+producing assets. These hedges have been placed in the form of
+zero-cost
+collars. We have also hedged specific production related to our
+acquisitions as well as a portion of existing production for our
+2006
+Northeast Mayfield development program using swap contracts. 
+· 
+Repurchase
+of Common Stock .
+In 2005 we repurchased a total of 1,175,282 shares of our common
+stock at
+an average cost of $24.51 per share. These repurchases were funded
+from
+available cash. As of December 31, 2005, the number of additional
+shares
+that we may repurchase under the program is
+3,846,118. 
+Major
+Customers 
+During
+2005, sales to Tesoro Refining and Marketing accounted for 13 percent of our
+total oil and gas production revenue. During 2004 sales to Tesoro Refining
+and
+Marketing accounted for 20 percent of our total oil and gas production revenue.
+During 2003 sales to BP America Production Company accounted for 14 percent,
+sales to Midcoast Energy accounted for 13 percent and sales to Tesoro Refining
+and Marketing accounted for 11 percent of our total oil and gas production
+revenue. 
+Employees
+and Office Space 
+As
+of
+February 15, 2006, we had 305 full-time employees. None of our employees are
+subject to a collective bargaining agreement, and we consider our relations
+with
+our employees to be good. We lease approximately 56,900 square feet of office
+space in Denver, Colorado for our executive and administrative offices, of
+which
+9,500 square feet is subleased. We also lease approximately 18,600 square feet
+of office space in Tulsa, Oklahoma; approximately 11,700 square feet in
+Shreveport, Louisiana; approximately 13,700 square feet in Houston, Texas;
+approximately 32,200 square feet in Billings, Montana; and approximately 2,000
+square feet in Casper, Wyoming. 
+Title
+to Properties 
+Substantially
+all of our working interests are held pursuant to leases from third parties.
+A
+title opinion is usually obtained prior to the commencement of drilling
+operations on properties. We have obtained title opinions or conducted a
+thorough title review on substantially all of our producing properties and
+believe that we have satisfactory title to such properties in accordance with
+standards generally accepted in the oil and gas industry. The majority of the
+value of our properties is subject to a mortgage under our credit facility,
+customary royalty interests, liens for current taxes, and other burdens that
+we
+believe do not materially interfere with the use of or affect the value of
+such
+properties. We perform only a minimal title investigation before acquiring
+undeveloped leasehold. 
+4 
+Seasonality 
+Generally,
+but not always, the demand and price levels for natural gas increase during
+the
+colder winter months and decrease during the warmer summer months. In addition,
+pipelines, utilities, local distribution companies and industrial users utilize
+natural gas storage facilities and purchase some of their anticipated winter
+requirements during the summer, which can lessen seasonal demand fluctuations.
+Crude oil and the demand for heating oil are also impacted by generally higher
+prices in the winter. Seasonal anomalies such as mild winters sometimes lessen
+these fluctuations. The impact of seasonality has somewhat been mitigated by
+the
+overall supply and demand economics related to crude oil because there is a
+narrow margin of production capacity in excess of existing worldwide
+demand. 
+Competition 
+The
+oil
+and gas industry is intensely competitive. This is particularly true in the
+acquisition of prospective oil and natural gas properties and oil and gas
+reserves. We believe that our leasehold position provides a sound foundation
+for
+a robust drilling program. Our competitive position also depends on our
+geological, geophysical and engineering expertise, and our financial resources.
+We believe that the location of our leasehold acreage, our exploration, drilling
+and production expertise and the experience and knowledge of our management
+and
+industry partners enable us to compete effectively in our core operating areas.
+Notwithstanding our talents and assets, we still face stiff competition from
+a
+substantial number of major and independent oil and gas companies that have
+larger technical staffs and greater financial and operational resources than
+we
+do. Many of these companies not only engage in the acquisition, exploration,
+development and production of oil and natural gas reserves, but also have
+refining operations, market refined products and generate electricity. We also
+compete with other oil and natural gas companies in attempting to secure
+drilling rigs and other equipment necessary for the drilling and completion
+of
+wells. Consequently, drilling equipment may be in short supply from time to
+time. Currently, access to incremental drilling equipment in certain regions
+is
+difficult but is not, at this time, anticipated to have any material negative
+impact on our ability to deploy our capital drilling budget for 2006. Finally,
+we also compete for people. As drilling activities have accelerated, the need
+for talented people has grown at a time when the number of people available
+is
+constrained. 
+Government Regulations 
+Our
+business is subject to various federal, state and local laws and governmental
+regulations that may be changed from time to time in response to economic or
+political conditions. Matters subject to regulation include the issuance of
+drilling permits, discharge permits for drilling operations, drilling bonds,
+reports concerning operations, the spacing of wells, unitization and pooling
+of
+properties, taxation and environmental protection. From time to time, regulatory
+agencies have imposed price controls and limitations on production by
+restricting the rate of flow of oil and gas wells below actual production
+capacity in order to conserve supplies of oil and gas. 
+Energy
+Regulations .
+Our
+sales of natural gas are affected by the availability, terms and cost of
+transportation. The price and terms of access to pipeline transportation are
+subject to extensive federal and state regulation. From 1985 to the present,
+several major regulatory changes have been implemented by Congress and the
+Federal Energy Regulatory Commission that affect the economics of natural gas
+production, transportation and sales. In addition, the FERC is continually
+proposing and implementing new rules and regulations affecting those segments
+of
+the natural gas industry that remain subject to the FERC’s jurisdiction, most
+notably interstate natural gas transmission companies. These initiatives may
+also affect the intrastate transportation of gas under certain circumstances.
+The stated purpose of many of these regulatory changes is to promote competition
+among the various sectors of the natural gas industry. 
+5 
+The
+ultimate impact of the complex rules and regulations issued by the FERC since
+1985 cannot be predicted. In addition, many aspects of these regulatory
+developments have not become final but are still pending judicial and final
+FERC
+decisions. Regulations implemented by the FERC in recent years could result
+in
+an increase in the cost of transportation service on certain petroleum product
+pipelines. In addition, some of the FERC’s more recent proposals may adversely
+affect the availability and reliability of interruptible transportation service
+on interstate pipelines. Additional proposals and proceedings that might affect
+the natural gas industry are pending before Congress and the courts. The natural
+gas industry historically has been very heavily regulated, and there is no
+assurance that the less stringent regulatory approach recently pursued by the
+FERC and Congress will continue. We do not believe that we will be more
+materially affected by any action taken by the FERC than other natural gas
+producers and marketers with whom we compete. 
+Certain
+operations we conduct involve federal minerals administered by the Minerals
+Management Service. The MMS issues leases covering such lands through
+competitive bidding. These leases contain relatively standardized terms and
+require compliance with federal laws and detailed MMS regulations. For offshore
+operations, lessees must obtain MMS approval for exploration plans and
+development and production plans prior to the commencement of such operations.
+In addition to permits required from other agencies such as the Coast Guard,
+the
+Army Corps of Engineers and the Environmental Protection Agency, lessees must
+obtain a permit from the MMS prior to the commencement of drilling. Lessees
+must
+also comply with detailed MMS regulations governing, among other
+things: 
+· 
+engineering
+and construction specifications for offshore production
+facilities; 
+· 
+safety
+procedures; 
+· 
+flaring
+of production; 
+· 
+plugging
+and abandonment of Outer Continental Shelf wells; 
+· 
+calculation
+of royalty payments and the valuation of production for this
+purpose;
+and 
+· 
+removal
+of facilities. 
+To
+cover
+the various obligations of lessees on the OCS, the MMS generally requires that
+lessees post substantial bonds or other acceptable assurances that such
+obligations will be met. The cost of such bonds or other surety can be
+substantial, and we may not be able to continue to obtain bonds or other surety
+in all cases. Under certain circumstances the MMS may require our operations
+on
+federal leases to be suspended or terminated. 
+Many
+of
+the states in which we conduct our oil and gas drilling and production
+activities regulate such activities by requiring, among other things, drilling
+permits and bonds and reports concerning operations. The laws of these states
+also govern a number of environmental and conservation matters, including the
+handling and disposing of waste material, plugging and abandonment of wells,
+restoration requirements, unitization and pooling of natural gas and oil
+properties and establishment of maximum rates of production from natural gas
+and
+oil wells. Some states prorate production to the market demand for oil and
+natural gas. 
+Environmental
+Regulations. 
+Our
+operations are subject to numerous existing federal, state and local laws and
+regulations governing environmental quality and pollution control. These laws
+and regulations may require that permits be obtained before drilling commences,
+restrict the types, quantities and concentration of various substances that
+can
+be released into the environment in connection with drilling and production
+activities, and limit or prohibit drilling activities on certain lands lying
+within wilderness, wetlands and other protected areas, including areas
+containing endangered animal species. As a result, these laws and regulations
+may substantially increase the costs of exploring, developing or producing
+oil
+and gas and may prevent or delay the commencement or continuation of a project.
+In addition, these laws and regulations may impose substantial clean-up,
+remediation and other obligations in the event of any discharges or emissions
+in
+violation of such laws and regulations. 
+6 
+Our
+coalbed methane gas production from the Hanging Woman Basin is similar to our
+traditional natural gas production as to the physical producing facilities
+and
+the product produced. However, the subsurface mechanisms that allow the gas
+to
+move to the wellbore and the producing characteristics of coalbed methane wells
+are very different from traditional natural gas production. Unlike conventional
+gas wells, which require a porous and permeable reservoir, hydrocarbon migration
+and a natural structural and/or stratigraphic trap, coalbed methane gas is
+trapped in the molecular structure of the coal itself until released by pressure
+changes resulting from the removal of in situ 
+water.
+Frequently, coalbeds are partly or completely saturated with water. As the
+water
+is removed, internal pressures on the coal are decreased, allowing the gas
+to
+desorb from the coal and flow to the wellbore. Unlike traditional gas wells,
+new
+coalbed methane wells often produce water for several months and then, as the
+water production decreases, natural gas production increases. 
+Coalbed
+methane gas production in the Hanging Woman Basin requires state permits for
+the
+use of well-site pits and evaporation ponds for the disposal of produced water.
+Groundwater produced from the coal seams can generally be discharged into
+arroyos, surface waters, well-site pits and evaporation ponds without a permit
+if it does not exceed surface discharge permit levels, and meets state and
+federal primary drinking water standards. All of these disposal options require
+an extensive third-party water sampling and laboratory analysis program to
+ensure compliance with state permit standards. Where water of lesser quality
+is
+involved or the wells produce water in excess of the applicable volumetric
+permit limits, additional disposal wells may have to be drilled to re-inject
+the
+produced water back into deep underground rock formations. 
+A
+portion
+of our acreage at Hanging Woman Basin is on federal lands, with a segment of
+the
+lands in Montana. We are subject to delays in permitting associated with the
+completion of a supplemental Environmental Impact Statement covering the
+contemplation of phased development on Federal leases in Montana. We are also
+affected by considerations for sage grouse that are native to the area. Each
+of
+these issues has the potential to impact the timing of our permitting and
+drilling operations associated with development of our reserves at Hanging
+Woman
+Basin. 
+To
+date
+we have not experienced any material adverse effect on our operations from
+obligations under environmental laws and regulations. We believe that we are
+in
+substantial compliance with currently applicable environmental laws and
+regulations and that continued compliance with existing requirements would
+not
+have a material adverse impact on us. 
+Cautionary
+Information about Forward-Looking Statements 
+This
+Form
+10-K contains "forward-looking statements" within the meaning of Section 27A
+of
+the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
+1934. All statements, other than statements of historical facts, included in
+this Form 10-K that address activities, events or developments that we expect,
+believe or anticipate will or may occur in the future are forward-looking
+statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,”
+“expect,” “intend,” “plan,” “will” and “project” and similar expressions are
+intended to identify forward-looking statements. Forward-looking statements
+appear in a number of places in this Form 10-K, and include statements about
+such matters as: 
+· 
+The
+amount and nature of future capital expenditures and
+the availability of
+capital resources to fund capital
+expenditures; 
+· 
+The
+drilling of wells and other exploration and development
+plans, as well as
+possible future acquisitions; 
+· 
+Reserve
+estimates and the estimates of both future net revenues and
+the present
+value of future net revenues that are included in their
+calculation; 
+· 
+Future
+oil and gas production estimates; 
+· 
+Our
+outlook on future oil and gas
+prices; 
+7 
+· 
+Cash
+flows, anticipated liquidity and the future repayment
+of
+debt; 
+· 
+Business
+strategies and other plans and objectives for future operations,
+including
+plans for expansion and growth of operations, and our outlook
+on future
+financial condition or results of operations;
+and 
+· 
+Other
+similar matters such as those discussed in the “Management’s Discussion
+and Analysis of Financial Condition and Results of Operations” section of
+this Form 10-K. 
+Our
+forward-looking statements are based on assumptions and analyses made by us
+in
+light of our experience and our perception of historical trends, current
+conditions, expected future developments and other factors that we believe
+are
+appropriate under the circumstances. These statements are subject to a number
+of
+known and unknown risks and uncertainties which may cause our actual results
+to
+differ materially from results expressed or implied by the forward-looking
+statements. These risks are described in the “Risk Factors” section of this Form
+10-K, and include such factors as: 
+· 
+the
+volatility and level of realized oil and natural gas
+prices; 
+· 
+unexpected
+drilling conditions and results; 
+· 
+the
+risks of various exploration and hedging
+strategies; 
+· 
+the
+uncertain nature of the expected benefits from the acquisition
+of oil and
+gas properties; 
+· 
+production
+rates and reserve replacement; 
+· 
+the
+imprecise nature of oil and gas reserve
+estimates; 
+· 
+drilling
+and operating service availability; 
+· 
+uncertainties
+in cash flow; 
+· 
+the
+financial strength of hedge contract counterparties; 
+· 
+the
+availability of economically attractive exploration, development
+and
+property acquisition opportunities and any necessary financing;
+and 
+· 
+competition,
+litigation, environmental matters, and the potential impact
+of government
+regulations. 
+We
+caution you that forward-looking statements are not guarantees of
+future performance and that actual results or developments may differ
+materially from those expressed or implied in the forward-looking statements.
+Although we may from time to time voluntarily update our prior forward-looking
+statements, we disclaim any commitment to do so except as required by securities
+laws. 
+Available
+Information 
+Our
+Internet website address is www.stmaryland.com. Through our website’s financial
+information section we make available free of charge our annual reports on
+Form
+10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and
+amendments to those reports filed with or furnished to the SEC under applicable
+securities laws. These materials are made available as soon as reasonably
+practical after we electronically file such material with, or furnish it to,
+the
+SEC. 
+8 
+We
+also
+make available through our website’s corporate governance section our corporate
+governance guidelines, code of business conduct and ethics, and the charters
+for
+our Board of Directors’ audit committee, compensation committee, executive
+committee and nominating and corporate governance committee. These documents
+are
+also available in print to any stockholder who requests them. Requests for
+these
+documents may be submitted to: 
+St. Mary
+Land & Exploration Company 
+Investor
+Relations 
+1776
+Lincoln Street, Suite 700 
+Denver,
+Colorado 80203 
+Telephone:
+(303) 863-4322 
+Information
+on our website is not incorporated by reference into this Form 10-K and should
+not be considered part of this document. 
+Glossary 
+The
+terms
+defined in this section are used throughout this Form 10-K. 
+2-D
+seismic or 2-D data. 
+Seismic
+data that is acquired and processed to yield a two-dimensional cross-section
+of
+the subsurface. 
+3-D
+seismic or 3-D data. 
+Seismic
+data that is acquired and processed to yield a three-dimensional picture of
+the
+subsurface. 
+Bbl. 
+One
+stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil
+or
+other liquid hydrocarbons. 
+Bcf. 
+Billion
+cubic feet, used in reference to natural gas. 
+BCFE. 
+Billion
+cubic feet of gas equivalent. Gas equivalents are determined using the ratio
+of
+six Mcf of gas (including gas liquids) to one Bbl of oil. 
+BOE. 
+Barrels
+of oil equivalent. Oil equivalents are determined using the ratio of six Mcf
+of
+gas (including gas liquids) to one Bbl of oil. 
+Development
+well. 
+A well
+drilled within the proved area of an oil or gas reservoir to the depth of a
+stratigraphic horizon known to be productive. 
+Dry
+hole. 
+A well
+found to be incapable of producing either oil or gas in sufficient quantities
+to
+justify completion as an oil or gas well. 
+Exploratory
+well. 
+A well
+drilled to find and produce oil or gas in an unproved area, to find a new
+reservoir in a field previously found to be productive of oil or gas in another
+reservoir or to extend a known reservoir beyond its known horizon. 
+Farmout. 
+An
+assignment of an interest in a drilling location and related acreage conditional
+upon the drilling of a well on that location. 
+Fee
+land. 
+The most
+extensive interest that can be owned in land, including surface and mineral
+(including oil and gas) rights. 
+Field. 
+An area
+consisting of a single reservoir or multiple reservoirs all grouped on or
+related to the same individual geological structural feature or stratigraphic
+condition. 
+Finding
+cost. 
+Expressed in dollars per BOE or MCFE. Finding costs are calculated by dividing
+the amount of total capital expenditures for oil and gas activities, including
+the effect of asset retirement obligations, by the amount of estimated net
+proved reserves added through discoveries, acquisitions, and revisions of
+previous estimates during the same period. The information for this calculation
+is included in the note regarding disclosures about oil and gas producing
+activities contained in the Notes to Consolidated Financial Statements included
+in this Form 10-K. 
+9 
+Gross
+acre. 
+An acre
+in which a working interest is owned. 
+Gross
+well. 
+A well
+in which a working interest is owned. 
+Hydraulic
+fracturing. 
+A
+procedure to stimulate production by forcing a mixture of fluid and proppant
+(usually sand) into the formation under high pressure. This creates artificial
+fractures in the reservoir rock, which increases permeability and
+porosity. 
+MBbl. 
+One
+thousand barrels of oil or other liquid hydrocarbons. 
+MMBbl. 
+One
+million barrels of oil or other liquid hydrocarbons. 
+MBOE. 
+One
+thousand barrels of oil equivalent. 
+MMBOE. 
+One
+million barrels of oil equivalent. 
+Mcf. 
+One
+thousand cubic feet, used in reference to natural gas. 
+MCFE .
+One
+thousand cubic feet of gas equivalent. Gas equivalents are determined using
+the
+ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. 
+MMcf. 
+One
+million cubic feet, used in reference to natural gas. 
+MMCFE .
+One
+million cubic feet of gas equivalent. Gas equivalents are determined using
+the
+ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. 
+MMBtu. 
+One
+million British Thermal Units. A British Thermal Unit is the amount of heat
+required to raise the temperature of a one-pound mass of water by one degree
+Fahrenheit. 
+Net
+acres or net wells. 
+The sum
+of our fractional working interests owned in gross acres or gross
+wells. 
+Net
+asset value per share. 
+The
+result of the fair market value of total assets less total liabilities, divided
+by the total number of outstanding shares of common stock. 
+NYMEX .
+New
+York Mercantile Exchange. 
+PV-10
+value. 
+The
+present value of estimated future gross revenue to be generated from the
+production of estimated net proved reserves, net of estimated production and
+future development costs, using prices and costs in effect as of the date
+indicated (unless such prices or costs are subject to change pursuant to
+contractual provisions), without giving effect to non-property related expenses
+such as general and administrative expenses, debt service and future income
+tax
+expenses or to depreciation, depletion and amortization, discounted using an
+annual discount rate of 10 percent. While this measure does not include the
+effect of income taxes as it would in the use of the standardized measure
+calculation, it does provide an indicative representation of the relative value
+of the Company on a comparative basis to other companies and from period to
+period. 
+Productive
+well. 
+A well
+that is producing oil or gas or that is capable of production. 
+Proved
+developed reserves. 
+Reserves
+that can be expected to be recovered through existing wells with existing
+equipment and operating methods. 
+Proved
+reserves. 
+The
+estimated quantities of oil, gas and gas liquids which geological and
+engineering data demonstrate with reasonable certainty to be recoverable in
+future years from known reservoirs under existing economic and operating
+conditions. 
+Proved
+undeveloped reserves. 
+Reserves
+that are expected to be recovered from new wells on undrilled acreage, or from
+existing wells where a relatively major expenditure is required for
+recompletion. 
+10 
+Recompletion. 
+The
+completion for production from an existing wellbore in a formation other than
+that in which the well has previously been completed. 
+Reserve
+life. 
+Expressed in years, represents the estimated net proved reserves at a specified
+date divided by actual production for the preceding 12-month
+period. 
+Reserve
+replacement percentage - excluding sales .
+The sum
+of reserve extensions and discoveries, reserve acquisitions, and reserve
+revisions of previous estimates for a specified period of time divided by
+production for that same period of time. This is believed to be a useful
+non-GAAP measure that is widely utilized within the exploration and production
+industry as well as by investors. It is an easily calculable number and is
+representative of the relative success a company is having in replacing its
+production from its declining asset base as well as its ability to grow the
+overall company. 
+Reserve
+replacement percentage - including sales .
+The sum
+of sales of reserves, reserve extensions and discoveries, reserve acquisitions,
+and reserve revisions of previous estimates for a specified period of time
+divided by production for that same period of time. This is believed to be
+a
+useful non-GAAP measure that is widely utilized within the exploration and
+production industry as well as by investors. It is an easily calculable number
+and is representative of the relative success a company is having in replacing
+its production from its declining asset base as well as its ability to grow
+the
+overall company. 
+Royalty. 
+The
+share paid to the owner of mineral rights, expressed as a percentage of gross
+income from oil and gas produced and sold unencumbered by expenses relating
+to
+the drilling, completing and operating of the affected well. 
+Royalty
+interest. 
+An
+interest in an oil and gas property entitling the owner to shares of oil and
+gas
+production free of costs of exploration, development and production
+operations. 
+Undeveloped
+acreage. 
+Lease
+acreage on which wells have not been drilled or completed to a point that would
+permit the production of commercial quantities of oil and gas, regardless of
+whether such acreage contains estimated net proved reserves. 
+Working
+interest. 
+The
+operating interest that gives the owner the right to drill, produce and conduct
+operating activities on the property and to share in the production, sales,
+and
+costs. 
+Item
+1A. RISK
+FACTORS 
+In
+addition to the other information included in this Form 10-K, the following
+risk
+factors should be carefully considered when evaluating
+St. Mary. 
+Risks
+Related to Our Business 
+Oil
+and natural gas prices are volatile, and a decline in prices could hurt our
+profitability, financial condition and ability to grow. 
+Our
+revenues, operating results, profitability, future rate of growth and the
+carrying value of our oil and gas properties depend heavily on the prices we
+receive for oil and natural gas sales. Oil and gas prices also affect our cash
+flows and borrowing capacity, as well as the amount and value of our oil and
+gas
+reserves. 
+Historically,
+the markets for oil and gas have been volatile and they are likely to continue
+to be volatile. Wide fluctuations in oil and gas prices may result from
+relatively minor changes in the supply of and demand for oil and gas, market
+uncertainty and other factors that are beyond our control,
+including: 
+· 
+worldwide
+and domestic supplies of oil and natural
+gas; 
+· 
+the
+ability of the members of the Organization of Petroleum Exporting
+Countries to agree to and maintain oil price and production
+controls; 
+11 
+· 
+pipeline,
+transportation, or refiner capacity constraints in a regional
+or localized
+area may put downward pressure on the realized price for
+oil or natural
+gas; 
+· 
+political
+instability or armed conflict in oil or gas producing
+regions; 
+· 
+worldwide
+and domestic economic conditions; 
+· 
+the
+level of consumer demand; 
+· 
+the
+availability of transportation facilities; 
+· 
+weather
+conditions; and 
+· 
+governmental
+regulations and taxes. 
+These
+factors and the volatility of oil and gas markets make it very difficult to
+predict future oil and gas price movements with any certainty. Declines in
+oil
+or gas prices would reduce our revenues and could also reduce the amount of
+oil
+and gas that we can produce economically and therefore could have a material
+adverse effect on us. 
+If
+we
+are not able to replace reserves, we will not be able to sustain
+production. 
+Our
+future operations depend on our ability to find, develop and acquire oil and
+gas
+reserves that are economically recoverable. Our properties produce oil and
+gas
+at a declining rate over time. In order to maintain current production rates
+we
+must locate and develop or acquire new oil and gas reserves to replace those
+being depleted by production. We may do this even during periods of low oil
+and
+gas prices. In addition, competition for the acquisition of producing oil and
+gas properties is intense and many of our competitors have financial and other
+resources for acquisitions that are substantially greater than those available
+to us. Therefore, we may not be able to acquire oil and gas properties that
+contain economically recoverable reserves, or we may not be able to acquire
+such
+properties at prices acceptable to us. Without successful drilling or
+acquisition activities, our reserves, production and revenues will decline
+rapidly. 
+Competition
+in our industry is intense, and many of our competitors have greater financial
+and technical resources than we do. 
+We
+face
+intense competition from major oil companies, independent oil and gas
+exploration and production companies, financial buyers, and institutional and
+individual investors who are actively seeking oil and gas properties throughout
+the world, along with the equipment, expertise, labor and materials required
+to
+operate oil and gas properties. Many of our competitors have financial and
+technical resources vastly exceeding those available to us, and many oil and
+gas
+properties are sold in a competitive bidding process in which our competitors
+may be able to pay more for development prospects and productive properties
+or
+in which our competitors have technological information or expertise to evaluate
+and successfully bid for the properties that is not available to us. In
+addition, shortages of equipment, labor or materials as a result of intense
+competition may result in increased costs or the inability to obtain those
+resources as needed. We may not be successful in acquiring and developing
+profitable properties in the face of this competition. 
+We
+compete for people. As drilling activities have accelerated, the need for
+talented people has grown at a time when the number of people available is
+constrained. 
+The
+actual quantities and present values of our proved oil and gas reserves may
+be
+less than we have estimated. 
+This
+Form
+10-K and other SEC filings by us contain estimates of our proved oil and gas
+reserves and the estimated future net revenues from those reserves. Reserve
+estimates are based on various assumptions, including assumptions required
+by
+the SEC relating to oil and gas prices, drilling and operating expenses, capital
+expenditures, taxes and availability of funds. The process of estimating
+reserves is complex. This process requires significant decisions and assumptions
+in the evaluation of available geological, geophysical, engineering and economic
+data for each reservoir. These estimates are dependent on many variables and
+therefore changes often occur as these variables evolve and commodity prices
+fluctuate. Therefore, these estimates are inherently imprecise. 
+12 
+Actual
+future production, oil and gas prices, revenues, taxes, development
+expenditures, operating expenses and quantities of recoverable oil and gas
+reserves will most likely vary from those estimated. Any significant variance
+could materially affect the estimated quantities and present values of proved
+reserves disclosed by us, and the actual quantities and present values may
+be
+less than we have previously estimated. In addition, we may adjust estimates
+of
+proved reserves to reflect production history, results of exploration and
+development, prevailing oil and gas prices and other factors, many of which
+are
+beyond our control. Our properties may also be susceptible to hydrocarbon
+drainage from production by operators on adjacent properties. 
+As
+of
+December 31, 2005, approximately 18 percent of our estimated proved
+reserves (by volume) were proved undeveloped. Estimates of proved undeveloped
+reserves and proved developed non-producing reserves are nearly always based
+on
+volumetric calculations rather than the performance data used to estimate
+producing reserves. Recovery of proved undeveloped reserves requires significant
+capital expenditures and successful drilling operations. Production revenues
+from proved developed non-producing reserves will not be realized until some
+time in the future. Our estimates of proved undeveloped reserves assume that
+we
+will make significant capital expenditures to develop these reserves, including
+an estimated $153 million in 2006. Although we have estimated our reserves
+and
+the costs associated with these reserves in accordance with industry standards,
+estimated costs may not be accurate, development may not occur as scheduled
+and
+actual results may not occur as estimated. 
+You
+should not assume that the PV-10 values included in this Form 10-K represent
+the
+current market value of our estimated oil and natural gas reserves. Management
+has based the estimated discounted future net cash flows from proved reserves
+on
+prices and costs as of the date of the estimate, in accordance with SEC
+requirements, whereas actual future prices and costs may be materially higher
+or
+lower. For example, values of our reserves as of December 31, 2005, were
+estimated using a calculated weighted-average sales price of $10.08 per Mcf
+of
+gas (Gulf Coast spot price) and $61.04 per Bbl of oil (NYMEX). We ensure that
+we
+consider basis and location differentials as of that date in estimating our
+reserves. During 2005 our monthly average realized gas prices, excluding the
+effect of hedging, were as high as $12.69 per Mcf and as low as $6.06 per Mcf.
+For the same period our monthly average realized oil prices were as high as
+$61.59 per Bbl and as low as $44.38 per Bbl. Many other factors will affect
+actual future net cash flows, including: 
+· 
+the
+amount and timing of actual
+production; 
+· 
+supply
+and demand for oil and natural gas; 
+· 
+curtailments
+or increases in consumption by oil and natural gas purchasers;
+and 
+· 
+changes
+in governmental regulations or
+taxes. 
+The
+timing of production from oil and natural gas properties and of related expenses
+affects the timing of actual future net cash flows from proved reserves and
+thus
+their actual present value. Our actual future net cash flows could be less
+than
+the estimated future net cash flows for purposes of computing PV-10 values.
+In
+addition, the ten percent discount factor required by the SEC to be used to
+calculate PV-10 values for reporting purposes is not necessarily the most
+appropriate discount factor given actual interest rates and risks to which
+our
+business and the oil and natural gas industry in general are
+subject. 
+Our
+producing property acquisitions may not be worth what we paid due to
+uncertainties in evaluating recoverable reserves and other expected benefits,
+as
+well as potential liabilities. 
+13 
+Successful
+property acquisitions require an assessment of a number of factors beyond our
+control. These factors include exploration potential, future oil and gas prices,
+operating costs and potential environmental and other liabilities. These
+assessments are not precise and their accuracy is inherently
+uncertain. 
+In
+connection with our acquisitions, we perform a customary review of the acquired
+properties that will not necessarily reveal all existing or potential problems.
+In addition, our review may not allow us to fully assess the deficiencies and
+potential of the properties. We do not inspect every well, and even when we
+inspect a well we may not discover structural, subsurface or environmental
+problems that may exist or arise. We may not be entitled to contractual
+indemnification for pre-closing liabilities, including environmental
+liabilities. Normally, we acquire interests in properties on an “as is” basis
+with limited remedies for breaches of representations and warranties. As a
+result of these factors, we may not be able to acquire oil and gas properties
+with economically recoverable reserves on acceptable terms. 
+In
+addition, significant acquisitions can change the nature of our operations
+and
+business if the acquired properties have substantially different operating
+and
+geological characteristics or are in different geographic locations than our
+existing properties. To the extent that acquired properties are substantially
+different than our existing properties, our ability to efficiently realize
+the
+expected economic benefits of such acquisitions may be limited. 
+Integrating
+acquired properties and businesses involves a number of other special risks,
+including the risk that management may be distracted from normal business
+concerns by the need to integrate operations and systems as well as retain
+and
+assimilate additional employees. Therefore, we may not be able to realize all
+of
+the anticipated benefits of our acquisitions. 
+Exploration
+and development drilling may not result in commercially productive
+reserves. 
+Oil
+and
+gas drilling and production activities are subject to numerous risks, including
+the risk that no commercially productive oil or natural gas will be found.
+The
+cost of drilling and completing wells is often uncertain, and oil and gas
+drilling and production activities may be shortened, delayed or canceled as
+a
+result of a variety of factors, many of which are beyond our control. These
+factors include: 
+· 
+unexpected
+drilling conditions; 
+· 
+title
+problems; 
+· 
+pressure
+or irregularities in formations; 
+· 
+equipment
+failures or accidents; 
+· 
+adverse
+weather conditions; 
+· 
+compliance
+with environmental and other governmental
+requirements; 
+· 
+shortages
+or delays in the availability of or increases in the cost of
+drilling rigs
+and the delivery of equipment; and 
+· 
+shortages
+in availability of experienced drilling crews.
+The
+prevailing prices of oil and gas also affect the cost of and the demand for
+drilling rigs, production equipment and related services. The availability
+of
+drilling rigs can vary significantly from region to region at any particular
+time. Although land drilling rigs can be moved from one region to another in
+response to changes in levels of demand, an undersupply of rigs in any region
+may result in drilling delays and higher drilling costs for the rigs that are
+available in that region. 
+14 
+Another
+significant risk inherent in our drilling plans is the need to obtain drilling
+permits from state, local and other governmental authorities. Delays in
+obtaining regulatory approvals and drilling permits, including delays which
+jeopardize our ability to realize the potential benefits from leased properties
+within the applicable lease periods, the failure to obtain a drilling permit
+for
+a well or the receipt of a permit with unreasonable conditions or costs could
+have a material adverse effect on our ability to explore on or develop our
+properties. 
+The
+wells
+we drill may not be productive and we may not recover all or any portion of
+our
+investment in such wells. The seismic data and other technologies that we use
+do
+not allow us to know conclusively prior to drilling a well that oil or gas
+is
+present or may be produced economically. The cost of drilling, completing and
+operating a well is often uncertain, and cost factors can adversely affect
+the
+economics of a project. Drilling activities can result in dry wells or wells
+that are productive but do not produce sufficient net revenues after operating
+and other costs to cover initial drilling costs. 
+Our
+future drilling activities may not be successful, or our overall drilling
+success rate or our drilling success rate for activity within a particular
+area
+may decline. In addition, we may not be able to obtain any options or lease
+rights in potential drilling locations that we identify. Although we have
+identified numerous potential drilling locations, we may not be able to
+economically produce oil or natural gas from all of them. 
+Our
+hedging transactions may limit the prices that we receive for oil and gas sales
+and involve other risks. 
+To
+manage
+our exposure to price risks in the sale of our oil and natural gas, we enter
+into commodity price risk management arrangements from time to time with respect
+to a portion of our current or future production. We have hedged a significant
+portion of anticipated future production from our currently producing properties
+using zero-cost collars and swaps. Commodity price hedging may limit the prices
+that we receive for our oil and gas sales if oil or natural gas prices rise
+substantially over the price established by the hedge. In addition, these
+transactions may expose us to the risk of financial loss in certain
+circumstances, including instances in which: 
+· 
+our
+production is less than expected; or 
+· 
+the
+counterparties to our hedge contracts fail to perform under
+the
+contracts. 
+Some
+of
+our hedging agreements may also require us to furnish cash collateral, letters
+of credit or other forms of performance assurance in the event that
+mark-to-market calculations result in settlement obligations by us to the
+counterparties, which would encumber our liquidity and capital resources. In
+addition, some of our hedging transactions use derivative instruments that
+may
+involve basis risk. Basis risk in a hedging contract occurs when the index
+upon which the contract is based is more or less variable than the index upon
+which the hedged asset is based, thereby making the hedge less effective. For
+example, a NYMEX index used for hedging certain volumes of production may have
+more or less variability than the regional price index used for the sale of
+that
+production. 
+Future
+oil and gas price declines or unsuccessful exploration efforts may result in
+write-downs of our asset carrying values. 
+We
+follow
+the successful efforts method of accounting for our oil and gas properties.
+All
+property acquisition costs and costs of exploratory and development wells are
+capitalized when incurred, pending the determination of whether proved reserves
+have been discovered. If proved reserves are not discovered with an exploratory
+well, the costs of drilling the well are expensed. 
+The
+capitalized costs of our oil and gas properties, on a field basis, cannot exceed
+the estimated future net cash flows of that field. If net capitalized costs
+exceed future net revenues, we must write-down the costs of each such field
+to
+our estimate of fair market value. Unproved properties are evaluated at the
+lower of cost or fair market value. Accordingly, a significant decline in oil
+or
+gas prices or unsuccessful exploration efforts could cause a future write-down
+of capitalized costs. 
+15 
+We
+review
+the carrying value of our properties quarterly based on prices in effect as
+of
+the end of each quarter or as of the time of reporting our results. Once
+incurred, a writedown of oil and gas properties cannot be reversed at a later
+date even if oil or gas prices increase. 
+Substantial
+capital is required to replace our reserves. 
+We
+need
+to make substantial capital expenditures to find, acquire, develop and produce
+oil and natural gas reserves. Future cash flows and the availability of
+financing are subject to a number of factors, such as the level of production
+from existing wells, our success in locating and producing new reserves and
+prices of oil and natural gas. If oil or gas prices decrease or we encounter
+operating difficulties that result in our cash flows from operations being
+less
+than expected, we may have to reduce our capital expenditures unless we can
+raise additional funds through debt or equity financing. Debt or equity
+financing may not always be available to us in sufficient amounts or on
+acceptable terms. 
+If
+our
+revenues were to decrease due to lower oil or gas prices, decreased production
+or other reasons, and if we could not obtain capital through our credit facility
+or other acceptable debt or equity financing arrangements, our ability to
+execute our development plans, replace our reserves or maintain production
+levels could be greatly limited. 
+A
+decrease in oil or gas prices could limit our ability to borrow under our credit
+facility. 
+Our
+credit facility has a maximum loan amount of $500 million, subject to a
+borrowing base that the lenders periodically redetermine based on the value
+of
+our oil and gas properties, which in turn is based in part on oil and gas
+prices. Lower oil or gas prices in the future could limit our borrowing base
+and
+reduce our ability to borrow under the credit facility. 
+We
+could incur substantial additional debt, which could limit our financial
+flexibility. 
+As
+of
+December 31, 2005, we had $100.0 million in outstanding long-term debt
+under our 5.75 % Senior Convertible Notes due 2022. Our long-term debt
+represented 15 percent of our total book capitalization as of December 31,
+2005.
+Our credit facility has a maximum loan amount and current borrowing base of
+$500
+million, with a current commitment amount we have elected of $200 million,
+against which no borrowings were outstanding as of December 31,
+2005. 
+Our
+level
+of debt could have important consequences for our operations,
+including: 
+· 
+requiring
+us to dedicate a substantial portion of our cash flows
+from operations to
+make required payments on debt, thereby reducing the availability
+of cash
+flows for working capital, capital expenditures and other
+general business
+activities; 
+· 
+limiting
+our ability to obtain additional financing in the future
+for working
+capital, capital expenditures and other general business
+activities, or
+increasing the costs for such additional
+financing; 
+· 
+limiting
+our flexibility in planning for, or reacting to, changes in
+our business
+and our industry; and 
+· 
+increasing
+our vulnerability to adverse effects from a downturn in our
+business or
+the general
+economy. 
+We
+may
+incur additional debt, including secured debt under our credit facility or
+otherwise, in order to make future acquisitions or to develop our properties.
+An
+increased level of debt increases the risk that we may default on our debt
+obligations. We may not be able to generate sufficient cash flow from operations
+or be able to make other arrangements for the repayment or refinancing of the
+debt. 
+16 
+In
+addition, our credit facility is subject to periodic borrowing base
+redeterminations. We could be forced to repay a portion of our bank borrowings
+in the event of a downward redetermination of our borrowing base, and we may
+not
+have sufficient funds to make such repayment at that time. If we do not have
+sufficient funds and are otherwise unable to negotiate renewals of our borrowing
+or arrange new financing, we may be forced to sell significant
+assets. 
+We
+are subject to operating and environmental risks and hazards that could result
+in substantial losses. 
+Oil
+and
+gas operations are subject to many risks, including well blowouts, craterings,
+explosions, uncontrollable flows of oil, natural gas or well fluids, fires,
+adverse weather such as hurricanes in the Gulf Coast region, formations with
+abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic
+gas and other environmental risks and hazards. If any of these types of events
+occurs, we could sustain substantial losses. 
+Under
+certain limited circumstances we may be liable for environmental damage caused
+by previous owners or operators of properties that we own, lease or operate.
+As
+a result, we may incur substantial liabilities to third parties or governmental
+entities, which could reduce or eliminate funds available for exploration,
+development or acquisitions or cause us to incur losses. 
+Following
+the hurricanes in 2004 and 2005, the insurance markets have suffered significant
+losses. As a result, the availability of coverage and the cost at which such
+coverage will be available in the future is uncertain. 
+We
+maintain insurance against some, but not all, of these potential risks and
+losses. We have significant, but limited coverage for sudden environmental
+damages. We do not believe that insurance coverage for the full potential
+liability that could be caused by sudden environmental damages or insurance
+coverage for environmental damage that occurs over time is available at a
+reasonable cost. In addition, pollution and environmental risks generally are
+not fully insurable. Further, we may elect not to obtain other insurance
+coverage under circumstances where we believe that the cost of available
+insurance is excessive relative to the risks presented. Accordingly, we may
+be
+subject to liability or may lose substantial portions of certain properties
+in
+the event of environmental or other damages. If a significant accident or other
+event occurs and is not fully covered by insurance, we could suffer a material
+loss. 
+Our
+operations are subject to complex laws and regulations, including environmental
+regulations, that result in substantial costs and other risks. 
+Federal,
+state and local authorities extensively regulate the oil and gas industry.
+Legislation and regulations affecting the industry are under constant review
+for
+amendment or expansion, raising the possibility of changes that may affect,
+among other things, the pricing or marketing of oil and gas production.
+Noncompliance with statutes and regulations may lead to substantial penalties,
+and the overall regulatory burden on the industry increases the cost of doing
+business and, in turn, decreases profitability. 
+Governmental
+authorities regulate various aspects of oil and gas drilling and production,
+including the drilling of wells (through permit and bonding requirements),
+the
+spacing of wells, the unitization or pooling of oil and gas properties,
+environmental matters, safety standards, the sharing of markets, production
+limitations, plugging and abandonment, and restoration. To cover the various
+obligations of leaseholders in federal waters, federal authorities generally
+require that leaseholders have substantial net worth or post bonds or other
+acceptable assurances that such obligations will be met. The cost of these
+bonds
+or other assurances can be substantial, and we may not be able to obtain bonds
+or other assurances in all cases. Under limited circumstances, federal
+authorities may require any of our operations on federal leases to be suspended
+or terminated. Any such suspension or termination could have a material adverse
+effect on our operations. Our development at Hanging Woman Basin is particularly
+affected, as a portion of our acreage is on federal lands. 
+Our
+operations are also subject to complex and constantly changing environmental
+laws and regulations adopted by federal, state and local governmental
+authorities in jurisdictions where we are engaged in exploration or production
+operations. New laws or regulations, or changes to current requirements, could
+result in material costs or claims with respect to properties we own or have
+owned. We will continue to be subject to uncertainty associated with new
+regulatory interpretations and inconsistent interpretations between state and
+federal agencies. We could face significant liabilities to governmental
+authorities and third parties for discharges of oil, natural gas or other
+pollutants into the air, soil or water, and we could have to spend substantial
+amounts on investigations, litigation and remediation. Existing environmental
+laws or regulations, as currently interpreted or enforced, or as they may be
+interpreted, enforced or altered in the future, may have a material adverse
+effect on us. 
+17 
+We
+depend on transportation facilities owned by others. 
+The
+marketability of our oil and gas production depends in part on the availability,
+proximity and capacity of pipeline transportation systems owned by third
+parties. The lack of available transportation capacity on these systems and
+facilities could result in the shutting-in of producing wells, the delay or
+discontinuance of development plans for properties, or lower price realizations.
+Although we have some contractual control over the transportation of our
+production, material changes in these business relationships could materially
+affect our operations. Federal and state regulation of oil and gas production
+and transportation, tax and energy policies, changes in supply and demand,
+pipeline pressures, damage to or destruction of pipelines and general economic
+conditions could adversely affect our ability to produce, gather and transport
+oil and natural gas. 
+Ownership
+of royalty interests by an executive officer may create conflicts of
+interest. 
+As
+a
+result of his employment with another company prior to 1995, with which
+St. Mary engaged in a number of transactions, Kevin E. Willson, an
+executive officer of St. Mary, owns royalty interests in a number of our
+properties, which were earned as part of the prior employer’s employee benefit
+programs. Accordingly, conflicts of interest may exist between Mr. Willson
+and
+us, and such conflicts may not always be resolved in our favor. 
+Risks
+Related to Our Common Stock 
+The
+price of our common stock may fluctuate significantly, which may result in
+losses for investors. 
+From
+January 1, 2004, to February 15, 2006, the last daily sale price of
+our common stock as reported by the New York Stock Exchange ranged from a low
+of
+$13.92 per share to a high of $44.23 per share, as adjusted to reflect our
+2-for-1 stock split effected in the form of a stock dividend on March 31,
+2005. We expect our stock to continue to be subject to fluctuations as a result
+of a variety of factors, including factors beyond our control. These factors
+include: 
+· 
+changes
+in oil or natural gas prices; 
+· 
+variations
+in quarterly drilling, recompletions, acquisitions and operating
+results; 
+· 
+changes
+in financial estimates by securities analysts; 
+· 
+changes
+in market valuations of comparable companies; 
+· 
+additions
+or departures of key personnel; and 
+· 
+future
+sales of our common
+stock. 
+We
+may
+fail to meet expectations of our stockholders or of securities analysts at
+some
+time in the future, and our stock price could decline as a result. 
+Our
+certificate of incorporation and bylaws have provisions that discourage
+corporate takeovers and could prevent stockholders from receiving a takeover
+premium on their investment. 
+Our
+certificate of incorporation and bylaws contain provisions that may have the
+effect of delaying or preventing a change of control. These provisions, among
+other things, provide for non-cumulative voting in the election of the Board
+of
+Directors and impose procedural requirements on stockholders who wish to make
+nominations for the election of Directors or propose other actions at
+stockholder meetings. These provisions, alone or in combination with each other
+and with the shareholder rights plan described below, may discourage
+transactions involving actual or potential changes of control, including
+transactions that otherwise could involve payment of a premium over prevailing
+market prices to stockholders for their common stock. 
+18 
+Under
+our
+shareholder rights plan, if the Board of Directors determines that the terms
+of
+a potential acquisition do not reflect the long-term value of St. Mary, the
+Board of Directors could allow the holder of each outstanding share of our
+common stock other than those held by the potential acquirer to purchase one
+additional share of our common stock with a market value of twice the exercise
+price. This prospective dilution to a potential acquirer would make the
+acquisition impracticable unless the terms were improved to the satisfaction
+of
+the Board of Directors. The existence of the plan may impede a takeover not
+supported by our Board even though such takeover may be desired by a majority
+of
+our stockholders or may involve a premium over the prevailing stock
+price. 
+Our
+shares that are eligible for future sale may have an adverse effect on the
+price
+of our common stock. 
+As
+of
+February 15, 2006, we had 56,953,893 shares of common stock outstanding, net
+of
+250,000 shares held in treasury. Of the net shares outstanding, 55,595,375
+shares were freely tradable without substantial restriction or the requirement
+of future registration under the Securities Act of 1933. Also as of that date,
+options to purchase 4,506,090 shares of our common stock were outstanding,
+of
+which 3,929,271 were exercisable. These options are exercisable at prices
+ranging from $4.62 to $20.87 per share. In addition, restricted stock units
+providing for the issuance of up to a total of 632,809 shares of our common
+stock were outstanding. Sales of substantial amounts of common stock, or a
+perception that such sales could occur, and the existence of options and
+restricted stock units to issue shares of common stock at prices that may be
+below the then-current market price of the common stock could adversely affect
+the market price of the common stock and could impair our ability to raise
+capital through the sale of our equity securities. 
+We
+may not always pay dividends on our common stock. 
+The
+payment of future dividends remains in the discretion of the Board of Directors
+and will continue to depend on our earnings, capital requirements, financial
+condition and other factors. In addition, the payment of dividends is subject
+to
+covenants in our credit facility, including a covenant regarding the level
+of
+our current ratio of current assets to current liabilities and a limit on the
+annual dividend rate that we may pay no more than $0.25 per share. The Board
+of
+Directors may determine in the future to reduce the current annual dividend
+rate
+of $0.10 per share or discontinue the payment of dividends
+altogether. 
+A
+director and his extended family may be able to exert influence over
+us. 
+Thomas
+E.
+Congdon, a director and our former Chairman of the Board, and members of his
+extended family are estimated to own between five and ten percent of the
+outstanding shares of our common stock as of February 15, 2006. While no formal
+arrangements exist, these extended family members could be inclined to act
+in
+concert with Mr. Congdon on matters related to control of St. Mary,
+including for example the election of directors or response to an unsolicited
+proposal to acquire St. Mary. Accordingly, Mr. Congdon and his family may
+be able to influence matters presented to our Board of Directors and
+stockholders. 
+ITEM
+1B. UNRESOLVED
+STAFF COMMENTS 
+St.
+Mary
+has no unresolved comments from the SEC staff regarding its periodic or current
+reports under the Securities Act of 1934. 
+19 
+ITEM
+2. PROPERTIES 
+Operations 
+St. Mary's
+exploration, development and acquisition activities are focused in five core
+operating areas: the Rocky Mountain region; the Mid-Continent region; the
+ArkLaTex region; the Gulf Coast region; and the Permian Basin region. Our
+Hanging Woman Basin project is within our Rocky Mountain region and is managed
+by the personnel from our Billings office. Information concerning each of our
+major areas of operations is shown below in the summary of our estimated proved
+reserves as of December 31, 2005. 
+Estimated
+Proved Reserves 
+Oil 
+Gas 
+MMCFE 
+PV-10
+Value 
+(MBbl) 
+(MMcf) 
+Amount 
+Percent 
+(In
+thousands) 
+Percent 
+Rocky
+Mountain 
+52,870 
+85,492 
+402,712 
+50.7 
+$ 
+1,210,496 
+48.5 
+Hanging
+Woman Basin 
+- 
+25,219 
+25,219 
+3.1 
+65,638 
+2.6 
+Total
+Rocky Mountain 
+52,870 
+110,711 
+427,931 
+53.8 
+1,276,134 
+51.1 
+Mid-Continent 
+1,554 
+166,041 
+175,365 
+22.1 
+583,188 
+23.4 
+ArkLaTex 
+1,015 
+105,196 
+111,286 
+14.0 
+313,503 
+12.6 
+Gulf
+Coast 
+349 
+27,913 
+30,007 
+3.8 
+182,398 
+7.3 
+Permian
+Basin 
+7,115 
+7,214 
+49,904 
+6.3 
+138,946 
+5.6 
+Total 
+62,903 
+417,075 
+794,493 
+100.0 
+$ 
+2,494,169 
+100.0 
+Rocky
+Mountain Region . Nance
+Petroleum Corporation, a wholly owned subsidiary of St. Mary, has conducted
+operations in the Williston Basin in eastern Montana and western North Dakota
+since 1991. Our office in Billings, Montana has a 95 full-time person staff.
+We
+have expanded this area into the Greater Green River, Powder River, Big Horn
+and
+Wind River basins of Wyoming over the past three years. The largest growth
+in
+the region came in late 2002 and early 2003 with significant property
+acquisitions from Burlington Resources and Flying J. These transactions brought
+with them a tremendous acreage position that has precipitated additional growth
+in this region. 
+St. Mary
+spent $196.9 million in 2005 on exploration, development and acquisitions in
+the
+Rocky Mountain region, including Hanging Woman Basin, with $134.1 million of
+this directed towards drilling. The regional growth of reserves in 2005 was
+the
+most pronounced from the Bakken development in eastern Montana. Other organic
+growth has come from continued development of the Red River formation using
+smaller 3-D seismic surveys. We have successfully used 3-D seismic imaging
+to
+delineate structure and porosity development in this formation. The other
+significant drilling program is at our Hanging Woman Basin coalbed methane
+development in the northern Powder River Basin. In 2005, we spent $22.6 million
+drilling 131 wells and building infrastructure. Production from Hanging Woman
+Basin began in mid-December 2004, was 0.5 Bcf in 2005, and has exceeded our
+expectations. Because of potential permitting delays, dewatering time and low
+production rates per well, it will take a number of years to develop the field
+to the point of having production volumes that are meaningful to our total
+production. 
+Other
+recent transactions were the 2004 acquisition of Goldmark Engineering where
+we
+acquired a position in a mature oil field in the Big Horn Basin, and where
+we
+will focus on enhancement of wells that produce from the Tensleep formation.
+Our
+presence in Wyoming expanded in August 2005 when we acquired oil and gas
+properties in the Wind River, Powder River, and Greater Green River Basins
+for
+$37.1 million in cash. The allocation of the purchase price resulted in
+recording $43.9 million to proved and unproved oil and gas properties and a
+$7.0 million asset retirement obligation. This added approximately 32 BCFE
+of proved reserves as of the acquisition date. 
+Conventional
+oil and gas properties in the Rocky Mountain region accounted for 51 percent
+of
+our estimated proved reserves as of December 31, 2005, or 402.7 BCFE, 82
+percent of which are proved developed and 79 percent of which are
+oil. 
+20 
+Our
+capital budget for the Rocky Mountain region now represents the largest portion
+of our drilling budget at approximately $191 million for 2006. This budget
+is
+distributed over several key programs, including approximately $50 million
+in
+the Hanging Woman Basin where we have approximately 260 wells planned for the
+year. A risk of development at Hanging Woman Basin for 2006 will be the ability
+to successfully obtain the necessary regulatory approval of our water
+development plan on state and fee acreage for approximately 60 wells in Montana.
+Additionally, we have another 60 wells in Wyoming that the timing of drilling
+could be affected by considerations relating to the mating season for sage
+grouse. There are approximately 30 wells planned in the Bakken formation with
+total capital of $47 million. We are initiating a horizontal drilling program
+focusing in the Ratcliffe and Mission Canyon formations with $24 million of
+the
+budget allocated for the drilling of approximately 26 wells. The planned
+development of the Tensleep formation results in approximately $9 million of
+the
+budget being allocated to the Fourbear, Murphy Dome and Big Sand Draw fields.
+The remainder is planned for our Red River program and development in the
+Greater Green River Basin. 
+On
+average we have a high working interest in our wells in the Rocky Mountain
+region. In 425 wells we have a working interest greater than 90 percent.
+Including the Hanging Woman Basin development, we will be the operator of
+properties representing approximately 84 percent of our 2006 Rocky Mountain
+region capital budget. 
+Our
+reserves in the Bakken are approximately 69 BCFE, representing nearly nine
+percent of our total reserve volumes and ten percent of our PV-10 value. 
+The reserves in the Bakken are 83 percent oil. We have 92 wells
+predominately in Richland County, Montana and 70 wells concentrated in Mackenzie
+County, North Dakota. The Montana wells are produced from the Bakken
+dolomite while the North Dakota wells are mostly Bakken shale wells. The
+working interest in the Montana wells average 49 percent and the North Dakota
+ownership averages 61 percent. 
+Mid-Continent
+Region . 
+St. Mary has been active in the Mid-Continent region since 1973. Operations
+for the region are managed by our 45 full-time person office in Tulsa, Oklahoma.
+Our long history of operations and proprietary geologic knowledge enables us
+to
+sustain economic development and exploration programs despite periods of adverse
+industry conditions. We apply current technology in horizontal drilling,
+hydraulic fracturing and innovative well completion techniques to accelerate
+production and associated cash flow from the region’s tight gas reservoirs and
+developing plays. We are currently working to determine the best completion
+methods in our Wapanucka limestone, Cromwell sandstone and Woodford shale
+formations, commonly referred to as our Centrahoma area, located in Coal County,
+Oklahoma. We also attempt to benefit from the continuing consolidation of
+operators in the basin as we pursue attractive acquisition
+opportunities. 
+The
+Northeast Mayfield area is the largest concentration of our reserves and is
+located in Beckham County, Oklahoma on the western edge of the Anadarko Basin.
+This field represents 36.6 BCFE, or nearly five percent, of our total
+proved reserves and $110.0 million, or approximately four percent, of our total
+PV-10 value. Our average working interest in this field is 29 percent, and
+we have an interest in approximately 106 gross wells of which we operate
+41 percent. 
+Other
+significant fields in the Mid-Continent region are the Centrahoma field in
+Coal
+County, Oklahoma and the Constitution field in Jefferson County, Texas.
+Centrahoma represents five percent of total proved reserves and $82.8 million,
+or three percent, of total PV-10 value. The Constitution field represents two
+percent of total proved reserves and $98.7 million of PV-10 value. We operate
+approximately 85 percent of the wells we have an interest in located in
+the Centrahoma area. We do not act as operator in the Constitution field.
+Other significant fields in the Mid-Continent region are the Elk City field
+and
+the Southwest Mayfield field, both in Beckham County, Oklahoma, representing
+a
+total of two percent of proved reserves and three percent of total PV-10 value.
+We operate 14 percent of the wells in Elk City and 45 percent of the wells
+in
+Southwest Mayfield and have an average working interest of approximately 15
+and
+42 percent, respectively. 
+We
+have
+ongoing exploration and development programs in the Anadarko and Arkoma basins,
+principally located in Oklahoma. The Mid-Continent region accounts for 22
+percent of our estimated proved reserves as of December 31, 2005, or 175.4
+BCFE,
+79 percent of which are proved developed and 95 percent of which are natural
+gas. In 2005 our capital expenditures in the Mid-Continent were
+$135.6 million. We participated in drilling 91 gross wells in this region,
+87 percent of which were completed as producers. We operated 28 of these
+drilling projects. 
+21 
+St. Mary's
+development and exploration budget in the Mid-Continent region for 2006 totals
+$172 million, an increase of $64 million over 2005. The 2006 budget
+includes $66 million of planned drilling expenditures associated with 46
+budgeted Northeast Mayfield Atoka wells. Exploration efforts in 2004 and early
+2005 have built a foundation for this viable multi-year play in the Atoka and
+Granite Wash formations at Northeast Mayfield. The other area of focus in the
+Mid-Continent Region is the Centrahoma area where we plan to spend $42 million
+on 19 wells developing the Wapanucka limestone, Cromwell sandstone and Woodford
+shale formations. We plan to be the operator of properties representing
+approximately 74 percent of our capital budget in this region during 2006 and
+to
+utilize seven drilling rigs that we will operate throughout the
+year. 
+We
+have
+allocated $21 million of our 2006 drilling budget to low-to-medium-risk
+development in the Red Fork, Osborne, Cottage Grove and Cleveland formations.
+ArkLaTex
+Region .
+Our 21
+full-time person office in Shreveport, Louisiana manages St. Mary’s
+operations in the ArkLaTex region. The ArkLaTex region accounts for 14 percent
+of our estimated proved reserves as of December 31, 2005, or 111.3 BCFE, 56
+percent of which are proved developed and 95 percent of which are natural gas.
+Reserve growth in this region was derived primarily from recognition of the
+proved reserves from the Elm Grove field acquisition that we completed at the
+end of 2004. In 2006 we plan to spend $12 million on development at Elm Grove.
+This amount represents 41 percent of the total $66 million budget for the
+ArkLaTex region. The budget targets horizontal wells in the James, Glen Rose,
+Rodessa, and Pettet carbonate formations as well as vertical development in
+the
+Cotton Valley and Travis Peak formations at Terryville. Many of the Shreveport
+office’s successful exploration and development programs have derived from niche
+acquisitions. These acquisitions have provided access to strategic holdings
+of
+undeveloped acreage and proprietary packages of geologic and seismic data
+resulting in an active program of development and exploration. 
+Our
+holdings in the ArkLaTex region are comprised of interests in approximately
+714
+gross producing wells, including 139 wells we operated. We also hold interests
+in leases totaling approximately 157,000 gross acres and mineral servitudes
+totaling approximately 14,700 gross acres. Our capital expenditures in this
+region in 2005 were $44.0 million, including the effect of asset retirement
+obligations. 
+Our
+ownership at Elm Grove is six percent of our total proved reserves, representing
+$101.8 million of PV-10 value. We have an ownership interest in Elm Grove
+that is represented by 479 well locations, including PUD locations; with a
+working interest of up to 37 percent. Following our ownership in Elm Grove,
+the
+next most significant concentration of properties are the Spider and Box Church
+fields, which include a combined three percent or 24.1 BCFE of proved reserves
+and four percent of our total PV-10 value. We have working interests in 21
+gross
+wells in Spider and 38 gross wells in Box Church, all of which we operate.
+Gulf
+Coast Region .
+St. Mary’s presence in south Louisiana dates to the early 1900’s when our
+founders acquired a franchise property in St. Mary Parish on the shoreline
+of the Gulf of Mexico. These 24,914 acres of fee lands yielded $3.4 million
+of
+gross oil and gas royalty revenue in 2005. Our Gulf Coast region presence
+expanded as a result of the acquisition of King Ranch Energy, Inc. in 1999.
+Including the Louisiana fee lands, the Gulf Coast region accounts for four
+percent of our estimated proved reserves as of December 31, 2005, or 30.0 BCFE,
+87 percent of which are proved developed and 93 percent of which are
+natural gas. Of this 30.0 BCFE, 72 percent is onshore and 28 percent is
+offshore in the Gulf of Mexico and coastal Texas and Louisiana. We spent
+$36.8 million, including the effect of asset retirement obligations, on
+capital expenditures in 2005. 
+Our
+18
+full-time person team based in Houston, Texas, manages St. Mary’s diverse
+activities in our Gulf Coast and Permian Basin regions. Our exploration and
+development budget in the Gulf Coast region for 2006 is $67 million, which
+consists of planned activity both onshore and offshore projects in Texas and
+Louisiana as well as low to moderate risk direct hydrocarbon indicators in
+state
+and federal waters of the Gulf of Mexico. We plan to operate approximately
+42
+percent of the 2006 forecasted drilling projects. 
+22 
+The
+most
+significant field in the Gulf Coast region is the Judge Digby Field, located
+outside Baton Rouge, Louisiana, in Point Coupee Parish. As of the end of
+December 2005, this field represented slightly less than three percent of our
+total PV-10 value, with 11.6 BCFE of proved reserves. Production from the
+Judge Digby field totaled 3.3 BCFE in 2005. 
+Permian
+Basin Region . The
+Permian Basin area covers a significant portion of eastern New Mexico and
+western Texas and is one of the major producing basins in the United States.
+The
+basin includes hundreds of oil fields undergoing secondary and enhanced oil
+recovery projects. The use of 3-D seismic imaging of existing fields and
+advanced secondary recovery programs are substantially increasing oil
+recoveries. Our holdings in the Permian Basin resulted from a series of property
+acquisitions beginning in 1996. We believe that our Permian Basin operations
+provide us with a solid base of long-lived oil reserves and the potential for
+additional secondary recovery projects. In 2005, we spent $7.7 million on
+capital expenditures, including the effect of asset retirement obligations,
+in
+the Permian Basin region. This region accounted for 49.9 BCFE, or six percent
+of
+our proved reserves as of December 31, 2005. The PV-10 value associated with
+the
+Permian Basin was $139.0 million at year end. Our Permian reserves are 86
+percent proved developed and 86 percent oil. 
+The
+Parkway Delaware waterflood project, located in Eddy County, New Mexico,
+represents 17.9 BCFE or two percent of our proved reserves. The East Shugart
+Delaware Unit is a pilot waterflood located in Lea and Eddy Counties, New
+Mexico, that is analogous to the Parkway Delaware Unit and is comprised of
+17.5
+BCFE of proved reserves. Production from the Permian Basin properties
+represented 2.9 BCFE or three percent of total production for the Company in
+2005. 
+Our
+Permian Basin capital expenditures budget for 2006 is $4 million. We plan
+to drill three infill wells at Parkway Delaware during 2006. 
+Acquisitions
+and Divestitures 
+We
+spent
+a total of $87.8 million on acquisitions of proved and unproved oil and gas
+properties in 2005. The two most significant acquisitions, Agate Petroleum,
+Inc., and properties from Wold Oil Properties, Inc., accounted for $77.1
+million. We also made several smaller acquisitions in 2005. We purchased a
+total
+of 49.8 BCFE of proved reserves in 2005. 
+Significant
+acquisitions prior to 2005 include the 2004 acquisitions of oil and gas
+properties from Goldmark Engineering, Inc., in the Rocky Mountain region and
+from Border Company in the ArkLaTex region. In January 2003 we acquired oil
+and
+gas properties in the Rocky Mountain region from Flying J Oil & Gas, Inc.
+23 
+Reserves 
+The
+following table presents summary information with respect to the estimates
+of
+our proved oil and gas reserves for each of the years in the three year period
+ended December 31, 2005. The table includes reserves prepared by independent
+petroleum engineering firms, Ryder Scott Company and Netherland, Sewell &
+Associates, Inc., and us. For the periods presented, Ryder Scott Company and
+Netherland, Sewell & Associates, Inc., evaluated properties representing a
+minimum of 80 percent of the total PV-10 value of our reserves. The proved
+oil
+and gas reserves prepared by Netherland Sewell in 2004 and 2005 consist of
+the
+coalbed methane development at Hanging Woman Basin as well as our non-operated
+interest at Atlantic Rim. The PV-10 values shown in the following table are
+not
+intended to represent the current market value of the estimated proved oil
+and
+gas reserves owned by St. Mary. Neither prices nor costs have been
+escalated. You should read the following table along with the section entitled
+“Risk Factors - Risks Related to Our Business - Estimates of oil and gas
+reserves are not precise.” 
+As
+of December 31, 
+Proved
+Reserves Data: 
+2005 
+2004 
+2003 
+Oil
+(MBbl) 
+62,903 
+56,574 
+47,787 
+Gas
+(MMcf) 
+417,075 
+319,196 
+307,024 
+MMCFE 
+794,493 
+658,638 
+593,744 
+PV-10
+value (in thousands) 
+$ 
+2,494,169 
+$ 
+1,501,123 
+$ 
+1,278,165 
+Standardized
+measure of discounted 
+future
+net cash flows (in thousands) 
+$ 
+1,712,298 
+$ 
+1,033,938 
+$ 
+859,956 
+Proved
+developed reserves 
+82 % 
+85 % 
+89 % 
+Reserve
+replacement - including sales 
+256 % 
+186 % 
+234 % 
+Reserve
+replacement - excluding sales 
+256 % 
+190 % 
+293 % 
+Reserve
+life (years) (1) 
+9.1 
+8.7 
+7.7 
+________________ 
+(1) 
+Reserve
+life represents the estimated proved reserves at the dates indicated
+divided by actual production for the preceding 12-month
+period. 
+24 
+Production 
+The
+following table summarizes the average volumes and realized prices, including
+and excluding the effects of hedging, of oil and gas produced from properties
+in
+which St. Mary held an interest during the periods indicated. Also
+presented is a production cost per MCFE summary for the Company. 
+Years
+Ended December 31, 
+2005 
+2004 
+2003 
+Operating
+data: 
+Net
+production: 
+Oil
+(MBbl) 
+5,927 
+4,799 
+4,541 
+Gas
+(MMcf) 
+51,801 
+46,598 
+49,663 
+MMCFE 
+87,363 
+75,393 
+76,909 
+Average
+net daily production: 
+Oil
+(Bbl) 
+16,238 
+13,113 
+12,441 
+Gas
+(Mcf) 
+141,922 
+127,316 
+136,062 
+MCFE 
+239,352 
+205,992 
+210,709 
+Average
+realized sales price, excluding the effects of hedging: 
+Oil
+(per Bbl) 
+$ 
+53.18 
+$ 
+39.77 
+$ 
+29.40 
+Gas
+(per Mcf) 
+$ 
+8.08 
+$ 
+5.85 
+$ 
+5.12 
+Per
+MCFE 
+$ 
+8.40 
+$ 
+6.15 
+$ 
+5.04 
+Average
+realized sales price, including the effects of hedging: 
+Oil
+(per Bbl) 
+$ 
+50.93 
+$ 
+32.53 
+$ 
+26.96 
+Gas
+(per Mcf) 
+$ 
+7.90 
+$ 
+5.52 
+$ 
+4.89 
+Per
+MCFE 
+$ 
+8.14 
+$ 
+5.48 
+$ 
+4.75 
+Production
+costs per MCFE: 
+Lease
+operating expense 
+$ 
+0.99 
+$ 
+0.81 
+$ 
+0.77 
+Transportation
+expense 
+$ 
+0.09 
+$ 
+0.10 
+$ 
+0.09 
+Production
+taxes 
+$ 
+0.56 
+$ 
+0.36 
+$ 
+0.29 
+Productive
+Wells 
+As
+of
+December 31, 2005, we had working interests in 1,722 gross (843 net) productive
+oil wells and 2,750 gross (679 net) productive gas wells. Productive wells
+are
+either producing wells or wells capable of commercial production although
+currently shut in. One or more completions in the same wellbore are counted
+as
+one well. A well is categorized under state reporting regulations as an oil
+well
+or a gas well based upon the ratio of gas to oil produced when it first
+commenced production, and such designation may not be indicative of current
+production. 
+25 
+Drilling
+Activity 
+All
+of
+our drilling activities are conducted on a contract basis with independent
+drilling contractors. We do not own any drilling equipment. The following table
+sets forth the wells drilled and recompleted in which St. Mary participated
+during each of the three years indicated: 
+Years
+Ended December 31, 
+2005 
+2004 
+2003 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development: 
+Oil 
+83 
+38.09 
+50 
+18.08 
+36 
+14.88 
+Gas 
+379 
+152.69 
+180 
+53.23 
+140 
+43.79 
+Non-productive 
+29 
+9.12 
+36 
+14.29 
+37 
+15.98 
+491 
+199.90 
+266 
+85.60 
+213 
+74.65 
+Exploratory: 
+Oil 
+8 
+1.91 
+11 
+9.71 
+7 
+3.03 
+Gas 
+5 
+0.86 
+83 
+43.65 
+14 
+7.20 
+Non-productive 
+5 
+2.32 
+8 
+2.84 
+7 
+4.40 
+18 
+5.09 
+102 
+56.20 
+28 
+14.63 
+Farmout
+or non-consent 
+18 
+- 
+5 
+- 
+10 
+- 
+Total
+(1) 
+527 
+204.99 
+373 
+141.80 
+251 
+89.28 
+________________ 
+(1) 
+Does
+not include nine, seven, and 15 gross wells completed on St. Mary's
+fee lands during 2005, 2004 and 2003, respectively, in which we
+have only
+a royalty interest. 
+26 
+Acreage 
+The
+following table sets forth the gross and net acres of developed and undeveloped
+oil and gas leases, fee properties, mineral servitudes and lease options held
+by
+St. Mary as of December 31, 2005. Undeveloped acreage includes
+leasehold interests that may already have been classified as containing proved
+undeveloped reserves. 
+Developed
+Acres (1) 
+Undeveloped
+Acres (2) 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Arkansas
+3,365 
+420 
+207 
+68 
+3,572 
+488 
+Colorado
+2,885 
+2,470 
+24,832 
+13,914 
+27,717 
+16,384 
+Louisiana
+127,636 
+44,875 
+32,199 
+13,232 
+159,835 
+58,107 
+Mississippi 
+3,335 
+467 
+2,610 
+1,361 
+5,945 
+1,828 
+Montana
+58,062 
+36,668 
+446,549 
+297,671 
+504,611 
+334,339 
+New
+Mexico 
+5,600 
+2,658 
+1,320 
+1,187 
+6,920 
+3,845 
+North
+Dakota 
+174,333 
+94,791 
+172,955 
+103,896 
+347,288 
+198,687 
+Oklahoma 
+281,996 
+81,336 
+44,270 
+26,338 
+326,266 
+107,674 
+Texas
+128,265 
+34,429 
+48,417 
+24,689 
+176,682 
+59,118 
+Utah
+(3) 
+480 
+115 
+11,472 
+4,091 
+11,952 
+4,206 
+Wyoming 
+139,801 
+92,424 
+389,870 
+224,611 
+529,671 
+317,035 
+Other
+(4) 
+2,281 
+985 
+4,144 
+1,265 
+6,425 
+2,250 
+928,039 
+391,638 
+1,178,845 
+712,323 
+2,106,884 
+1,103,961 
+Louisiana
+Fee Properties 
+9,944 
+9,944 
+14,970 
+14,970 
+24,914 
+24,914 
+Louisiana
+Mineral Servitudes 
+10,173 
+5,740 
+4,490 
+4,128 
+14,663 
+9,868 
+20,117 
+15,684 
+19,460 
+19,098 
+39,577 
+34,782 
+Total
+948,156 
+407,322 
+1,198,305 
+731,421 
+2,146,461 
+1,138,743 
+________________ 
+(1) 
+Developed
+acreage is acreage assigned to producing wells for the spacing unit
+of the
+producing formation. Developed acreage in certain of St. Mary's
+properties that include multiple formations with different well spacing
+requirements may be considered undeveloped for certain formations,
+but
+have only been included as developed acreage in the presentation
+above.
+(2) 
+Undeveloped
+acreage is lease acreage on which wells have not been drilled or
+completed
+to a point that would permit the production of commercial quantities
+of
+oil and gas, regardless of whether such acreage contains estimated
+proved
+reserves. 
+(3) 
+St. Mary holds
+an
+overriding royalty interest in an additional 40,100 gross acres in
+Utah. 
+(4) 
+Includes interests
+in
+Alabama, Kansas, Nebraska, Nevada and South
+Dakota. 
+27 
+ITEM
+3. 
+LEGAL
+PROCEEDINGS 
+From
+time
+to time, we may be involved in litigation relating to claims arising out of
+our
+operations in the normal course of business. As of the date of this report,
+no
+legal proceedings are pending against us that we believe individually or
+collectively could have a material adverse effect upon our financial condition
+or results of operations. 
+ITEM
+4. 
+SUBMISSION OF MATTERS TO A VOTE OF SECURITY
+HOLDERS 
+There
+were no matters submitted to a vote of our security holders during the fourth
+quarter of 2005. 
+Item
+4A. 
+EXECUTIVE OFFICERS OF THE REGISTRANT 
+The
+following table sets forth the names, ages and positions held by St. Mary’s
+executive officers. The ages of the executive officers are as of February 15,
+2006. 
+Name 
+Age 
+Position 
+Mark A. Hellerstein 
+53 
+Chairman of the Board, President and
+Chief
+Executive Officer 
+Douglas W. York 
+44 
+Executive Vice President and Chief Operating
+Officer 
+Robert L. Nance 
+69 
+Senior Vice President and President
+and Chief
+Executive Officer of Nance Petroleum Corporation, a wholly-owned
+subsidiary of St. Mary 
+Jerry R. Schuyler 
+50 
+Senior Vice President and Regional
+Manager 
+Kevin E. Willson 
+49 
+Senior Vice President and Regional
+Manager 
+Robert T. Hanley 
+59 
+Vice President - Investor Relations
+and
+Management Reporting 
+David W. Honeyfield 
+39 
+Vice President - Chief Financial Officer,
+Treasurer and Secretary 
+Milam Randolph Pharo 
+53 
+Vice President - Land and Legal 
+Paul M. Veatch 
+39 
+Vice President - General Manager,
+ArkLaTex 
+Garry A. Wilkening 
+55 
+Vice President - Administration and
+Controller 
+Each
+executive officer has held his respective position during the past five years,
+except as follows: 
+Mark
+A.
+Hellerstein was appointed Chairman of the Board in September 2002. 
+Douglas
+W. York was appointed Executive Vice President and Chief Operating Officer
+in
+September 2003. Mr. York served as Vice President - Acquisitions and Reservoir
+Engineering from 1996 to September 2003. On December 15, 2005, Mr. York
+notified St. Mary that it is his intention to resign from the offices of
+Executive Vice President and Chief Operating Officer during the first quarter
+of
+2006. 
+Robert
+L.
+Nance was appointed Senior Vice President in March 2001. 
+Jerry
+R.
+Schuyler joined St. Mary in December 2003 as Senior Vice President and
+Regional Manager of the Gulf Coast region. From November 2001 to July 2002,
+Mr. Schuyler was Senior Vice President and General Manager - Eastern
+Onshore Division for Dominion Exploration & Production, Inc., where he
+managed all operations and exploration for Dominion’s Gulf Coast and eastern
+onshore U.S. regions. From March 2000 to November 2001, Mr. Schuyler was Senior
+Vice President and General Manager of Dominion’s Onshore U.S. Division, where he
+managed all operations and exploration for all of Dominion’s onshore U.S.
+regions. 
+Kevin
+E.
+Willson was appointed Senior Vice President and Regional Manager in November
+2003. Mr. Willson served as Vice President - Mid-Continent
+Exploration/Production from October 1998 to November 2003. 
+Robert
+T.
+Hanley was appointed Vice President - Investor Relations and Management
+Reporting in April 2003. Mr. Hanley served as Vice President - Business
+Development from July 2000 to April 2003. 
+28 
+David
+W.
+Honeyfield was appointed Chief Financial Officer in May 2005. Mr. Honeyfield
+joined St. Mary in May 2003 as Vice President - Finance, Treasurer and
+Secretary. Prior to joining St. Mary, Mr. Honeyfield was Controller and
+Chief Accounting Officer of Cimarex Energy Co. from September 2002 to May 2003
+and Controller and Chief Accounting Officer of Key Production Company, Inc.,
+which was acquired by Cimarex in September 2002. Prior to joining Key Production
+Company in April 2002, Mr. Honeyfield was a senior audit manager with
+Arthur Andersen LLP in Denver. 
+Paul
+M.
+Veatch was determined by the Board of Directors to be an executive officer
+of
+the Company in February 2006. Mr. Veatch was
+appointed Vice President and General Manager of the ArkLaTex Region in September
+2004. Mr. Veatch joined St. Mary in April 2001 and has served as Regional
+Acquisition Engineer & Manager of Engineering. Prior to joining St. Mary,
+Mr. Veatch had been with Burlington Resources in Denver, Colorado, and Midland,
+Texas. 
+Executive
+officers generally are elected at the regular meeting of the Board immediately
+following the annual stockholders meeting, to serve for the ensuing year or
+until their successors are duly qualified and elected. The executive officers
+of
+St. Mary do not have fixed terms and choose to serve at the discretion of the
+Board of Directors. Any officer elected or appointed by the Board may be removed
+by the Board with or without cause, subject to any contractual rights of the
+person so removed. 
+Mr.
+Hellerstein has an employment agreement with St. Mary. The agreement is in
+effect until June 30, 2007. Upon any termination of the employment of Mr.
+Hellerstein by St. Mary before June 30, 2007, for any reason other than
+death, disability or misconduct by Mr. Hellerstein, St. Mary is generally
+obligated to continue to pay his base salary, additional bonus and incentive
+compensation, and other fringe benefits until June 30, 2007. 
+There
+are
+no family relationships between any executive officer and any other executive
+officer or director. There are no arrangements or understandings between any
+officer and any other person pursuant to which that officer was
+elected. 
+PART
+II 
+ITEM 5. 
+MARKET
+FOR REGISTRANT'S
+COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES
+OF EQUITY
+SECURITIES 
+Market
+Information .
+St. Mary's common stock is currently traded on the New York Stock Exchange
+under the symbol SM. The range of high and low sales prices for the quarterly
+periods in 2005 and 2004, as reported by the New York Stock Exchange and
+adjusted for the two-for-one stock split effected in the form of a stock
+dividend which was distributed on March 31, 2005 to shareholders of record
+as of
+March 21, 2005, is set forth below: 
+Quarter
+Ended 
+High 
+Low 
+December
+31, 2005 
+$ 
+41.14 
+$ 
+30.52 
+September
+30, 2005 
+37.80 
+28.89 
+June
+30, 2005 
+30.45 
+21.46 
+March
+31, 2005 
+26.73 
+19.45 
+December
+31, 2004 
+$ 
+21.50 
+$ 
+18.56 
+September
+30, 2004 
+20.07 
+15.88 
+June
+30, 2004 
+18.60 
+15.90 
+March
+31, 2004 
+17.07 
+13.87 
+Holders .
+As of
+February 15, 2006, the number of record holders of St. Mary's common stock
+was 135. Management believes, after inquiry, that the number of beneficial
+owners of our common stock is in excess of 7,100. 
+Dividends .
+St. Mary has paid cash dividends to stockholders every year since 1940.
+Annual dividends of $0.05 per share were paid in each of the years 1998 through
+2004. An annual dividend of $0.10 per share was paid in 2005. We expect that
+our
+practice of paying dividends on our common stock will continue, although the
+payment of future dividends will continue to depend on our earnings, capital
+requirements, financial condition and other factors. In addition, the payment
+of
+dividends is subject to covenants in our credit facility, including the
+requirement that we maintain certain levels of stockholders’ equity and the
+limitation of our annual dividend rate to no more than $0.25 per share.
+Dividends are currently paid on a semi-annual basis. Dividends paid totaled
+$5.7
+million in 2005 and $2.8 million in 2004. 
+29 
+Restricted
+Shares. 
+Aside
+from Rule 144 restrictions on shares for insiders, shares subject to transfer
+restrictions under the provisions of the Employee Stock Purchase Plan and
+restricted shares issued under the Non-Employee Director Stock Compensation
+Plan, St. Mary has no restricted shares outstanding as of December 31,
+2005. 
+Issuer
+Purchases of Equity Securities. 
+St. Mary repurchased a total of 1,175,282 shares of its common stock during
+2005. 
+Equity
+Compensation Plans .
+St. Mary has a stock option plan, a restricted stock plan, an incentive
+stock option plan, an employee stock purchase plan, and a non-employee director
+stock compensation plan under which options and shares of St. Mary common
+stock are authorized for grant or issuance as compensation to eligible
+employees, consultants and members of the Board of Directors. Our stockholders
+have approved each of these plans. See Note 7 - Compensation Plans in the Notes
+to Consolidated Financial Statements included in Part IV, Item 15 of this report
+for further information about the material terms of these plans. The following
+table is a summary of the shares of common stock authorized for issuance under
+our equity compensation plans as of December 31, 2005: 
+(
+a
+) 
+(
+b
+) 
+(
+c
+) 
+Plan
+Category 
+Number
+of securities to be issued upon exercise of outstanding options,
+warrants
+and rights 
+Weighted-average
+exercise price of outstanding options, warrants and rights 
+Number
+of securities remaining available for future issuance under equity
+compensation plans (excluding securities reflected in column
+(a) 
+Stock
+Option Plan and Incentive Stock Option Plan 
+4,698,243 
+$ 
+12.21 
+- 
+(2 
+) 
+Restricted
+Stock Plan 
+632,809 
+N/A 
+1,063,617 
+(2 
+) 
+Employee
+Stock Purchase Plan 
+- 
+- 
+1,655,391 
+(1 
+) 
+Non-Employee
+Director Stock Compensation Plan 
+- 
+N/A 
+20,874 
+Equity
+compensation plans not approved by security holders 
+-
+-
+-
+Total 
+5,331,052 
+$ 
+12.21 
+2,739,882 
+______________ 
+(1) 
+Under
+the St. Mary Land & Exploration Company Employee Stock Purchase Plan
+(“the ESPP”), eligible employees may purchase shares of the Company’s
+common stock through payroll deductions of up to 15 percent of their
+eligible compensation. The purchase price of the stock is 85 percent
+of
+the lower of the fair market value of the stock on the first or last
+day
+of the purchase period, and shares issued under the ESPP are restricted
+for a period of 18 months from the date issued. The ESPP is intended
+to
+qualify under Section 423 of the Internal Revenue
+Code. 
+(2)
+There
+is a common pool of shares available for the Stock Option, Incentive
+Stock
+Option, and Restricted Stock plans. 
+30 
+The
+following table provides information about purchases by the Company during
+the
+quarter and year ended December 31, 2005, of shares of the Company’s
+common stock, which is the sole class of equity securities registered by the
+Company pursuant to Section 12 of the Exchange Act. 
+ISSUER
+PURCHASES OF EQUITY SECURITIES 
+Total
+Number of Shares Purchased in 2005 
+Average
+Price Paid per Share 
+Total
+Number of Shares Purchased as Part of Publicly Announced
+Program (1) 
+Maximum
+Number of Shares that May Yet be Purchased Under the Program (1) 
+January
+1, 2005 - 
+March
+31, 2005 
+- 
+$ 
+- 
+- 
+5,021,400 
+April
+1, 2005 - 
+June
+30, 2005 
+1,157,810 
+$ 
+24.48 
+1,157,810 
+3,863,590 
+July
+1, 2005 - 
+September
+30, 2005 
+- 
+$ 
+- 
+- 
+3,863,590 
+October
+1, 2005 - 
+October
+31, 2005 
+17,472 
+$ 
+31.72 
+17,472 
+3,846,118 
+November
+1, 2005 - 
+November
+30, 2005 
+- 
+$ 
+- 
+- 
+3,846,118 
+December
+1, 2005 - 
+December
+31, 2005 
+- 
+$ 
+- 
+- 
+3,846,118 
+Total
+October 1, 2005 - 
+December
+31, 2005 
+17,472 
+$ 
+31.72 
+17,472 
+3,846,118 
+Total 
+1,175,282 
+$ 
+24.51 
+1,175,282 
+3,846,118 
+(1) 
+In
+August 2004 the Company announced that its Board of Directors authorized
+the re-initiation of the Company’s stock repurchase program and approved
+an increase in the number of shares that may be repurchased under
+the
+original authorization approved in August 1998 to 6,000,000 as of
+the
+effective date of the resolution and as adjusted for the March 2005
+two-for-one stock split. The shares may be repurchased from time
+to time
+in open market transactions or privately negotiated transactions,
+subject
+to market conditions and other factors, including certain provisions
+of
+St. Mary’s existing bank credit facility agreement and compliance with
+securities laws. Stock repurchases may be funded with existing cash
+balances, internal cash flow and borrowings under St. Mary’s bank credit
+facility. The stock repurchase program may be suspended or discontinued
+at
+any time. 
+The
+payment of dividends and repurchases of stock are subject to covenants in our
+bank credit facility, including the requirement that we maintain certain levels
+of stockholders’ equity and we limit our annual dividend rate to no more than
+$0.25 per share. 
+31 
+ITEM
+6. SELECTED
+FINANCIAL DATA 
+The
+following table sets forth supplemental selected financial and operating data
+for St. Mary as of the dates and for the periods indicated. The financial
+data for each of the five years presented were derived from the consolidated
+financial statements of St. Mary. The following data should be read in
+conjunction with "Management's Discussion and Analysis of Financial Condition
+and Results of Operations," which includes a discussion of factors materially
+affecting the comparability of the information presented, and in conjunction
+with St. Mary's consolidated financial statements included in this
+report. 
+Years
+Ended December 31, 
+2005 
+2004 
+2003 
+2002 
+2001 
+(In
+thousands, except per share data) 
+Total
+operating revenues 
+$ 
+739,590 
+$ 
+433,099 
+$ 
+393,708 
+$ 
+196,305 
+$ 
+207,469 
+Income
+before cumulative effect of change in accounting principle 
+$ 
+151,936 
+$ 
+92,479 
+$ 
+90,140 
+$ 
+27,560 
+$ 
+40,459 
+Net
+income per share: 
+Basic 
+$ 
+2.67 
+$ 
+1.60 
+$ 
+1.53 
+$ 
+0.49 
+$ 
+0.72 
+Diluted 
+$ 
+2.33 
+$ 
+1.44 
+$ 
+1.40 
+$ 
+0.49 
+$ 
+0.71 
+Total
+Assets at year end 
+$ 
+1,268,747 
+$ 
+945,460 
+$ 
+735,854 
+$ 
+537,139 
+$ 
+436,989 
+Long-term
+obligations: 
+Line
+of credit 
+$ 
+- 
+$ 
+37,000 
+$ 
+11,000 
+$ 
+14,000 
+$ 
+64,000 
+Convertible
+Notes 
+$ 
+99,885 
+$ 
+99,791 
+$ 
+99,696 
+$ 
+99,601 
+-
+Cash
+dividends declared and paid per common share 
+$ 
+0.10 
+$ 
+0.05 
+$ 
+0.05 
+$ 
+0.05 
+$ 
+0.05 
+32 
+Supplemental
+Selected Financial and Operational Data: 
+Years
+Ended December 31, 
+2005 
+2004 
+2003 
+2002 
+2001 
+(In
+thousands, except per volume data) 
+Balance
+Sheet Data: 
+Total
+working capital 
+$ 
+4,937 
+$ 
+12,035 
+$ 
+3,101 
+$ 
+2,050 
+$ 
+34,000 
+Total
+stockholders’ equity 
+$ 
+569,320 
+$ 
+484,455 
+$ 
+390,653 
+$ 
+299,513 
+$ 
+286,117 
+Weighted-average
+shares
+outstanding: 
+Basic 
+56,907 
+57,702 
+62,467 
+55,713 
+55,946 
+Diluted 
+66,894 
+66,894 
+71,069 
+56,782 
+57,110 
+Reserves: 
+Oil
+(Bbls) 
+62,903 
+56,574 
+47,787 
+36,119 
+23,669 
+Gas
+(Mcf) 
+417,075 
+319,196 
+307,024 
+274,172 
+241,231 
+MCFE 
+794,493 
+658,638 
+593,744 
+490,887 
+383,247 
+Production
+and Operational: 
+Oil
+and gas production revenues, including hedging 
+$ 
+711,005 
+$ 
+413,318 
+$ 
+365,114 
+$ 
+185,670 
+$ 
+203,973 
+LOE
+and production taxes 
+$ 
+142,873 
+$ 
+95,518 
+$ 
+88,509 
+$ 
+50,839 
+$ 
+55,000 
+DD&A 
+$ 
+132,758 
+$ 
+92,223 
+$ 
+81,960 
+$ 
+54,432 
+$ 
+51,346 
+General
+and administrative 
+$ 
+32,756 
+$ 
+22,004 
+$ 
+21,197 
+$ 
+13,683 
+$ 
+11,762 
+Production
+Volumes: 
+Oil
+(Bbls) 
+5,927 
+4,799 
+4,541 
+2,815 
+2,434 
+Gas
+(Mcf) 
+51,801 
+46,598 
+49,663 
+38,164 
+39,491 
+MCFE 
+87,363 
+75,393 
+76,909 
+55,055 
+54,093 
+Realized
+Price - pre hedging: 
+Per
+Bbl 
+$ 
+53.18 
+$ 
+39.77 
+$ 
+29.40 
+$ 
+24.67 
+$ 
+24.08 
+Per
+Mcf 
+$ 
+8.08 
+$ 
+5.85 
+$ 
+5.12 
+$ 
+3.10 
+$ 
+4.22 
+Realized
+Price - net of hedging: 
+Per
+Bbl 
+$ 
+50.93 
+$ 
+32.53 
+$ 
+26.96 
+$ 
+25.34 
+$ 
+23.29 
+Per
+Mcf 
+$ 
+7.90 
+$ 
+5.52 
+$ 
+4.89 
+$ 
+3.00 
+$ 
+3.73 
+Expense
+per MCFE: 
+LOE 
+$ 
+0.99 
+$ 
+0.81 
+$ 
+0.77 
+$ 
+0.66 
+$ 
+0.75 
+Transportation 
+$ 
+0.09 
+$ 
+0.10 
+$ 
+0.09 
+$ 
+0.06 
+$ 
+0.04 
+Production
+taxes 
+$ 
+0.56 
+$ 
+0.36 
+$ 
+0.29 
+$ 
+0.20 
+$ 
+0.23 
+DD&A 
+$ 
+1.52 
+$ 
+1.22 
+$ 
+1.07 
+$ 
+0.99 
+$ 
+0.95 
+General
+and administrative 
+$ 
+0.37 
+$ 
+0.29 
+$ 
+0.28 
+$ 
+0.25 
+$ 
+0.22 
+Cash
+Flow: 
+From
+operations 
+$ 
+409,379 
+$ 
+237,162 
+$ 
+204,319 
+$ 
+141,709 
+$ 
+127,492 
+For
+investing 
+$ 
+(339,779 
+) 
+$ 
+(247,006 
+) 
+$ 
+(196,939 
+) 
+$ 
+(180,931 
+) 
+$ 
+(159,075 
+) 
+From
+(for) financing 
+$ 
+(61,093 
+) 
+$ 
+1,435 
+$ 
+(3,707 
+) 
+$ 
+46,260 
+$ 
+29,080 
+33 
+ITEM
+7. MANAGEMENT’S
+DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
+OPERATIONS 
+This
+discussion includes forward-looking statements. Please refer to “Cautionary
+Information about Forward-Looking Statements” in Part I, Item 1 of this Form
+10-K for important information about these types of statements. 
+Overview
+of the Company 
+General
+Overview 
+We
+are an
+independent energy company focused on the exploration, exploitation, acquisition
+and production of natural gas and crude oil in the United States. We earn
+greater than 95 percent of our revenues and generate our cash flows from
+operations primarily from the sale of produced natural gas and crude oil. Our
+oil and gas reserves and operations are concentrated primarily in various Rocky
+Mountain Basins, including the Williston, Big Horn, Wind River, Powder River
+and
+Greater Green River Basins; the Mid-Continent Anadarko and Arkoma Basins; the
+Permian Basin, the tight sandstone reservoirs of East Texas and North Louisiana;
+and onshore Gulf Coast and offshore Gulf of Mexico. We have developed a balanced
+portfolio of proved reserves, development drilling opportunities and
+non-conventional gas prospects. 
+As
+of
+December 31, 2005, we had estimated proved reserves of 794.5 BCFE, with PV-10
+value of $2.5 billion. An after income tax value of $1.7 billion
+is represented by the standardized measure calculation in Note 12 of Part
+IV, Item 15 of this report. Our reserves are 82 percent proved developed and
+53
+percent natural gas. The $2.5 billion PV-10 value for proved reserves is a
+66
+percent increase over the prior year. This amount reflects a 21 percent
+increase in proved reserves, a 41 percent increase in the adjusted oil reserve
+pricing to $61.04 per Bbl, and a 63 percent increase in the adjusted gas
+reserve pricing to $10.08 per Mcf as used in the calculation. Total production
+of oil and natural gas increased in 2005 by 16 percent to 87.4 BCFE.
+Approximately 59 percent of our total production volumes are derived from sales
+of natural gas. 
+Reserve
+Replacement and Growth 
+Like
+all
+oil and gas exploration and production companies, we face the challenge of
+natural production declines of oil and natural gas resources. An oil and gas
+exploration and production company depletes part of its asset base with each
+unit of oil and gas it produces. Historically, we have been able to grow our
+production despite this natural decline by adding more reserves through
+acquisitions and drilling than we produce. Future growth will depend on our
+ability to continue to add reserves in excess of production. 
+We
+believe growth in net asset value per share drives appreciation in our stock
+price. Our challenge is to grow net asset value per share. Our goal is to
+replace 200 percent of annual production with new reserves and grow production
+by ten to 15 percent per year. Please see the additional discussion of oil
+and
+gas reserve quantities in our critical accounting policies and estimates
+section. In 2005 we replaced 256 percent of our reserves at a finding cost
+of
+$1.88 per MCFE. Finding cost and reserve replacement percentage are defined
+in
+the glossary at the end of Part I, Item 1 of this report. We believe annual
+reserve replacement and finding cost amounts are important analytical measures
+that are widely used by investors and industry peers in evaluating the
+performance of oil and gas companies. While single year measurements have some
+meaning in terms of a trend, we believe that evaluating these items over an
+extended period of time is a better indication of performance. You should note
+that aberrations, causing both relatively good and bad results, will occur
+over
+short intervals of time. Our three-year reserve replacement percentage,
+excluding sales, is 247 percent and our three-year average finding cost is
+$1.64
+per MCFE. Our average finding cost was lower in 2005 than in 2004 despite an
+overall increase in the cost associated with drilling and an overall increase
+in
+the price of acquiring developed reserves. The relative finding cost decrease
+in
+2005 as compared to 2004 was the result of a shift in activity in the
+Mid-Continent region from exploratory activities in the deeper Morrow and
+Springer formations of the Northeast Mayfield area to development of the
+shallower, lower-cost, Atoka and Granite Wash formations. Also, our finding
+cost
+per MCFE decreased because we recorded a relative increase in proved undeveloped
+reserves. Our overall percentage of PUD reserves increased from 15 percent
+at
+the end of 2004 to 18 percent at the end of 2005. Of the 47.2 BCFE increase
+in
+the PUD reserves, 37.8 BCFE came from the ArkLaTex region. We also saw an
+increase in PUD reserves of 21.1 BCFE in the Mid-Continent region related
+to the activity at Northeast Mayfield. PUD reserves decreased as a result of
+being converted to proved developed reserves or decreased because remaining
+PUD
+reserves were not supported by newly proven developed reserves. PUD reserves
+decreased 10.8 BCFE in the Permian region because of these factors. We expect
+future finding costs per MCFE to increase as the overall cost of drilling a
+well
+in our core areas has approximately doubled in the last three years. Finding
+costs are comparison measures used to evaluate the effectiveness of an oil
+and
+gas company’s reserve replacement program and a snapshot in time of its expected
+future profitability. 
+34 
+Sustainability
+in our business is dependent on the ability to create new ideas and new value
+year after year. The challenges we face are becoming increasingly difficult
+as
+North American oil and gas production continues to decline and other exploration
+and production companies compete for available reserves. We believe we have
+a
+formula for meeting these challenges. We have placed talented geoscientists,
+engineers and landmen in each of our regional offices where their experience
+and
+knowledge of the local areas can be fully utilized. They are supported by a
+strong balance sheet and fiscal and operating discipline. Even so, we are
+subject to similar constraints as other companies in the exploration and
+production industry. Limitations to future growth will be based on overall
+availability of additional qualified personnel and the availability of drilling
+rigs to grow our drilling programs. We believe that we have sufficient staff
+levels and capital resources and that we will have appropriate access to
+drilling rigs to execute our $500 million drilling budget for 2006. 
+Stock
+Split 
+In
+March 2005 the Board of Directors approved a two-for-one stock split in the
+form of a stock dividend whereby one additional common share of stock was
+distributed for each common share outstanding. The stock dividend was
+distributed on March 31, 2005, to shareholders of record as of the
+close of business on March 21, 2005. All share and per share amounts
+for all prior periods presented within this report have been restated to reflect
+this stock split. 
+Effects
+of Hurricanes Katrina and Rita 
+Certain
+properties in our Gulf Coast region were affected by Hurricanes Katrina and
+Rita. These two events did not have a material adverse effect on our financial
+position or results of operations. We did not sustain any direct damage from
+Hurricane Katrina, but we did sustain damage from Hurricane Rita. Approximately
+1 BCFE of production was shut in during 2005 and our operated production
+platform at Vermilion Block 273 was sheared off its base. We believe our
+insurance coverage for property damage resulting from Hurricane Rita is
+sufficient to cover the property damage losses we incurred. Our 2005
+results of operations include the cost of applicable insurance deductibles
+related to our insurance coverage. Approximately 41 MCFED of production remained
+shut in as of February 15, 2006. Restoration of the remaining shut-in production
+is largely dependent on repairs to transportation and processing facilities
+which are owned and operated by other operators and facility owners.
+Potential
+revenue impacts caused by shut-in production from the hurricanes were offset
+by
+a sudden and significant increase in oil and gas prices caused by
+hurricane-related supply disruptions for both crude oil and natural gas. We
+benefited from higher commodity prices in all of our production areas during
+the
+month of September and October. The operations analysis later in this discussion
+reflects the result of higher prices for the year ended
+December 31, 2005. 
+Oil
+and Gas Prices 
+Results
+of our operations and financial condition are significantly affected by oil
+and
+natural gas commodity prices, which can fluctuate dramatically. In 2005, oil
+and
+gas producers benefited from high oil and gas commodity prices. Increased prices
+of natural gas were caused by numerous conditions. Finite storage capacity
+in
+North America, a limited import market and fluctuations in domestic demand
+created by weather have a significant effect on natural gas prices. Oil price
+fluctuations are more closely related to global events as opposed to domestic
+events, although the inability to increase supply domestically continues to
+be a
+factor. The global conditions that affect the price of oil include a continuing
+increase in demand from the global economy, political instability in the Middle
+East, and a decrease in excess worldwide production capacity. News sources
+reported that the second and third largest producing fields in the world went
+on
+decline in 2005. 
+35 
+Hedging
+Activities 
+We
+have
+an active hedging program in which we hedge the first two to three years of
+an
+acquisition’s equivalent production as well as a portion of our existing
+forecasted production on a discretionary basis. Beginning in October 2005,
+we
+hedged a significant portion of anticipated future production from our currently
+producing properties using zero-cost collars. These contracts supplement our
+previous swap and collar contracts. We also hedged a portion of specific
+forecasted natural gas production for 2006 and 2007 using swap contracts. Taking
+into account all oil and gas production hedge contracts in place through
+February 15, 2006, we have hedged approximately 13.0 million Bbls and
+73.7 million MMBTU of our anticipated production through the
+year 2011. We believe we have established an economic base for our future
+operations, and the spread between the price floor and ceiling on our collars
+allows us to continue to participate in a higher oil and gas price environment.
+Please see Note 10 of Part IV, Item 15 of this report for additional information
+regarding our oil and gas hedges, and see the caption, Summary
+of Oil and Gas Production Hedges in Place, 
+later in
+this section. 
+Net
+Profits Plan 
+Increases
+in oil and gas prices in the second half of 2005 resulted in a significant
+increase in the estimated future liability associated with our Net Profits
+Plan.
+The expense associated with the change in this estimated liability increased
+substantially in 2005. We recorded expense of $106.3 million for 2005
+compared to $24.4 million for 2004 and $5.3 million for 2003. The expense
+associated with the change in the liability correlates closely with oil and
+gas
+prices and how quickly we recover our costs before we begin making payments,
+as
+required by the Net Profits Plan. Based on our valuation calculations as
+described in our accounting policies footnote, we believe the expense for this
+liability will be significantly less in 2006 as compared to 2005. 
+The
+calculation of this liability requires management to prepare its best estimate
+of future amounts payable from the Net Profits Plan. On a monthly basis, we
+calculate estimates of the payments to be made for each individual pool under
+the plan. The underlying basis for our calculations are forecasted oil and
+gas
+production from the properties that comprise each individual pool, price
+assumptions and discount rate. In most cases, the cash flow streams used in
+these calculations will span more than 20 years. We generally use a
+15 percent discount rate to calculate the present value of these future
+payments, and the resulting amount is recorded as a liability. Commodity prices
+impact the calculated cash flows during periods after payout and can
+dramatically affect the timing of the estimated date of payout of the individual
+pools. Our commodity price assumptions are currently determined from a rolling
+average of actual prices received for the preceding 24 months combined with
+adjusted NYMEX strip prices for the next 12 months. This average is supplemented
+by including the effect of hedge prices for the percentage of forecasted
+production hedged in the relevant period. The calculation of the estimated
+liability for the Net Profits Plan is highly sensitive to our price estimates
+and discount rate assumptions. For example, if we changed the prices in
+our calculation by ten percent, the liability recorded at December 31, 2005,
+would differ by approximately $26 million, and a one percent change in the
+discount rate would result in a change of approximately $5 million. We
+frequently evaluate the assumptions used in our calculations to evaluate the
+possible impacts stemming from the current market environment. This review
+considers current oil and gas prices, discount rates and overall market
+conditions. The calculation of this liability will not correlate precisely
+to
+the standardized measure of discounted future net cash flows presented in Note
+12 of Part IV, Item 15 of this report due to different pricing and discount
+assumptions. 
+As
+a
+result of higher prices over the last 12 months and the rate at which we have
+recovered costs associated with the designated properties in each pool, actual
+cash payments for amounts earned under the Net Profits Plan for 2005 were $20.8
+million. Because of the life cycles of these pools and the existing commodity
+prices, we have budgeted approximately $40 million for cash payments in
+2006. The actual cash payments to be made in future periods are dependent on
+actual production, realized prices and operating and capital costs associated
+with the individual pools. Actual cash payments will be inherently different
+from the estimated liability amount. Additional discussion is included in the
+analysis in the Comparison
+of Financial Results and Trends 
+sections
+below. 
+36 
+2005
+Highlights 
+In
+2005
+we experienced record production and earnings. Record production is the
+culmination of investment decisions made in prior years and in the current
+period. Significant increases in commodity prices for oil and natural gas and
+increased production resulted in the highest net revenues in our history. In
+2006, we anticipate production to be greater than in 2005. If oil and gas prices
+remain high, it is reasonable to assume that revenue growth will continue.
+Our
+margins remained very strong in 2005 as a result of price increases in spite
+of
+the upward pressure from rig and service companies. In 2005, lease operating
+and
+transportation expense on a per MCFE basis increased from $0.91 per MCFE to
+$1.08 per MCFE. This was partially a result of a greater percentage of our
+production coming from oil properties which generally have higher operating
+costs. Other drivers for this increase include upward pressure on service costs,
+chemicals and labor and an increase in workover expense from $6.9 million in
+2004 to $12.0 million in 2005. Increased workover costs will continue to impact
+us as nearly 40 percent of our production is from oil properties that require
+a
+higher amount of maintenance than required by flowing gas wells. 
+Highlights
+for 2005 also include the repurchase of 1,175,282 shares of our common stock
+under our stock repurchase program at an average price of $24.51 per share.
+We
+also closed on $87.8 million of oil and gas property acquisitions for a
+total of $73.9 million in cash. Our cash outflows were funded entirely by
+existing cash, operating cash inflows and short-term investments on hand. We
+repaid the $37.0 million of outstanding borrowings under this credit facility
+as
+of December 31, 2004, and we have no borrowings currently outstanding
+under our credit facility. 
+In
+2005
+oil prices rose to record levels as excess OPEC capacity shrank to its lowest
+level in recent time. Demand for oil was impacted by the growing economies
+of
+China and India as well as from a recovering U.S. economy. Spot market prices
+reflected worldwide concerns about producer ability to ensure sufficient supply
+to meet increasing demand amid a host of uncertainties caused by weather-related
+destruction, political instability, a weaker US dollar, foreign oil rig worker
+strikes and crude oil refining constraints. Average natural gas prices for
+the
+year were at an all-time high due to supply and transportation constraints,
+weather-related lost production, and continuing strong demand for natural gas
+in
+domestic markets resulting from an improving economy and the effect high oil
+prices have on natural gas demand. NYMEX prices for the year averaged $8.55
+per
+MMBtu and $56.56 per Bbl, translating into a 49 percent increase to our per
+MCFE
+realized price over 2004. At December 31, 2005, the 12-month NYMEX
+strip was $63.18 per Bbl for oil and $10.78 per MMBtu for gas. As of February
+15, 2006, pricing for the same period, including settled prices, was
+$60.46 per Bbl for oil and $8.36 per MMBtu for gas. As a result, the
+overall draws from gas storage have been lower than both the prior year and
+the
+prior five-year average. 
+Net
+income for 2005 was $151.9 million or $2.33 per diluted share compared to
+$92.5 million or $1.40 per diluted share for the prior year. Net cash
+provided by operating activities was $409.4 million, up 73 percent from
+2004. Average daily production for the year increased 16 percent to 239.4
+MMCFE. Our average net realized price increased 49 percent to $8.14 per MCFE.
+Unit costs increased for the period as lease operating and transportation
+expenses increased $0.17 to $1.08 per MCFE, production taxes increased $0.20
+to
+$0.56 per MCFE, DD&A increased $0.30 to $1.52 per MCFE and general and
+administrative expense increased $0.08 to $0.37 per MCFE. 
+37 
+The
+table
+below provides information regarding selected production and financial
+information for the quarter ended December 31, 2005, and the
+immediately preceding three quarters. 
+For
+the Three Months Ended 
+December
+31, 
+September
+30, 
+June
+30, 
+March
+31, 
+2005 
+2005 
+2005 
+2005 
+(In
+millions) 
+Production
+(MCFE) 
+21.9 
+23.1 
+21.8 
+20.6 
+Oil
+and gas production revenues before the effects of hedging 
+$ 
+231.6 
+$ 
+203.1 
+$ 
+160.4 
+$ 
+138.4 
+Lease
+operating expense 
+$ 
+23.8 
+$ 
+22.9 
+$ 
+19.2 
+$ 
+20.3 
+Transportation
+costs 
+$ 
+2.6 
+$ 
+1.8 
+$ 
+1.8 
+$ 
+1.9 
+Production
+taxes 
+$ 
+16.1 
+$ 
+13.4 
+$ 
+9.2 
+$ 
+10.0 
+General
+and administrative expense 
+$ 
+9.5 
+$ 
+9.8 
+$ 
+7.5 
+$ 
+6.0 
+Net
+income 
+$ 
+51.2 
+$ 
+27.3 
+$ 
+38.3 
+$ 
+35.1 
+Percentage
+change from previous quarter: 
+Production
+(MCFE) 
+(5)% 
+6% 
+6% 
+Oil
+and gas production revenues 
+14 % 
+27% 
+16% 
+Lease
+operating expense 
+4% 
+19% 
+(5)% 
+Transportation
+costs 
+44% 
+0% 
+(5)% 
+Production
+taxes 
+20% 
+46% 
+(8)% 
+General
+and administrative expense 
+(3)% 
+31% 
+25% 
+Net
+income 
+88% 
+(29)% 
+9% 
+Outlook
+for 2006 
+Oil
+and
+gas prices remain very volatile. We have attractive prospects to drill, and
+rig
+counts are growing. However, this growth trend could be mitigated by the
+necessity for drilling companies to hire qualified crews to work these rigs.
+We
+have felt the impact of escalating rig and other service costs. The country’s
+ability to supply gas remains challenged as the average decline rate from
+existing natural gas wells has increased from 16 percent to 30 percent over
+the
+past thirteen years, as estimated by various industry analysts. This change
+is a
+result of increased activity in the Gulf of Mexico where reserve lives are
+quite
+short, the use of 3-D seismic to identify smaller reservoirs, the use of better
+completion techniques that allow reserves to be produced faster, and more
+efficiently, and high deliverability of storage that allows wells to be produced
+at full capacity all year long. New sources of gas such as LNG, frontier regions
+(e.g. deepwater Gulf of Mexico and Mackenzie Delta, Alaska) and unconventional
+gas plays are all more costly and have long lead times, but at some point could
+have a positive impact on supply. We believe oil prices are high now due to
+perceptions of reduced spare capacity, increasing worldwide demand and an
+apparent increased target price range for OPEC. It is not possible for us to
+predict prices, however we believe that growing net asset value per share is
+the
+fundamental driver of our stock price over the long term. 
+We
+enter
+2006 in excellent financial condition and with a capital expenditure budget
+of
+$600 million. We are successfully transitioning the emphasis of our capital
+program to drilling as evidenced by the 50 percent growth in our drilling budget
+as compared to total drilling capital expenditures of $333.7 million in 2005.
+We
+have budgeted $100 million for acquisitions in 2006, which is much lower than
+in
+prior years, on a relative percentage basis. The decreased emphasis on the
+acquisition component of our budget reflects the overall competitiveness of
+the
+acquisition market and the high prices being paid in recent acquisition
+transactions in our industry. More importantly, it reflects the strides we
+have
+made to advance our prospect inventory and activity level on the drilling side.
+The information below provides some detail of our plans for 2006: 
+· 
+We
+believe that we have the necessary capital, personnel,
+and rigs available
+to execute this program. The $500 million budgeted for
+drilling activities
+in 2006 is allocated among our core areas as
+follows: 
+38 
+Rockies
+Conventional - $141 million 
+- There
+are approximately 30 wells planned in the Bakken formation with total capital
+of
+$47 million. We are initiating a horizontal drilling program focusing on the
+Ratcliffe and Mission Canyon formations with $24 million of the budget
+allocated for the drilling of approximately 26 wells. The planned development
+of
+the Tensleep formation results in approximately $9 million of the budget being
+allocated to the Fourbear, Murphy Dome and Big Sand Draw fields. The
+remainder is planned for the Red River program, horizontal Madison, and
+development in the Greater Green River Basin. 
+Rockies
+- Hanging Woman Basin Coalbed Methane - $50 million 
+- We are
+planning on increasing our activity to drill 260 wells in 2006, up from 131
+in
+2005. We intend to expand our activity into Montana. Potential Montana delays
+may result from uncertainties related to our ability to obtain the timely
+regulatory approval of our water development plan on state and fee acreage.
+The
+Wyoming delays could result from timing of drilling in areas that are affected
+by stipulations associated with sage grouse. 
+Mid-Continent
+- $172 million - 
+This
+portion of the drilling budget is dominated by development of the Atoka program
+at Northeast Mayfield and the horizontal development of the Wapanucka limestone,
+Cromwell sandstone and Woodford shale formations at Centrahoma. 
+ArkLaTex
+- $66 million - 
+We will
+continue to expand our horizontal efforts in the James Lime, Glen Rose, Pettet
+and Rodessa formations. We will also participate in the expansion of the
+development activity at Elm Grove and Terryville. 
+Gulf
+Coast and Permian - $71 million - 
+We will
+concentrate primarily on targets with direct hydrocarbon indicators along the
+Gulf Coast and on the Gulf of Mexico shelf. We have a $4 million budget for
+development in the Permian Basin. 
+· 
+The
+$100 million budgeted for acquisitions could be expected
+to increase
+production in 2006, depending on the availability and timing
+of
+acquisition opportunities. We continuously evaluate opportunities
+in the
+marketplace for oil and gas properties and, accordingly,
+may be a buyer or
+a seller of properties at various times. We will continue
+to emphasize
+smaller niche acquisitions within our existing core areas
+utilizing our
+technical expertise, financial flexibility and structuring
+experience. In
+addition, we may seek larger acquisitions of assets or
+companies that
+would afford opportunities to expand beyond our existing
+core areas.
+However, we would want to ensure that we also acquired
+the necessary
+personnel with expertise in a new basin in order for it
+to be attractive
+to us. We do not currently have any specifically identified pending
+transactions.
+39 
+A
+year-to-year overview of selected reserve, production and financial
+information, including trends: 
+As
+of and for the Years Ended 
+Percent
+Change Between 
+2005 
+2004 
+2003 
+2005/2004 
+2004/2003 
+Selected
+Operations Data (In Thousands, Except Price, Volume, and Per MCFE
+Amounts): 
+Total
+proved reserves (PV-10 basis) 
+Oil
+(MBbl) 
+62,903 
+56,574 
+47,787 
+Natural
+gas (MMcf) 
+417,075 
+319,196 
+307,024 
+MMCFE 
+794,493 
+658,638 
+593,744 
+21 
+% 
+11 
+% 
+Net
+production volumes 
+Oil
+(MBbl) 
+5,927 
+4,799 
+4,541 
+Natural
+gas (MMcf) 
+51,801 
+46,598 
+49,663 
+MMCFE 
+87,363 
+75,393 
+76,909 
+16 
+% 
+(2 
+)% 
+Average
+daily production 
+Oil
+(MBbl) 
+16 
+13 
+12 
+Natural
+gas (MMcf) 
+142 
+127 
+136 
+MMCFE 
+239 
+206 
+211 
+16 
+% 
+(2 
+)% 
+Oil
+& gas production revenues 
+Oil
+production, including hedging 
+$ 
+301,860 
+$ 
+156,112 
+$ 
+122,444 
+Gas
+production, including hedging 
+409,145 
+257,206 
+242,670 
+Total 
+$ 
+711,005 
+$ 
+413,318 
+$ 
+365,114 
+72 
+% 
+13 
+% 
+Oil
+& gas production costs 
+Lease
+operating expenses 
+$ 
+86,130 
+$ 
+61,269 
+$ 
+59,152 
+Transportation
+costs 
+8,010 
+7,235 
+7,197 
+Production
+taxes 
+48,733 
+27,014 
+22,160 
+Total 
+$ 
+142,873 
+$ 
+95,518 
+$ 
+88,509 
+50 
+% 
+8 
+% 
+Average
+net realized sales price (1) 
+Oil
+(per Bbl) 
+$ 
+50.93 
+$ 
+32.53 
+$ 
+26.96 
+57 
+% 
+21 
+% 
+Natural
+gas (per Mcf) 
+$ 
+7.90 
+$ 
+5.52 
+$ 
+4.89 
+43 
+% 
+13 
+% 
+Per
+MCFE data: 
+Average
+net realized price (1) 
+$ 
+8.14 
+$ 
+5.48 
+$ 
+4.75 
+49 
+% 
+15 
+% 
+Lease
+operating expense 
+(0.99 
+) 
+(0.81 
+) 
+(0.77 
+) 
+22 
+% 
+5 
+% 
+Transportation
+costs 
+(0.09 
+) 
+(0.10 
+) 
+(0.09 
+) 
+(10 
+)% 
+11 
+% 
+Production
+taxes 
+(0.56 
+) 
+(0.36 
+) 
+(0.29 
+) 
+56 
+% 
+24 
+% 
+General
+and administrative 
+(0.37 
+) 
+(0.29 
+) 
+(0.28 
+) 
+28 
+% 
+4 
+% 
+Operating
+profit 
+$ 
+6.13 
+$ 
+3.92 
+$ 
+3.32 
+56 
+% 
+18 
+% 
+Depletion,
+depreciation and amortization 
+$ 
+1.52 
+$ 
+1.22 
+$ 
+1.07 
+25 
+% 
+14 
+% 
+Financial
+Information (In Thousands, Except Per Share Amounts): 
+Working
+capital 
+$ 
+4,937 
+$ 
+12,035 
+$ 
+3,101 
+(59 
+)% 
+288 
+% 
+Long-term
+debt 
+$ 
+99,885 
+$ 
+136,791 
+$ 
+110,696 
+(27 
+)% 
+24 
+% 
+Stockholders’
+equity 
+$ 
+569,
+320 
+$ 
+484,455 
+$ 
+390,653 
+18 
+% 
+24 
+% 
+Net
+income 
+$ 
+151,936 
+$ 
+92,479 
+$ 
+95,575 
+64 
+% 
+(3 
+)% 
+Basic
+net income per common share 
+$ 
+2.67 
+$ 
+1.60 
+$ 
+1.53 
+67 
+% 
+5 
+% 
+Diluted
+net income per common share 
+$ 
+2.33 
+$ 
+1.44 
+$ 
+1.40 
+62 
+% 
+3 
+% 
+Basic
+weighted-average shares outstanding 
+56,907 
+57,702 
+62,467 
+(1 
+)% 
+(8 
+)% 
+Diluted
+weighted-average shares outstanding 
+66,894 
+66,894 
+71,069 
+- 
+% 
+(6 
+)% 
+Net
+cash provided by operating activities 
+$ 
+409,379 
+$ 
+237,162 
+$ 
+204,319 
+73 
+% 
+16 
+% 
+Net
+cash used in investing activities 
+$ 
+(339,779 
+) 
+$ 
+(247,006 
+) 
+$ 
+(196,939 
+) 
+38 
+% 
+25 
+% 
+Net
+cash provided by (used in) financing 
+activities 
+$ 
+(61,093 
+) 
+$ 
+1,435 
+$ 
+(3,707 
+) 
+(4357 
+)% 
+139 
+% 
+____________________
+(1)
+Includes the effects of our hedging activities. 
+We
+present this table as a summary of information relating to key indicators of
+financial condition and operating performance that we believe are
+important. 
+40 
+The
+increase in our oil and gas reserve volumes reflects our drilling results and
+acquisition activity combined with increases in natural gas and crude oil prices
+used to evaluate reserves. Please see Note 12 of Part IV, Item 15 for additional
+details. Over time, the ability to economically replace 200 percent of the
+total
+volumes produced in the current year has proven to be a key factor that
+determines whether we are successful in achieving our goal of increasing net
+asset value per share by 15 percent per year. We anticipate that we must
+continue our successful drilling program and average one or more relatively
+significant acquisitions per year in the current price environment to achieve
+this level of ongoing growth. The measure of our success will vary from
+year-to-year due to changes in these factors, some of which we can control
+and
+others which we cannot control. 
+The
+changes in production volumes, oil and gas production revenues and costs reflect
+the cyclical and highly volatile nature of prices our industry receives for
+production and the effect of the timing of acquisitions. The comparison of
+changes in production from 2004 to 2005 reflect the positive results from our
+drilling programs in 2005 and the timing of our acquisitions made in the fourth
+quarter of 2004. Acquisitions made during 2004 operated for a full year in
+2005;
+therefore, incremental production increased in 2005. Production volume in 2005
+was also affected by new production from producing oil and gas properties
+acquired in 2005. 
+We
+present per MCFE information because we use this information to evaluate our
+performance relative to our peers and to identify and measure trends that we
+believe require analysis. Our year-to-year comparison of financial results
+presented later provides additional details for the changes in selected line
+items between years. We expect oil and gas production expenses to increase
+in
+2006 as a result of increased activity in our higher-cost Rocky Mountain region,
+increased production taxes, and general inflation due to higher oil and gas
+pricing. Depreciation, depletion and amortization will continue to increase
+due
+to the higher costs associated with finding and acquiring crude oil and natural
+gas reserves. General and administrative expense is also projected to increase
+because of the expense associated with payments under our Net Profits Plan,
+increased expensing of stock-based compensation and overall upward pressure
+on
+compensation in the exploration and production industry. 
+We
+have
+in-the-money stock options, unvested restricted stock units and convertible
+notes that are considered potentially dilutive securities. At times these
+dilutive securities can affect our earnings per share. Consequently both basic
+and diluted earnings per share are presented in the table above. A detailed
+explanation is presented in Note 1 of Part IV, Item 15 of this report. Our
+basic
+and diluted weighted-average common shares outstanding used in our 2004 earnings
+per share calculations reflects a decrease in shares caused by the repurchase
+of
+our common stock from Flying J and the re-initiation of our stock repurchase
+program offset by an increase in outstanding shares related to stock option
+exercises. Basic and diluted weighted-average shares outstanding in 2005 were
+affected by similar factors as 2004. We issued 936,403 shares of common stock
+in
+2005 as a result of stock option exercises. These share issuances were offset
+by
+the repurchase of 1,175,282 shares of common stock via our stock repurchase
+plan. 
+The
+remaining information in the table relates to information we have provided
+in
+the operations update press releases and is intended to supplement the
+discussion above. 
+Overview
+of Liquidity and Capital Resources 
+We
+own
+depleting assets. In order to maintain our current size and to sustain our
+projected growth levels, we will have to successfully invest capital into new
+projects and acquisitions. The following analysis and discussion includes our
+assessments of market risk and possible effects of inflation and changing
+prices. 
+Sources
+of cash 
+Our
+primary sources of liquidity are the cash provided by operating activities,
+debt
+financing, sales of non-strategic properties and access to capital markets.
+All
+of these sources can be impacted by the general condition of our industry and
+by
+significant fluctuations in oil and gas prices, operating costs and volumes
+produced. We have no control over the market prices for oil and gas, although
+we
+are able to influence the amount of our net revenues related to oil and gas
+sales through the use of derivative contracts. A decrease in market prices
+would
+reduce expected cash flow from operating activities and could reduce the
+borrowing base of our credit facility and the value of non-strategic properties
+we might consider selling. Historically, decreases in market prices have limited
+our industry’s access to the capital markets. The debt and equity financing
+capital markets are currently favorable to energy companies that operate in
+the
+exploration and production industry. This is a result of strong commodity prices
+and the general strength reflected in the balance sheets of the companies in
+this industry. The availability of capital has a high correlation to overall
+commodity prices. Accordingly, a downturn in prices could adversely impact
+our
+ability to raise capital. Our current access to cash under our existing credit
+facility and from cash on hand and cash flows from operations is significant.
+We
+are not currently planning to access the capital markets in 2006. If
+additional development or attractive acquisition opportunities arise that exceed
+our currently available resources, we may consider other forms of financing,
+including the public offering or private placement of equity or debt securities.
+41 
+Our
+current credit facility .
+We have
+a five-year, $500 million credit facility agreement with Wachovia Bank,
+Wells Fargo Bank and eight other participating banks. This credit facility
+has a
+borrowing base of $500 million, and we have elected a commitment amount of
+$200 million, which results in lower commitment fees payable to the bank
+syndicate. We believe this commitment level is adequate for our near-term
+liquidity requirements. The credit agreement has a maturity date of
+April 7, 2010. We believe that we would be able to increase the note
+amount of this facility if necessary as we believe that the actual borrowing
+base far exceeds the $500 million face amount. Even so, there must be a
+compelling reason to incur the costs associated with increasing the size of
+the
+credit facility. We must comply with certain financial and non-financial
+covenants under our existing credit facility and we are in compliance with
+all
+covenants as of December 31, 2005 and February 15, 2006. Interest and commitment
+fees are accrued based on the borrowing base utilization percentage. Euro-dollar
+loans accrue interest at LIBOR plus the applicable margin from the utilization
+table located in Note 5 of Part IV, Item 15 of this report, and
+Alternate Base Rate loans accrue interest at prime plus the applicable margin
+from the utilization table. We have a single letter-of-credit outstanding under
+our facility in the amount of $1.15 million. This reduces the amount available
+under the commitment amount on a dollar-for-dollar basis. Borrowings under
+the
+new facility are secured by the majority of our oil and gas properties and
+a
+pledge of the common stock of our material subsidiary companies. 
+Commitment
+fees are accrued on the unused portion of the aggregate commitment amount and
+are included in interest expense in the consolidated statements of operations.
+We had no outstanding loan balance as of December 31, 2005, and that
+remains true as of the date of this report. As of December 31, 2005, we had
+a
+cash and short-term investment balance of $16.4 million and as of February
+15,
+2006, our cash and short term investments were approximately $38 million.
+We
+decreased our net borrowings from the previous year by $37.0 million. Our
+weighted-average interest rate paid in 2005 was 7.1 percent and
+included fees paid on the unused portion of the credit facility aggregate
+commitment amount, amortization of deferred financing costs, amortization of
+the
+contingent interest embedded derivative associated with the convertible notes,
+and the effects of interest rate swaps. 
+Uses
+of cash 
+We
+use
+cash for the acquisition, exploration and development of oil and gas properties
+and for the payment of debt obligations, trade payables, income taxes, common
+stock repurchases and stockholder dividends. During 2005 we spent $333.7 million
+on capital development, $87.8 million for property acquisitions and
+$28.9 million to acquire shares of our common stock using cash flows from
+operations. All borrowings under our credit facility were repaid from operating
+cash flows. We also made cash payments for income taxes of $65.8 million.
+The current portion of our income tax expense was 94 percent of our total income
+tax expense. We expect to remain a highly taxable entity, although the
+percentage of our current income tax expense is expected to be closer to 50
+percent of our total tax liability in 2006 as a result of our higher capital
+spending program and reduced expense related to the Net Profits Plan
+liability. 
+Expenditures
+for exploration and development of oil and gas properties and acquisitions
+are
+the primary use of our capital resources. We anticipate spending approximately
+$500 million for capital and exploration expenditures in 2006 with an additional
+$100 million allocated for acquisitions of oil and gas properties. The capital
+expenditures budget is described in more detail earlier in the Outlook
+for 2006 
+section.
+We regularly review our capital expenditure budget to reflect changes in current
+and projected cash flows, acquisition opportunities, debt requirements and
+other
+factors. 
+42 
+As
+of
+December 31, 2005, we have Board authorization to repurchase up to an
+additional 3.8 million shares of our common stock under our stock
+repurchase program. These shares may be repurchased from time to time in open
+market transactions or privately negotiated transactions and subject to market
+conditions and other factors, including certain provisions of our existing
+bank
+credit facility agreement and compliance with securities laws. 
+In
+connection with our two-for-one stock split in March 2005, we announced
+that the semi-annual dividend rate would remain at $0.05 per share. This
+effectively doubles our annual cash dividend payments from 2004. Our
+intention is to continue to make these dividend payments for the foreseeable
+future subject to our future earnings, our financial condition, possible credit
+facility covenants and other currently unexpected factors which could arise.
+We
+paid $5.7 million for dividends in 2005 compared with $2.8 million in
+2004. 
+We
+believe that internally generated cash flows will be sufficient to fund our
+planned operational, drilling and acquisition expenditures for the foreseeable
+future. The amount and allocation of future capital and exploration expenditures
+will depend upon a number of factors including the number and size of available
+economic acquisitions and drilling opportunities, our cash flows from operating
+and financing activities and our ability to assimilate acquisitions we make.
+Also, the impact of oil and gas prices on investment opportunities, the
+availability of capital and borrowing facilities and the success of our
+development and exploratory activities could lead to changes in funding
+requirements for future development. 
+The
+following table presents amounts and percentage changes between years in net
+cash flows from our operating, investing and financing activities. The analysis
+following the table should be read in conjunction with our consolidated
+statements of cash flows in Part IV, Item 15 of this report. 
+Amount
+of Change Between 
+Percent
+of Change Between 
+2005/2004 
+2004/2003 
+2005/2004 
+2004/2003 
+Net
+Cash Provided By Operating Activities 
+$ 
+172,217 
+$ 
+32,843 
+73% 
+16% 
+Net
+Cash Used In Investing Activities 
+$ 
+(92,773 
+) 
+$ 
+(50,067 
+) 
+38% 
+25% 
+Net
+Cash Provided By (Used In) Financing Activities 
+$ 
+(62,528 
+) 
+$ 
+5,142 
+(4,357)% 
+139% 
+Analysis
+of cash flow changes between 2005 and 2004 
+Operating
+activities .
+Cash
+received from oil and gas sales, net of the effects of hedging, increased
+$268.6 million to $651.6 million for the year ended December
+31, 2005. This increase was the result of a 16 percent increase in
+production and a 49 percent increase in our net realized prices between the
+two periods. Changes in current assets and liabilities combined with cash
+expenditures for oil and gas production expenses, exploration expenses and
+administrative expenses increased by $75.0 million between the two
+comparable periods, and net cash payments made for income taxes increased $51.0
+million. The future operating cash flow impact of the increased percentage
+of
+hedged production using zero-cost collars will have the effect of reducing
+the
+sensitivity to movements in oil and gas prices to the extent prices fall outside
+of the collar range. 
+Investing
+activities .
+Total
+cash outflow for 2005 capital expenditures, as adjusted for accruals and
+including acquisitions of oil and gas properties, increased $76.6 million
+or 29 percent to $344.8 million. This increase reflects increased
+drilling expenditures and net cash paid for the acquisition of Agate Petroleum,
+Inc., and for oil and gas properties acquired in Wyoming during 2005. The year
+ended December 31, 2004, reflects $20.7 million net cash received
+from short-term investments and from the expiration of the restriction period
+for funds held for tax-deferred exchange of oil and gas properties.
+Financing
+activities .
+Net
+payments against our credit facility were $37.0 million for the year ended
+December 31, 2005, versus net borrowings of $26.0 million in 2004. We
+paid $28.9 million to acquire shares of our common stock under our stock
+repurchase program in 2005, compared to $16.3 million paid in 2004. In 2004
+$19.4 million was paid to repurchase shares of our common stock and to
+settle the loan receivable from Flying J. We received $2.8 million
+less from the exercise of stock options in 2005 compared to 2004. As a
+result of our two-for-one stock split, cash paid for dividends was $5.7 million
+in 2005 compared to the $2.8 million paid in 2004. 
+43 
+We
+had
+$14.9 million in cash and cash equivalents and had working capital of
+$4.9 million as of December 31, 2005, compared to $6.4 million in
+cash and cash equivalents and working capital of $12.0 million as of
+December 31, 2004. 
+Analysis
+of cash flow changes between 2004 and 2003 
+Operating
+activities. Sources
+of cash flow from oil and gas sales increased $40.7 million from the period
+ended December 31, 2003, to the period ended December 31, 2004. This was a
+result of a 15 percent increase in our realized prices that offset a net
+production decrease of two percent between the comparative periods. Cash
+expenditures for operating expenses, exploration expense and administrative
+expenses increased by $2.4 million. Other revenue items decreased by
+$5.7 million. 
+Investing
+Activities. The
+increase in net cash used resulted from $75.6 million of increased drilling
+expenditures in 2004 over 2003 and from a 2004 cash payment of $3.8 million
+held
+as a deposit for our Agate acquisition. These increases were offset by a $7.6
+million decrease in acquisition activity in 2004. Total capital expenditures
+increased by 34 percent to $268.2 million from $200.2 million in 2003. Proceeds
+from sales of oil and gas properties decreased by $20.7 million, but expiration
+of the restriction period for funds held for deferred tax exchange of oil and
+gas properties and net receipts from short-term investments resulted in a net
+cash provided change between periods of $41.8 million. Volumes, revenue and
+net
+operating margin from properties that were sold in 2003 and 2004 were not a
+material component in the consolidated statements of operations or balance
+sheets for any year presented, nor do they represent a group of assets that
+would qualify for discontinued operations accounting treatment. 
+Cash
+expended in 2003 for acquisitions of oil and gas properties included our
+utilization of $71.6 million of short-term investments, cash equivalents
+and increased borrowings under our credit facility to provide a loan to Flying
+J
+as part of our acquisition of properties. This loan was secured by the shares
+of
+our common stock issued in the transaction. 
+Financing
+activities. The
+$5.1 million increase in cash provided by financing activities reflects the
+$26.0 million we borrowed on our credit facility in 2004 to fund acquisitions
+and drilling activity and an $11.5 million increase in proceeds from stock
+option exercises over the 2003 amounts. We paid $19.4 million to
+repurchase our shares from Flying J on February 9, 2004, and we paid $16.3
+million to repurchase shares under our stock repurchase program. In 2003 we
+borrowed to fund our acquisition of properties from Flying J and used cash
+flow
+from operations to reduce our outstanding debt for the year. 
+St. Mary
+had $6.4 million in cash and cash equivalents and had working capital of
+$12.0 million as of December 31, 2004, compared to $14.8 million in cash
+and cash equivalents and working capital of $3.1 million as of December 31,
+2003. 
+44 
+Capital
+Expenditures 
+The
+following table sets forth certain historical information regarding the costs
+incurred by us in our oil and gas activities. The 2005 and 2004 amounts include
+capitalized costs associated with asset retirement obligations. 
+Years
+Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Development
+costs 
+$ 
+249,518 
+$ 
+190,829 
+$ 
+111,908 
+Exploration
+costs 
+69,817 
+37,977 
+33,296 
+Acquisitions: 
+Proved 
+84,981 
+69,054 
+73,989 
+Unproved 
+2,853 
+7,646 
+8,942 
+Leasing
+activity 
+14,330 
+7,877 
+7,480 
+Total
+$ 
+421,499 
+$ 
+313,383 
+$ 
+235,615 
+The
+costs
+we incurred for capital and exploration activities in 2005 increased
+$108.1 million or 34 percent compared to 2004. This increase was a result
+of planned increases in drilling activity, an $11 million increase in
+acquisitions, and a $13.8 million increase in capitalized costs associated
+with
+asset retirement obligations resulting from changes in estimates and from wells
+drilled in 2005. We have seen a tremendous amount of cost inflation over the
+past three years, and we estimate that it now costs approximately twice as
+much
+to drill a well as it did three years ago. 
+Our
+ongoing development of the coalbed methane reserves in the Hanging Woman Basin
+area is proceeding as expected. During 2005 131 wells were drilled, 114 of
+which
+we operate. We have 154,000 net lease acres in the basin and are concentrating
+our initial development on 80,000 net acres located in Wyoming. 
+Commodity
+Price Risk and Interest Rate Risk 
+We
+are
+exposed to market risk, including the effects of changes in oil and gas
+commodity prices and changes in interest rates as discussed below under the
+caption “ Summary
+of Interest Rate Hedges in Place .”
+Changes in interest rates can affect the amount of interest we earn on our
+cash,
+cash equivalents and short-term investments and the amount of interest we pay
+on
+borrowings under our revolving credit facility. Changes in interest rates do
+not
+affect the amount of interest we pay on our fixed-rate convertible notes, but
+do
+affect the fair value of convertible note debt. 
+Since
+we
+produce and sell natural gas and crude oil, our financial results are affected
+when prices for these commodities fluctuate. The next table reflects our
+estimate of the effect on cash flow from operations of a ten percent change
+in
+our average realized sales price for natural gas, for oil and in total for
+the
+years presented. These amounts have been reduced by the effective income tax
+rate applicable to each period since a reduction in revenue would reduce cash
+requirements to pay income taxes. General and administrative expenses have
+not
+been adjusted. To fund the capital and exploration expenditures we incurred
+in
+those years we would have been required to utilize different amounts under
+our
+credit facility as a source of funds. In each of these years we would have
+had
+sufficient borrowing base available under our credit facility to meet this
+contingency without reducing or eliminating expenditures and affecting our
+growth strategy. 
+45 
+Pro
+Forma effect on revenues of a ten p ercent
+change in average sales price: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Oil
+$ 
+18,098 
+$ 
+9,180 
+$ 
+6,979 
+Natural
+Gas 
+24,502 
+15,280 
+13,889 
+Total 
+$ 
+42,600 
+$ 
+24,460 
+$ 
+20,868 
+We
+enter
+into hedging transactions in order to reduce the impact of fluctuations in
+commodity prices. Note 10 of Part IV, Item 15 of this report
+contains important information about our oil and gas derivative
+contracts, and additional information is below under the caption Summary
+of Oil and Gas Production Hedges in Place .
+We do
+not anticipate significant changes in existing hedge contracts or derivative
+contract transactions. 
+Summary
+of Oil and Gas Production Hedges in Place 
+Our
+oil
+and natural gas derivative contracts include swap and collar arrangements.
+All
+contracts are entered into for other-than-trading purposes. Please refer to
+Note 10 - Derivative Financial Instruments in Part IV, Item 15 of
+this report for additional information regarding accounting for our derivative
+transactions. 
+Our
+net
+realized oil and gas prices are impacted by hedges we have placed on future
+forecasted production. We have historically entered into hedges of existing
+production around the time we make acquisitions of producing oil and gas
+properties. Our intent has been to lock-in a significant portion of an
+equivalent amount of existing production to the prices we used to evaluate
+the
+risked economics of our acquisition. We also hedge a portion of our
+forecasted production on a discretionary basis. We have entered into a
+significant volume of zero-cost collar hedging transactions that has increased
+our hedged positions to approximately 13 million Bbls and 74 million
+MMBTU of anticipated future production through 2011, including hedges entered
+into subsequent to year end. 
+In
+a
+typical commodity swap agreement, if the agreed upon published third-party
+index
+price is lower than the swap fixed price, we receive the difference between
+the
+index price per unit of production and the agreed upon swap fixed price. If
+the
+index price is higher than the swap fixed price, we pay the difference. For
+collar agreements, we receive the difference between an agreed upon index and
+the floor price if the index price is below the floor price. We pay the
+difference between the agreed upon contracted ceiling price and the index price
+if the index price is above the contracted ceiling price. No amounts are paid
+or
+received if the index price is between the contracted floor and ceiling
+prices. 
+The
+following tables describe the volumes, average contract prices, and fair value
+of contracts we have in place as of December 31, 2005. We seek to
+minimize basis risk and index the majority of our oil contracts to NYMEX prices
+and our gas contracts to various regional index prices associated with pipelines
+in proximity to our areas of gas production. 
+46 
+Oil
+Contracts 
+Oil
+Swaps 
+Contract
+Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair
+Value at 
+December
+31, 2005 
+Asset/(Liability) 
+(Bbl) 
+(per
+Bbl) 
+(in
+thousands) 
+First
+quarter 2006 - 
+NYMEX
+WTI 
+385,366 
+$ 
+53.23 
+$ 
+(3,329 
+) 
+IF
+Bow River 
+24,000 
+$ 
+39.16 
+(5 
+) 
+Second
+quarter 2006 - 
+NYMEX
+WTI 
+327,976 
+$ 
+54.53 
+(2,739 
+) 
+IF
+Bow River 
+30,000 
+$ 
+40.68 
+(116 
+) 
+Third
+quarter 2006 - 
+NYMEX
+WTI 
+281,372 
+$ 
+54.79 
+(2,426 
+) 
+IF
+Bow River 
+33,000 
+$ 
+40.46 
+(169 
+) 
+Fourth
+quarter 2006 - 
+NYMEX
+WTI 
+155,686 
+$ 
+50.57 
+(2,001 
+) 
+IF
+Bow River 
+30,000 
+$ 
+37.54 
+(154 
+) 
+2007
+- 
+NYMEX
+WTI 
+314,786 
+$ 
+39.78 
+(7,046 
+) 
+IF
+Bow River 
+76,000 
+$ 
+38.85 
+(466 
+) 
+2008
+- 
+NYMEX
+WTI 
+35,000 
+$ 
+56.63 
+(191 
+) 
+All
+oil swap contracts 
+$ 
+(18,642 
+) 
+Oil
+Collars 
+Contract
+Period 
+NYMEX
+WTI 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+Fair
+Value at 
+December
+31, 2005 
+Asset/(Liability) 
+(Bbl) 
+(per
+Bbl) 
+(per
+Bbl) 
+(in
+thousands) 
+First
+quarter 2006 
+545,000 
+$ 
+51.34 
+$ 
+72.07 
+$ 
+(76 
+) 
+Second
+quarter 2006 
+537,000 
+$ 
+51.32 
+$ 
+72.05 
+(438 
+) 
+Third
+quarter 2006 
+516,000 
+$ 
+51.31 
+$ 
+72.06 
+(725 
+) 
+Fourth
+quarter 2006 
+607,000 
+$ 
+51.59 
+$ 
+72.28 
+(945 
+) 
+2007 
+2,585,000 
+$ 
+50.57 
+$ 
+72.73 
+(4,826 
+) 
+2008 
+1,668,000 
+$ 
+50.00 
+$ 
+69.82 
+(4,866 
+) 
+2009 
+1,526,000 
+$ 
+50.00 
+$ 
+67.31 
+(4,072 
+) 
+2010 
+1,367,500 
+$ 
+50.00 
+$ 
+64.91 
+(3,397 
+) 
+2011 
+1,236,000 
+$ 
+50.00 
+$ 
+63.70 
+(2,629 
+) 
+All
+oil collars 
+$ 
+(21,974 
+) 
+47 
+Gas
+Contracts 
+Gas
+Swaps 
+Contract
+Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair
+Value at 
+December
+31, 2005 
+Asset/(Liability) 
+(MMBtu) 
+(per
+MMBtu) 
+(in
+thousands) 
+First
+quarter 2006 - 
+IF
+ANR OK 
+2,030,000 
+$ 
+9.10 
+$ 
+151 
+IF
+PEPL 
+330,000 
+$ 
+6.41 
+(854 
+) 
+IF
+CIG 
+340,000 
+$ 
+7.51 
+(438 
+) 
+IF
+NGPL 
+450,000 
+$ 
+11.95 
+1,287 
+IF
+CenterPoint 
+390,000 
+$ 
+6.56 
+(1,312 
+) 
+Second
+quarter 2006 - 
+IF
+ANR OK 
+1,960,000 
+$ 
+8.08 
+(2,281 
+) 
+IF
+PEPL 
+330,000 
+$ 
+5.31 
+(1,266 
+) 
+IF
+CIG 
+330,000 
+$ 
+6.30 
+(609 
+) 
+IF
+NGPL 
+610,000 
+$ 
+9.77 
+278 
+IF
+CenterPoint 
+380,000 
+$ 
+5.67 
+(1,476 
+) 
+Third
+quarter 2006 - 
+IF
+ANR OK 
+1,740,000 
+$ 
+8.51 
+(1,774 
+) 
+IF
+PEPL 
+330,000 
+$ 
+5.29 
+(1,364 
+) 
+IF
+CIG 
+300,000 
+$ 
+6.35 
+(684 
+) 
+IF
+NGPL 
+580,000 
+$ 
+9.94 
+300 
+IF
+CenterPoint 
+360,000 
+$ 
+5.67 
+(1,496 
+) 
+Fourth
+quarter 2006 - 
+IF
+ANR OK 
+1,020,000 
+$ 
+9.06 
+(652 
+) 
+IF
+PEPL 
+110,000 
+$ 
+5.31 
+(442 
+) 
+IF
+CIG 
+300,000 
+$ 
+6.70 
+(655 
+) 
+IF
+NGPL 
+550,000 
+$ 
+10.24 
+126 
+IF
+CenterPoint 
+160,000 
+$ 
+5.71 
+(687 
+) 
+2007
+- 
+IF
+ANR OK 
+1,640,000 
+$ 
+9.22 
+(118 
+) 
+IF
+NGPL 
+3,280,000 
+$ 
+9.16 
+(246 
+) 
+IF
+CIG 
+630,000 
+$ 
+6.42 
+(1,211 
+) 
+All
+gas swap contracts 
+$ 
+(15,423 
+) 
+48 
+Gas
+Collars 
+Contract
+Period 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+Fair
+Value at 
+December
+31, 2005 
+Asset/(Liability) 
+(MMBtu) 
+(per
+MMBtu) 
+(per
+MMBtu) 
+(in
+thousands) 
+First
+quarter 2006 - 
+IF
+ANR OK 
+150,000 
+$ 
+8.00 
+$ 
+9.15 
+(57 
+) 
+IF
+PEPL 
+820,000 
+$ 
+9.12 
+$ 
+19.78 
+621 
+IF
+HSC 
+570,000 
+$ 
+8.97 
+$ 
+20.99 
+388 
+NYMEX
+Henry Hub 
+440,000 
+$ 
+10.00 
+$ 
+24.00 
+119 
+Second
+quarter 2006 - 
+IF
+ANR OK 
+350,000 
+$ 
+6.89 
+$ 
+9.13 
+(322 
+) 
+IF
+PEPL 
+760,000 
+$ 
+7.27 
+$ 
+13.55 
+28 
+IF
+CIG 
+70,000 
+$ 
+7.00 
+$ 
+11.52 
+8 
+IF
+HSC 
+480,000 
+$ 
+7.71 
+$ 
+13.80 
+35 
+NYMEX
+Henry Hub 
+400,000 
+$ 
+8.00 
+$ 
+14.50 
+(11 
+) 
+Third
+quarter 2006 - 
+IF
+ANR OK 
+450,000 
+$ 
+6.92 
+$ 
+9.28 
+(528 
+) 
+IF
+PEPL 
+720,000 
+$ 
+7.27 
+$ 
+13.54 
+(71 
+) 
+IF
+CIG 
+210,000 
+$ 
+7.00 
+$ 
+11.52 
+(16 
+) 
+IF
+HSC 
+430,000 
+$ 
+7.71 
+$ 
+13.80 
+(66 
+) 
+NYMEX
+Henry Hub 
+330,000 
+$ 
+8.00 
+$ 
+14.50 
+(37 
+) 
+Fourth
+quarter 2006 - 
+IF
+ANR OK 
+100,000 
+$ 
+7.00 
+$ 
+9.82 
+(96 
+) 
+IF
+PEPL 
+655,000 
+$ 
+7.90 
+$ 
+14.07 
+(21 
+) 
+IF
+CIG 
+390,000 
+$ 
+7.23 
+$ 
+12.51 
+(31 
+) 
+IF
+HSC 
+400,000 
+$ 
+8.10 
+$ 
+14.20 
+11 
+NYMEX
+Henry Hub 
+270,000 
+$ 
+8.63 
+$ 
+15.54 
+(33 
+) 
+2007
+- 
+IF
+PEPL 
+7,960,000 
+$ 
+7.35 
+$ 
+10.74 
+(5,033 
+) 
+IF
+CIG 
+3,120,000 
+$ 
+6.66 
+$ 
+9.36 
+(1,787 
+) 
+IF
+HSC 
+1,240,000 
+$ 
+7.84 
+$ 
+10.60 
+(902 
+) 
+NYMEX
+Henry Hub 
+790,000 
+$ 
+8.28 
+$ 
+11.32 
+(646 
+) 
+49 
+Gas
+Collars (continued) 
+Contract
+Period 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+Fair
+Value at 
+December
+31, 2005 
+Asset/(Liability) 
+(MMBtu) 
+(per
+MMBtu) 
+(per
+MMBtu) 
+(in
+thousands) 
+2008
+- 
+IF
+PEPL 
+6,600,000 
+$ 
+6.28 
+$ 
+9.42 
+(5,353 
+) 
+IF
+CIG 
+2,880,000 
+$ 
+5.60 
+$ 
+8.72 
+(1,658 
+) 
+IF
+HSC 
+960,000 
+$ 
+6.57 
+$ 
+9.70 
+(755 
+) 
+NYMEX
+Henry Hub 
+480,000 
+$ 
+7.00 
+$ 
+10.57 
+(365 
+) 
+2009
+- 
+IF
+PEPL 
+5,510,000 
+$ 
+5.30 
+$ 
+9.25 
+(4,537 
+) 
+IF
+CIG 
+2,400,000 
+$ 
+4.75 
+$ 
+8.82 
+(1,175 
+) 
+IF
+HSC 
+840,000 
+$ 
+5.57 
+$ 
+9.49 
+(690 
+) 
+NYMEX
+Henry Hub 
+360,000 
+$ 
+6.00 
+$ 
+10.35 
+(266 
+) 
+2010
+- 
+IF
+PEPL 
+4,945,000 
+$ 
+5.31 
+$ 
+7.61 
+(4,157 
+) 
+IF
+CIG 
+2,040,000 
+$ 
+4.85 
+$ 
+7.08 
+(1,011 
+) 
+IF
+HSC 
+600,000 
+$ 
+5.57 
+$ 
+7.88 
+(496 
+) 
+NYMEX
+Henry Hub 
+240,000 
+$ 
+6.00 
+$ 
+8.38 
+(195 
+) 
+2011
+- 
+IF
+PEPL 
+4,225,000 
+$ 
+5.31 
+$ 
+6.51 
+(3,438 
+) 
+IF
+CIG 
+1,800,000 
+$ 
+5.00 
+$ 
+6.32 
+(621 
+) 
+IF
+HSC 
+480,000 
+$ 
+5.57 
+$ 
+6.77 
+(392 
+) 
+NYMEX
+Henry Hub 
+120,000 
+$ 
+6.00 
+$ 
+7.25 
+(93 
+) 
+All
+gas collars 
+$ 
+(33,649 
+) 
+Please
+see Note 10 - Derivative Financial Instruments in Part IV, Item 15 of
+this report for additional information regarding our oil and gas
+hedges. 
+Summary
+of Interest Rate Hedges in Place 
+We
+entered into fixed-to-floating interest rate swaps on $50 million of
+convertible notes on October 3, 2003. Due to continuing increases in
+interest rates, we entered into a floating-to-fixed interest rate swap on
+April 13, 2005, through March 20, 2007, on this same
+notional amount of $50 million in order to effectively offset our
+fixed-to-floating interest rate swaps. Under the floating-to-fixed interest
+rate
+swap, we will be paid a variable interest rate of 235 basis points above the
+six-month LIBOR rate as determined on the semi-annual settlement date and will
+pay a fixed interest rate of 6.85 percent. The impact of this instrument,
+when combined with the other interest rate swaps, is that we have fixed our
+net
+liability related to the interest rate swaps, and we will pay a 1.1 percent
+interest factor on $50 million of notional debt through March 2007.
+The payment dates of the swap match exactly with the interest payment dates
+of
+the convertible notes and the fixed-to-floating interest rate swaps. Increasing
+interest rates and a higher average outstanding credit facility balance resulted
+in a higher interest expense of $8.2 million in 2005 compared with $6.2 million
+in 2004. 
+Market
+risk is estimated as the potential change in fair value resulting from an
+immediate hypothetical one-percentage point parallel shift in the yield curve.
+For fixed-rate debt, interest rate changes affect the fair market value but
+do
+not impact results of operations or cash flows. Conversely, interest rate
+changes for floating-rate debt generally do not affect the fair market value
+but
+do impact future results of operations and cash flows, assuming other factors
+are held constant. The carrying amount of our floating-rate debt typically
+approximates its fair value, although we had no floating rate debt outstanding
+as of December 31, 2005. Our fixed rate debt outstanding at this same date
+was
+$99.9 million associated with the Convertible Notes. Based on the character
+of our debt outstanding as of the end of the year, we do not believe there
+is
+any cash flow impact that could result from a change in interest
+rates. 
+50 
+Please
+see Note 10 of Part IV, Item 15 of this report for additional
+information regarding our interest rate swaps. 
+Schedule
+of contractual obligations 
+The
+following table summarizes our future estimated principal payments and minimum
+lease payments for the periods specified (in millions): 
+Contractual
+Obligations 
+Total 
+Less
+than 
+1
+year 
+1-3
+years 
+3-5
+years 
+More
+than 
+5
+years 
+Long-Term
+Debt 
+$ 
+107.8 
+$ 
+6.2 
+$ 
+101.6 
+$ 
+- 
+$ 
+- 
+Operating
+Leases 
+9.3 
+2.5 
+4.1 
+2.3 
+0.4 
+Other
+Long-Term Liabilities 
+76.6 
+5.2 
+69.3 
+1.0 
+1.1 
+Total 
+$ 
+193.7 
+$ 
+13.9 
+$ 
+175.0 
+$ 
+3.3 
+$ 
+1.5 
+This
+table excludes the unfunded portion of our estimated pension liability of $1.9
+million, as we cannot determine with accuracy the timing of future payments.
+We
+have made payments of $1.1 million, $1.3 million, and $901,000 in 2005, 2004
+and
+2003, respectively, towards the pension liability. The table also excludes
+estimated payments associated with our Net Profits Plan. We record a liability
+for the estimated future payments. However, predicting the precise timing of
+payments associated with this liability is contingent upon estimates of
+appropriate discount factors, adjusting for risk and time-value, and upon a
+number of factors that we cannot control. We do believe that the cash outflow
+in
+the next two years will be greater than the magnitude of payments that were
+made
+in 2005. We have excluded asset retirement obligations because we are not able
+to precisely predict the timing for these amounts. Pension liabilities and
+asset
+retirement obligations are discussed in Note 8 and Note 9 of Part IV, Item
+15, respectively, and the Net Profits Plan is discussed in Note 7 of Part IV,
+Item 15 of this report. 
+Two
+leases for office space will expire in less than one year, and two office space
+leases will expire in the second year. Estimated costs to replace these leases
+are not included in the table above. 
+For
+purposes of the table we assume that the holders of our Convertible Notes will
+not exercise the conversion feature. If the holders do exercise their conversion
+feature, we will not have to repay the $99.9 million upon conversion but instead
+will issue 7,692,307 shares of common stock. 
+We
+believe that we will continue to pay annual dividends of at least $0.10 per
+share. We anticipate making cash payments for income taxes, dependent on net
+income and capital spending. 
+Included
+in the other long-term liabilities line is approximately $64 million related
+to
+noncurrent accrued derivative liability. 
+Off-Balance
+Sheet Arrangements 
+Aside
+from operating leases we do not have any off-balance sheet financing nor do
+we
+have any unconsolidated subsidiaries. 
+Critical
+Accounting Policies and Estimates 
+We
+are
+engaged in the exploration, development, acquisition and production of natural
+gas and crude oil. Our discussion of financial condition and results of
+operation is based upon the information reported in our consolidated financial
+statements. The preparation of these consolidated financial statements requires
+us to make assumptions and estimates that affect the reported amounts of assets,
+liabilities, revenues and expenses as well as the disclosure of contingent
+assets and liabilities at the date of our financial statements. We base our
+decisions affecting the estimates we use on historical experience and various
+other sources that are believed to be reasonable under the circumstances. Actual
+results may differ from the estimates we calculate due to changing business
+conditions or unexpected circumstances. Policies we believe are critical to
+understanding our business operations and results of operations are detailed
+below. For additional information on our significant accounting policies you
+should see Note 1 - Summary of Significant Accounting Policies, Note 9 -
+Asset Retirement Obligations, and Note 12 -Disclosures About Oil and Gas
+Producing Activities in Part IV, Item 15 of this report. 
+51 
+Oil
+and gas reserve quantities .
+Estimated reserve quantities and the related estimates of future net cash flows
+are the most important estimates for an exploration and production company
+because they affect the perceived value of our company, are used in comparative
+financial analysis ratios, and are used as the basis for the most significant
+accounting estimates in our financial statements which include the periodic
+calculations of depletion, depreciation and impairment for our proved oil and
+gas properties and the estimates of our liability for future payments under
+the
+Net Profits Plan. Proved oil and gas reserves are the estimated quantities
+of
+crude oil, natural gas and natural gas liquids which geological and engineering
+data demonstrate with reasonable certainty to be recoverable in future periods
+from known reservoirs under existing economic and operating conditions. Future
+cash inflows and future production and development costs are determined by
+applying benchmark prices and costs, including transportation, quality and
+basis
+differentials, in effect at the end of each period to the estimated quantities
+of oil and gas remaining to be produced as of the end of that period. Expected
+cash flows are reduced to present value using a discount rate that depends
+upon
+the purpose for which the reserve estimates will be used. For example, the
+standardized measure calculation required by SFAS No. 69, Disclosures about
+Oil
+and Gas Producing Activities, requires a ten percent discount rate to be
+applied. Although reserve estimates are inherently imprecise, and estimates
+of
+new discoveries and undeveloped locations are more imprecise than those of
+established proved producing oil and gas properties, we make considerable effort
+to estimate our reserves, including the use of independent reserve engineering
+consultants. We expect that periodic reserve estimates will change in the future
+as additional information becomes available or as oil and gas prices and
+operating and capital costs change. We evaluate and estimate our oil and gas
+reserves at December 31 and June 30 of each year. For purposes of depletion,
+depreciation, and impairment, reserve quantities are adjusted at all interim
+periods for the estimated impact of additions and dispositions. Changes in
+depletion, depreciation or impairment calculations caused by changes in reserve
+quantities or net cash flows are recorded in the period that the reserve
+estimates change. 
+52 
+The
+following table presents information regarding reserve changes from period
+to
+period that reflect changes from items we do not control, such as price, and
+from changes resulting from better information due to production history and
+well performance. These changes do not require a capital expenditure on our
+part, but may have resulted from capital expenditures we incurred to develop
+other estimated proved reserves. 
+Years
+Ended December 31, 
+2005 
+2004 
+2003 
+MMCFE 
+Percent
+of total 
+MMCFE 
+Percent
+of total 
+MMCFE 
+Percent
+of total 
+Change 
+Additions 
+Change 
+Additions 
+Change 
+Additions 
+Revisions
+resulting 
+from
+price changes 
+23,095 
+10 
+% 
+16,206 
+11 
+% 
+6,750 
+3 
+% 
+Revisions
+resulting 
+From
+performance 
+10,817 
+5 
+% 
+(26,127 
+) 
+(18 
+)% 
+14,290
+6 
+% 
+Total 
+33,912 
+15 
+% 
+(9,921 
+) 
+(7 
+)% 
+21,040 
+9 
+% 
+Over
+the
+three-year period, we added 592.6 BCFE of reserves. Of these, 46.1 BCFE, or
+eight percent, was a result of price changes. A one BCFE reduction in reserves
+was a result of changes in estimates based on the performance of our oil and
+gas
+properties. As previously noted, oil and gas prices are volatile, and estimates
+of reserves are inherently imprecise. Consequently, we anticipate we will
+continue to experience these types of changes. 
+The
+following table reflects the estimated MMCFE change and percentage change to
+our
+total reported reserve volumes from the described hypothetical
+changes: 
+Years
+Ended December 31, 
+2005 
+2004 
+2003 
+MMCFE 
+Percent 
+MMCFE 
+Percent 
+MMCFE 
+Percent 
+Change 
+Change 
+Change 
+Change 
+Change 
+Change 
+A
+A
+10% decrease in pricing 
+(28,940 
+) 
+(4 
+%) 
+(16,672 
+) 
+(3 
+%) 
+(9,479 
+) 
+(2%) 
+A
+A
+10% decrease in proved 
+undeveloped
+reserves 
+(14,554 
+) 
+(2 
+%) 
+(9,839 
+) 
+(1 
+%) 
+(6,744 
+) 
+(1%) 
+Additional
+reserve information can be found in the reserve table and discussion included
+in
+Item 1 of Part I of this report. 
+Successful
+efforts method of accounting. Generally
+accepted accounting principles provide for two alternative methods for the
+oil
+and gas industry to use in accounting for oil and gas producing activities.
+These two methods are generally known in our industry as the full cost method
+and the successful efforts method. Both methods are widely used. The methods
+are
+different enough that in many circumstances the same set of facts will provide
+materially different financial statement results within a given year. We have
+chosen the successful efforts method of accounting for our oil and gas producing
+activities, and a detailed description is included in Note 1 of Part IV, Item
+15
+of this report. 
+Revenue
+recognition .
+Our
+revenue recognition policy is significant because revenue is a key component
+of
+our results of operations and our forward-looking statements contained in our
+analyses of liquidity and capital resources. We derive our revenue primarily
+from the sale of produced natural gas and crude oil. We report revenue as the
+gross amounts we receive before taking into account production taxes and
+transportation costs, which are reported as separate expenses. Revenue is
+recorded in the month our production is delivered to the purchaser, but payment
+is generally received between 30 and 90 days after the date of production.
+No
+revenue is recognized unless it is determined that title to the product has
+transferred to a purchaser. At the end of each month we make estimates of the
+amount of production delivered to the purchaser and the price we will receive.
+We use our knowledge of our properties, their historical performance, the
+anticipated effect of weather conditions during the month of production, NYMEX
+and local spot market prices and other factors as the basis for these estimates.
+Variances between our estimates and the actual amounts received are recorded
+in
+the month payment is received. A ten percent change in our year-end revenue
+accrual would have impacted net income before tax by $13.9 million in
+2005. 
+53 
+Crude
+oil and natural gas hedging .
+Our
+crude oil and natural gas hedging contracts usually qualify for cash flow
+deferral hedge accounting under SFAS No. 133. Under this accounting
+pronouncement a majority of the gain or loss from a contract qualifying as
+a
+cash flow hedge is deferred as to statement of operations recognition. The
+position reflected in the statement of operations is based on the actual
+settlements with the counterparty. If our natural gas and crude oil hedge
+contracts did not qualify for hedge accounting treatment or we chose not to
+use
+this hedge accounting methodology, our periodic statements of operations could
+include significant changes in the estimate of non-cash derivative gain or
+loss
+due to swings in the value of these contracts. Consequently, we would report
+a
+different amount for oil and gas hedge loss in our statements of operations.
+These fluctuations could be especially significant in a volatile pricing
+environment such as what we have encountered over the last three years. Net
+income after tax would have increased or (decreased) for 2005, 2004 and 2003
+by
+the following amounts: ($57.2 million), $2.6 million, and ($14.3 million),
+respectively, if our hedges did not qualify as cash flow deferral hedges under
+SFAS 133. 
+Change
+in Net Profits Plan Liability .
+We
+record the estimated liability of future payments for our Net Profit Plan.
+The
+estimated liability is calculated based on a number of assumptions, including
+estimates of oil and gas reserves, recurring and workover lease operating
+expense, product and ad valorem tax rates, present value discount factors and
+pricing assumptions. Additional discussion is included in the analysis in the
+above section titled Overview of the Company, under the heading Net
+Profits Plan .
+Asset
+retirement obligations. We
+are required
+to recognize an estimated liability for future costs associated with the
+abandonment of our oil and gas properties. We base our estimate of the liability
+on our historical experience in abandoning oil and gas wells projected into
+the
+future based on our current understanding of federal and state regulatory
+requirements. Our present value calculations require us to estimate the economic
+lives of our properties, assume what future inflation rates apply to external
+estimates as well as determine what credit adjusted risk-free rate to use.
+The
+statement of operations impact of these estimates is reflected in our
+depreciation, depletion and amortization calculations and occurs over the
+remaining life of our oil and gas properties. 
+Valuation
+of long-lived and intangible assets. Our
+property and equipment is recorded at cost. An impairment allowance is provided
+on unproved property when we determine that the property will not be developed
+or the carrying value will not be realized. We evaluate the realizability of
+our
+proved properties and other long-lived assets whenever events or changes in
+circumstances indicate that impairment may be appropriate. Our impairment test
+compares the expected undiscounted future net revenues from a property, using
+escalated pricing, with the related net capitalized costs of the property at
+the
+end of each period. When the net capitalized costs exceed the undiscounted
+future net revenue of a property, the cost of the property is written down
+to
+our estimate of fair value, which is determined by applying a discount rate
+that
+we believe is indicative of the current market. Our criteria for an acceptable
+internal rate of return are subject to change over time. Different pricing
+assumptions or discount rates could result in a different calculated
+impairment. 
+Income
+taxes .
+We
+provide for deferred income taxes on the difference between the tax basis of
+an
+asset or liability and its carrying amount in our financial statements in
+accordance with SFAS No. 109, Accounting for Income Taxes. This
+difference will result in taxable income or deductions in future years when
+the
+reported amount of the asset or liability is recovered or settled, respectively.
+Considerable judgment is required in determining when these events may occur
+and
+whether recovery of an asset is more likely than not. Additionally, our federal
+and state income tax returns are generally not filed before the consolidated
+financial statements are prepared, therefore we estimate the tax basis of our
+assets and liabilities at the end of each period as well as the effects of
+tax
+rate changes, tax credits and net operating and capital loss carryforwards
+and
+carrybacks. Adjustments related to differences between the estimates we used
+and
+actual amounts we reported are recorded in the period in which we file our
+income tax returns. These adjustments and changes in our estimates of asset
+recovery could have an impact on our results of operations. A one percent change
+in our effective tax rate would have affected our calculated income tax expense
+by $2.4 million for the year ended December 31, 2005. 
+54 
+Stock-based
+compensation. 
+We have
+historically accounted for stock-based compensation using the intrinsic value
+recognition and measurement principles detailed in Accounting Principles Board
+Opinion No. 25, Accounting for Stock Issued to Employees. No stock-based
+employee compensation expense relating to stock options has been reflected
+in
+our expense as all options granted under our plans had an exercise price equal
+to the market value of the underlying common stock on the date of grant. We
+currently use the Black-Scholes option valuation model to calculate required
+disclosures under SFAS No. 123, Accounting for Stock Based Compensation. As
+of
+January 1, 2006, we have adopted the provision of SFAS No. 123(R), “Share-Based
+Payment.” This statement requires us to record expense associated with the fair
+value of stock-based compensation. As a result of adoption of this statement,
+we
+expect to record compensation expense associated with unvested stock options
+totaling $2.2 million recorded in future periods under the modified-prospective
+adoption method. We have recorded expense associated with the issuance of
+restricted stock units since the plan was adopted in 2004 and units were first
+issued. Going forward this expense will decrease on a relative per share basis
+for all units that have already been issued because the accounting standard
+requires cost recognition using fair value estimates of the restricted stock
+units, rather than intrinsic value. 
+Additional
+Comparative Data in Tabular Format: 
+Change
+Between Years 
+Oil
+and Gas Production Revenues : 
+2005
+and 2004 
+2004
+and 2003 
+Increase
+in oil and gas production 
+revenues
+(in thousands) 
+$ 
+297,687 
+$ 
+48,204 
+Components
+of Revenue Increases (Decreases): 
+Oil 
+Realized
+price change per Bbl 
+$ 
+18.40 
+$ 
+5.57 
+Realized
+price percentage change 
+57% 
+21% 
+Production
+change (MBbl) 
+1,128 
+258 
+Production
+percentage change 
+23% 
+6% 
+Natural
+Gas 
+Realized
+price change per Mcf 
+$ 
+2.38 
+$ 
+0.63 
+Realized
+price percentage change 
+43% 
+13% 
+Production
+change (MMcf) 
+5,204 
+(3,065) 
+Production
+percentage change 
+11% 
+(6)% 
+Our
+product mix as a percentage of total oil and gas revenue and
+production: 
+Years
+Ended December 31, 
+Revenue 
+2005 
+2004 
+2003 
+Oil 
+42% 
+38% 
+34% 
+Natural
+Gas 
+58% 
+62% 
+66% 
+Production 
+Oil 
+41% 
+38% 
+35% 
+Natural
+Gas 
+59% 
+62% 
+65% 
+55 
+Information
+regarding the effects of oil and gas hedging activity: 
+Years
+Ended December 31, 
+2005 
+2004 
+2003 
+Oil
+Hedging 
+Percentage
+of oil production hedged 
+24 % 
+45% 
+54% 
+Oil
+volumes hedged (MBbl) 
+1,419 
+2,156 
+2,474 
+Decrease
+in oil revenue 
+$ 
+(13.3
+million 
+) 
+$ 
+(34.8
+million 
+) 
+$ 
+(11.1
+million 
+) 
+Average
+realized oil price per Bbl before hedging 
+$ 
+53.18 
+$ 
+39.77 
+$ 
+29.40 
+Average
+realized oil price per Bbl after hedging 
+$ 
+50.93 
+$ 
+32.53 
+$ 
+26.96 
+Natural
+Gas Hedging 
+Percentage
+of gas production hedged 
+25% 
+25% 
+40% 
+Natural
+gas volumes hedged (MMBtu) 
+14.0
+million 
+12.9
+million 
+21.7
+million 
+Decrease
+in gas revenue 
+$ 
+(9.2
+million 
+) 
+$ 
+(15.5
+million 
+) 
+$ 
+(11.4
+million 
+) 
+Average
+Average realized gas price per Mcf before hedging 
+$ 
+8.08 
+$ 
+5.85 
+$ 
+5.12 
+Average
+Average realized gas price per Mcf after hedging 
+$ 
+7.90 
+$ 
+5.52 
+$ 
+4.89 
+Information
+regarding the components of exploration expense: 
+Years
+Ended December 31, 
+Summary
+of Exploration Expense (in millions) 
+2005 
+2004 
+2003 
+Geological
+and geophysical expenses 
+$ 
+7.9 
+$ 
+7.3 
+$ 
+5.1 
+Exploratory
+dry holes 
+8.1 
+4.2 
+8.5 
+Overhead
+and other expenses 
+28.9 
+17.1 
+11.7 
+Total 
+$ 
+44.9 
+$ 
+28.6 
+$ 
+25.3 
+Comparison
+of Financial Results and Trends between 2005 and 2004 
+Oil
+and gas production revenues .
+Average
+net daily production increased 16 percent to 239.4 MMCFE for 2005 compared
+with
+206.0 MMCFE in 2004. The following table presents specific components that
+contributed to the increase in revenue between the two periods: 
+Average
+Net Daily Production 
+Added
+Oil
+and Gas 
+Revenue
+Added 
+Production 
+Costs
+Added 
+(MMCFE) 
+(In
+millions) 
+(In
+millions) 
+Williston
+Basin Middle Bakken Play 
+19.9 
+37.5 
+1.3 
+Paggi-Broussard
+1 
+16.3 
+37.5 
+0.9 
+Border
+acquisition 
+8.3 
+18.2 
+2.1 
+Agate
+acquisition 
+7.0 
+15.2 
+5.0 
+Goldmark
+acquisition 
+3.9 
+7.0 
+3.9 
+Wold
+acquisition 
+3.2 
+8.5 
+3.1 
+Other
+wells completed in 2004 and 2005 
+27.6 
+105.3 
+15.2 
+Other
+acquisitions 
+0.8 
+2.3 
+0.8 
+Total 
+87.0 
+231.5 
+32.3 
+The
+revenue increases in this table also reflect the difference in oil and gas
+prices received between the comparable periods. The production increases are
+offset by natural declines in production from older properties to result in
+the
+net increase in production between the years presented. Additional production
+costs reflect increases resulting from inflation and competition for
+resources. 
+56 
+Oil
+and gas hedge loss. 
+The 55
+percent decrease in total oil and gas hedge loss to $22.5 million was
+caused by a change in the composition of our hedge position and changes in
+oil
+and gas commodity prices. During 2004 we had significant hedge positions related
+to contracts entered into for acquisitions that closed in 2002 and 2003. These
+hedges were at lower fixed contract prices that resulted in a larger realized
+hedge loss during 2004. These hedges expired in late 2004. 
+Oil
+and gas production expenses. Total
+production costs increased $47.4 million or 50 percent to
+$142.9 million for 2005, from $95.5 million in 2004. Our current year
+acquisition of properties added $8.1 million of incremental production
+costs, prior year acquisitions of properties added $6.8 million of incremental
+production costs, and other wells completed in 2004 and 2005 added
+$15.2 million of incremental production costs in 2005 that were not
+reflected in 2004. We experienced an increase in production taxes consistent
+with the increase in revenue from higher realized prices. 
+Total
+oil
+and gas production costs per MCFE increased $0.37 to $1.64 for 2005, compared
+with $1.27 for 2004. This increase is comprised of the
+following: 
+· 
+An
+$0.08 increase in production taxes in our Mid-Continent
+region resulting
+from higher natural gas revenues and the suspension of
+Oklahoma severance
+tax incentives in 2005 due to average natural gas prices
+in excess of
+price caps; 
+· 
+An
+$0.11 increase in production taxes due to higher revenue
+from crude oil in
+our Rocky Mountain and Permian regions; 
+· 
+A
+$0.01 increase in production taxes in our ArkLaTex and Gulf
+coast regions
+reflecting higher natural gas prices offset by additional benefits
+from
+severance tax incentive credits received from Louisiana and
+Texas; 
+· 
+A
+$0.12 increase in recurring LOE reflecting a $0.03 increase
+due to the
+start-up activity in our Hanging Woman Basin coalbed methane
+project, a
+general seven percent increase that we had forecast and cost
+increases we
+had not forecast in our budget process; 
+· 
+A
+$0.05 increase in workover LOE reflecting a $0.04 increase
+in our Rocky
+Mountain region. 
+Exploration
+expense .
+Exploration expense increased 57 percent in 2005. The most significant component
+of our increase to exploration expense was $12.0 million for exploration
+overhead incurred as we increased the size of our geologic and exploration
+staff
+and incentive compensation related to those individuals. 
+General
+and administrative. 
+General
+and administrative expenses increased $10.8 million or 49 percent to
+$32.8 million for 2005, compared with $22.0 million for 2004. G&A
+increased $0.08 to $0.37 per MCFE for 2005 compared to $0.29 per MCFE for the
+period in 2004. The primary driver for the increase in G&A expense per MCFE
+is the increase in payments under the Net Profits Plan. 
+A
+20
+percent increase in employee count has resulted in an increase in base employee
+compensation of $2.9 million between the year ended December 31, 2005, and
+the
+same period of 2004. Oil and gas price increases have triggered additional
+Net
+Profits Plan payouts and have increased the amounts payable to plan
+participants. Consequently, the current period realized expense associated
+with
+the Net Profits Plan has increased by $12.8 million in 2005. The increase
+in Net Profits Plan payments is the result of the significantly higher oil
+and
+gas prices received, which has the effect of increasing the absolute amount
+of
+payments as well as accelerating the time it takes for pools to reach payout.
+Thirteen of our 19 pools are in payout status as of the end of 2005. The cash
+bonus and RSU bonus are $8.3 million higher than last year as a result of our
+overall performance, which includes an evaluation of reserve replacement,
+production increases and net asset value per share enhancement. 
+The
+incentive plan compensation increases combined with a net $1.8 million increase
+in other compensation expense were partially offset by increases in COPAS
+overhead reimbursements and allocation of G&A to exploration expense. COPAS
+overhead reimbursement from operations increased $3.1 million due to an increase
+in operated well count resulting from our drilling and acquisition programs.
+The
+amount of G&A we allocated to exploration expense increased
+$11.9 million due to incentive plan payment increases and increases in our
+technical exploration staff. 
+57 
+Change
+in Future Net Profits Plan Liability .
+For the
+year ended December 31, 2005, this expense increased $81.9 million to
+$106.3 million from $24.4 million for 2004. This increase reflects our
+estimation of the effect of a sustained higher price environment and the impact
+of hedge contracts entered into in 2005 on the performance of individual pools
+as previously described. This liability is a significant management estimate.
+Adjustments to the liability are subject to estimation and may change
+dramatically from period-to-period based on assumptions used for production
+rates, reserve quantities, commodity pricing, discount rates, tax rates and
+production costs. 
+Interest
+expense. 
+Interest
+expense increased by $2.0 million to $8.2 million for 2005 compared to $6.2
+million for 2004. The increase reflects an increase in our average outstanding
+borrowings and higher interest rates on the floating rate portion of our
+long-term debt. Additionally, we received benefits from fixed-to-floating
+interest rate swaps in effect during 2004 that were effectively offset by
+floating-rate-to-fixed-rate interest rate swaps we entered into in
+April 2005. 
+Income
+tax expense .
+Income
+tax expense totaled $86.3 million for 2005 and $53.7 million in 2004, resulting
+in effective tax rates of 36.3 percent and 36.8 percent, respectively. The
+effective rate change from 2004 reflects changes in the mix of the highest
+marginal state tax rates as a result of acquisition and drilling activity and
+also reflects other permanent differences including the estimated effect of
+the
+domestic production activities deduction from the American Jobs Creation Act
+of 2004. 
+The
+current portion of income tax expense in 2005 is $80.8 million compared to
+$22.5 million in 2004. These amounts are 94 percent and 42 percent of
+total income tax expense for the respective periods. The difference results
+from
+increased estimated taxable income caused by the higher price environment,
+a
+decreased estimated percentage of deductible intangible drilling costs relative
+to gross revenue, and the effect of the change in Net Profit Plan liability,
+which is not currently deductible. We project that the current portion of
+taxable income will be lower in 2006 as a result of our increased drilling
+budget. 
+Comparison
+of Financial Results and Trends between 2004 and 2003 
+Oil
+and gas production revenues .
+Average
+net daily production decreased two percent to 206.0 MMCFE for 2004 compared
+with
+210.7 MMCFE in 2003. Wells completed and properties acquired in 2003 and during
+2004 added revenue of $102.8 million and average net daily production of 38.2
+MMCFE in 2004 compared to 2003. These increases are offset by natural declines
+in production from older properties and 3.9 MMCFE per day of 2003 production
+from properties that were sold in 2003. 
+Oil
+and gas hedge loss. 
+As noted
+in the table above, the 124 percent increase in total oil and gas hedge loss
+to
+$50.3 million for 2004 was caused by a 35 percent increase in the average
+pre-hedge oil price and a 14 percent increase in the pre-hedge gas
+price. 
+Oil
+and gas production expenses. Total
+production costs increased $7.0 million or eight percent to $95.5 million
+for 2004, from $88.5 million in 2003. Our acquisition of properties added
+$2.8 million of incremental production costs, and wells completed in 2003
+and 2004 added $7.7 million of incremental production costs in 2004 that
+were not reflected in 2003. We experienced an increase in production taxes
+consistent with the increase in revenue from higher realized
+prices. 
+Total
+oil
+and gas production costs per MCFE increased $0.12 to $1.27 for 2004, compared
+with $1.15 for 2003. This increase is comprised of the
+following: 
+· 
+A
+$0.07 increase in production taxes due to higher realized
+per MCFE
+prices; 
+· 
+A
+$0.01 increase in transportation costs; 
+· 
+A
+$0.01 decrease in LOE relating to workover
+charges; 
+58 
+· 
+A
+$0.04 increase in LOE that reflects increasing costs
+in our Rocky Mountain
+region; and 
+· 
+A
+$0.01 increase reflecting a general increases in LOE
+per MCFE in our other
+core areas. 
+Exploration
+expense .
+Exploration expense increased 13 percent in 2004. The most significant
+component
+of our increase to exploration expense was $5.5 million for exploration
+overhead
+we incurred as we increased the size of our geologic and exploration
+staff. 
+General
+and administrative expense .
+General
+and administrative expenses increased $807,000 or four percent to $22.0 million
+for 2004, compared with $21.2 million in 2003. The increase in cost on a per
+MCFE basis of $0.01 reflects the effect of the four percent increase in G&A
+and a two percent decrease in production between the respective
+periods. 
+An
+increase in our employee count from 226 to 249 resulted in a general increase
+in
+G&A of $4.2 million between 2004 and 2003. That increase plus a $913,000
+increase in fees that are directly related to Sarbanes-Oxley compliance, and
+a
+$959,000 increase in other professional fees were offset by an increase of
+$5.5 million of general and administrative expense we allocated to
+exploration expense. 
+Change
+in Net Profits Plan liability. For
+the year ended December 31, 2004, the expense related to the change in the
+estimated liability for this plan increased to $24.4 million from
+$5.3 million for 2003. This increase is due to the performance of
+individual pools, the effect of a higher price environment, and the application
+of lower discount rates to reflect the current economics of the market.
+Interest
+expense. 
+Interest
+expense decreased by $1.7 million to $6.2 million for 2004 compared to $8.0
+million for 2003. The decrease reflects the benefit of interest rate swaps
+we
+entered into on October 3, 2003, and decreased average borrowings under our
+credit facility in 2004 relative to the prior year. 
+Income
+tax expense .
+Income
+tax expense totaled $53.7 million for 2004 and $55.9 million in 2003, resulting
+in effective tax rates of 36.8 percent and 38.3 percent, respectively. The
+effective rate change from 2003 reflects percentage depletion and other
+permanent differences as well as changes in the composition of the highest
+marginal state tax rates as a result of acquisition and drilling activity.
+The
+cumulative effect of the change in marginal state tax rates that we recorded
+in
+2004 was a result of filing our 2003 income tax returns and completing the
+evaluation of the impact on future temporary difference reversals. 
+The
+current portion of the income tax expense in 2004 was $22.5 million compared
+to
+$32.2 million in 2003. These amounts are 42 percent and 58 percent of the
+total tax for the respective periods. The difference results from decreased
+estimated taxable income caused by an increase in the estimated percentage
+of
+deductible intangible drilling costs relative to total income and the effect
+of
+an increase in stock option exercises. 
+Cumulative
+effect of change in accounting principal, net of income tax 
+On
+January 1, 2003 we adopted SFAS No. 143. The impact of adoption
+resulted in income to us of $8.8 million offset by the deferred income tax
+effect of $3.4 million. See Note 9 in Part IV, Item 15 of this
+report. 
+59 
+Other
+Liquidity and Capital Resource Information 
+Pension
+Benefits 
+Substantially
+all of our employees who meet age and service requirements participate in a
+non-contributory defined benefit pension plan. At December 31, 2005, we recorded
+a $290,000 pre-tax loss in accumulated other comprehensive income related to
+this plan. We believe this obligation will be funded from future cash flows
+from
+operating activities. For purposes of calculating our obligation under the
+plan,
+we have used an expected return on plan assets of 7.5 percent. We think
+this rate of return is appropriate over the long-term given the 60 percent
+equity and 40 percent debt securities mix of investment of plan assets and
+the
+historical rate of return provided by equity and debt securities since the
+1920s. Our estimated actual rate of return was 7.8 percent for 2005 and was
+10.4
+percent for 2004. The difference in investment income using our projected rate
+of return compared to our actual rates of return for the past two years was
+not
+material and will not have a material effect on the results of operation or
+cash
+flows from operating activities in future years. 
+For
+the
+2005 plan year, a 0.25 percentage point decrease in the discount rate combined
+with a 1.9 percentage point increase in the estimated rate of future
+compensation increases caused a $401,000 increase in the projected benefit
+obligation of the plan. We do not believe this change was material and project
+that it will not have a material effect on the results of operations or on
+cash
+flows from operating activities in future periods. 
+We
+also
+have a supplemental non-contributory defined benefit pension plan that covers
+certain management employees. There are no plan assets for this plan. For the
+2005 plan year, a 0.25 percentage point decrease in the discount rate
+combined with a 1.9 percentage point increase in the estimated rate of future
+compensation increases and the payment of $298,000 in prior year benefits caused
+a $464,000 decrease in the projected benefit obligation for this plan. This
+plan’s accumulated benefit obligation was $1.1 million at December 31, 2005, and
+$1.2 million at December 31, 2004. We believe this obligation will be funded
+from future cash flows from operating activities. 
+Accounting
+Matters 
+We
+recognized a $5.4 million gain net of income tax in 2003 from the adoption
+of
+SFAS No. 143 effective January 1, 2003. 
+Environmental 
+St. Mary’s
+compliance with applicable environmental regulations has not resulted in any
+significant capital expenditures or materially adverse effects to our liquidity
+or results of operations. We believe we are in substantial compliance with
+environmental regulations and foresee that no material expenditures will be
+incurred in the future. However, we are unable to predict the impact that future
+compliance with regulations may have on future capital expenditures, liquidity
+and results of operations. 
+ITEM
+7A. QUANTITATIVE
+AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+The
+information required by this item is provided under the captions “Commodity
+Price Risk and Interest Rate Risk,” “Summary of Oil and Gas Production Hedges in
+Place,” and “Summary of Interest Rate Hedges in Place” in Item 7 above and
+is incorporated herein by reference. 
+ITEM
+8. FINANCIAL
+STATEMENTS AND SUPPLEMENTARY DATA 
+The
+Consolidated Financial Statements that constitute Item 8 follow the text of
+this
+report. An index to the Consolidated Financial Statements and Schedules appears
+in Item 15(a) of this report. 
+60 
+ITEM
+9. CHANGES
+IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
+DISCLOSURE 
+None. 
+ITEM
+9A. CONTROLS
+AND PROCEDURES 
+We
+maintain a system of disclosure controls and procedures that are designed to
+ensure that information required to be disclosed in our SEC reports is recorded,
+processed, summarized and reported within the time periods specified in the
+SEC’s rules and forms, and to ensure that such information is accumulated and
+communicated to our management, including the Chief Executive Officer and the
+Chief Financial Officer, as appropriate to allow timely decisions regarding
+required disclosure. 
+We
+carried out an evaluation, under the supervision and with the participation
+of
+our management, including the Chief Executive Officer and the Chief Financial
+Officer, of the effectiveness of the design and operation of our disclosure
+controls and procedures as of the end of the period covered by this Annual
+Report on Form 10-K. Based upon that evaluation, the Chief Executive Officer
+and
+the Chief Financial Officer concluded that our disclosure controls and
+procedures are effective for the purposes discussed above as of the end of
+the
+period covered by this Annual Report on Form 10-K. There was no change in our
+internal control over financial reporting that occurred during our most recent
+fiscal quarter that has materially affected, or is reasonably likely to
+materially affect, our internal control over financial reporting. 
+MANAGEMENT’S
+REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 
+To
+the
+Stockholders’ of St. Mary Land & Exploration Company 
+Management
+of the Company is responsible for establishing and maintaining adequate internal
+control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f)
+under the Securities Exchange Act of 1934, as amended. The Company’s internal
+control over financial reporting is designed to provide reasonable assurance
+regarding the reliability of financial reporting and the preparation of
+financial statements for external purposes in accordance with generally accepted
+accounting principles. The Company’s internal control over financial reporting
+includes those policies and procedures that: 
+(i) 
+pertain
+to the maintenance of records that, in reasonable detail, accurately
+and
+fairly reflect the transactions and dispositions of the assets of
+the
+Company; 
+(ii) 
+provide
+reasonable assurance that transactions are recorded as necessary
+to permit
+preparation of financial statements in accordance with generally
+accepted
+accounting principles, and that receipts and expenditures of the
+Company
+are being made only in accordance with authorizations of management
+and
+directors of the Company; and 
+(iii) 
+provide
+reasonable assurance regarding prevention or timely detection of
+unauthorized acquisition, use or disposition of the Company’s assets that
+could have a material effect on the financial
+statements. 
+Because
+of the inherent limitations, internal control over financial reporting may
+not
+prevent or detect misstatements. Also, projections of any evaluation of
+effectiveness to future periods are subject to the risk that controls may become
+inadequate because of changes in conditions, or that the degree of compliance
+with the policies or procedures may deteriorate. 
+Management
+assessed the effectiveness of the Company’s internal control over financial
+reporting as of December 31, 2005. In making this assessment, management used
+the criteria set forth by the Committee of Sponsoring Organizations of the
+Treadway Commission in Internal
+Control-Integrated Framework . 
+61 
+Based
+on
+our assessment and those criteria, management believes that the Company
+maintained effective internal control over financial reporting as of December
+31, 2005. 
+The
+Company’s independent registered public accounting firm has issued an
+attestation report on management’s assessment of the Company’s internal controls
+over financial reporting. That report immediately follows this
+report. 
+/S/
+MARK A. HELLERSTEIN 
+/S/
+DAVID W. HONEYFIELD 
+Mark A. Hellerstein 
+David W. Honeyfield 
+Chairman, CEO and President 
+Vice President - CFO, Secretary &
+Treasurer 
+February 23, 2006 
+February 23,
+2006 
+REPORT
+OF
+INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To
+the
+Board of Directors and Stockholders of 
+St.
+Mary
+Land & Exploration Company and Subsidiaries 
+We
+have
+audited management’s assessment, included in the accompanying Management’s
+Report on Internal Control over Financial Reporting, that St. Mary Land &
+Exploration Company and subsidiaries (the “Company”) maintained effective
+internal control over financial reporting as of December 31, 2005, based on
+criteria established in Internal
+Control—Integrated Framework 
+issued
+by the Committee of Sponsoring Organizations of the Treadway Commission. The
+Company’s management is responsible for maintaining effective internal control
+over financial reporting and for its assessment of the effectiveness of internal
+control over financial reporting. Our responsibility is to express an opinion
+on
+management’s assessment and an opinion on the effectiveness of the Company’s
+internal control over financial reporting based on our audit. 
+We
+conducted our audit in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). Those standards require that we
+plan
+and perform the audit to obtain reasonable assurance about whether effective
+internal control over financial reporting was maintained in all material
+respects. Our audit included obtaining an understanding of internal control
+over
+financial reporting, evaluating management’s assessment, testing and evaluating
+the design and operating effectiveness of internal control, and performing
+such
+other procedures as we considered necessary in the circumstances. We believe
+that our audit provides a reasonable basis for our opinions. 
+A
+company’s internal control over financial reporting is a process designed by, or
+under the supervision of, the company’s principal executive and principal
+financial officers, or persons performing similar functions, and effected by
+the
+company’s board of directors, management, and other personnel to provide
+reasonable assurance regarding the reliability of financial reporting and the
+preparation of financial statements for external purposes in accordance with
+generally accepted accounting principles. A company’s internal control over
+financial reporting includes those policies and procedures that (1) pertain
+to
+the maintenance of records that, in reasonable detail, accurately and fairly
+reflect the transactions and dispositions of the assets of the company; (2)
+provide reasonable assurance that transactions are recorded as necessary to
+permit preparation of financial statements in accordance with generally accepted
+accounting principles, and that receipts and expenditures of the company are
+being made only in accordance with authorizations of management and directors
+of
+the company; and (3) provide reasonable assurance regarding prevention or timely
+detection of unauthorized acquisition, use, or disposition of the company’s
+assets that could have a material effect on the financial
+statements. 
+Because
+of the inherent limitations of internal control over financial reporting,
+including the possibility of collusion or improper management override of
+controls, material misstatements due to error or fraud may not be prevented
+or
+detected on a timely basis. Also, projections of any evaluation of the
+effectiveness of the internal control over financial reporting to future periods
+are subject to the risk that the controls may become inadequate because of
+changes in conditions, or that the degree of compliance with the policies or
+procedures may deteriorate. 
+62 
+In
+our
+opinion, management’s assessment that the Company maintained effective internal
+control over financial reporting as of December 31, 2005, is fairly stated,
+in
+all material respects, based on the criteria established in Internal
+Control—Integrated Framework 
+issued
+by the Committee of Sponsoring Organizations of the Treadway Commission. Also
+in
+our opinion, the Company maintained, in all material respects, effective
+internal control over financial reporting as of December 31, 2005,
+based on the criteria established in Internal
+Control—Integrated Framework 
+issued
+by the Committee of Sponsoring Organizations of the Treadway
+Commission. 
+We
+have
+also audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), the consolidated financial statements as of
+and
+for the year ended December 31, 2005, of the Company, and our report dated
+February 23, 2006, expressed an unqualified opinion on those financial
+statements. 
+/S/
+DELOITTE & TOUCHE LLP 
+Denver,
+Colorado 
+February
+23, 2006 
+ITEM
+9B. OTHER
+INFORMATION 
+None. 
+PART
+III 
+ITEM
+10. DIRECTORS
+AND EXECUTIVE OFFICERS OF THE REGISTRANT 
+The
+information required by this Item concerning St. Mary’s Directors is
+incorporated by reference to the information provided under the captions
+“Election of Directors” and “Nominees for Election of Directors” in
+St. Mary’s definitive proxy statement for the 2006 annual meeting of
+stockholders to be filed within 120 days from December 31, 2005. The
+information required by this Item concerning St. Mary’s executive officers
+is incorporated by reference to the information provided in Part I—Item
+4A—EXECUTIVE OFFICERS OF THE REGISTRANT, included in this Form
+10-K. 
+The
+information required by this Item concerning compliance with Section 16(a)
+of
+the Securities Exchange Act of 1934 is incorporated by reference to the
+information provided under the caption “Section 16(a) Beneficial Ownership
+Reporting Compliance” in St. Mary’s definitive proxy statement for the 2006
+annual meeting of stockholders to be filed within 120 days from
+December 31, 2005. 
+ITEM
+11. EXECUTIVE
+COMPENSATION 
+The
+information required by this Item is incorporated by reference to the
+information provided under the captions, “Director Compensation,” “Executive
+Compensation,” “Report of the Compensation Committee on Executive Compensation,”
+“Retirement Plans,” “Performance Graph,” and “Employee Agreements and
+Termination of Employment and Change-in-Control Arrangements” in St. Mary’s
+definitive proxy statement for the 2006 annual meeting of stockholders to be
+filed within 120 days from December 31, 2005. 
+63 
+ITEM 12. 
+SECURITY
+OWNERSHIP OF
+CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
+AND RELATED STOCKHOLDER
+MATTERS 
+The
+information required by this Item concerning security ownership of certain
+beneficial owners and management is incorporated by reference to the information
+provided under the caption “Security Ownership of Certain Beneficial Owners and
+Management” in St. Mary’s definitive proxy statement for the 2006 annual
+meeting of stockholders to be filed within 120 days from
+December 31, 2005. 
+The
+information required by this Item concerning securities authorized for issuance
+under equity compensation plans is incorporated by reference to the information
+provided under the caption “Equity Compensation Plans” in Part II, Item 5 -
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
+Purchases of Equity Securities, included in this Form 10-K. 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND
+RELATED
+TRANSACTIONS 
+The
+information required by this Item is incorporated by reference to the
+information provided under the caption “Certain Relationships and Related
+Transactions” in St. Mary’s definitive proxy statement for the 2006 annual
+meeting of stockholders to be filed within 120 days from
+December 31, 2005. 
+ITEM 14. 
+PRINCIPAL ACCOUNTING FEES
+AND
+SERVICES 
+The
+information required by this Item is incorporated by reference to the
+information provided under the caption “Independent Accountants” in
+St. Mary’s definitive proxy statement for the 2006 annual meeting of
+stockholders to be filed within 120 days from
+December 31, 2005. 
+64 
+PART
+IV 
+ITEM
+15. EXHIBITS
+AND FINANCIAL STATEMENT SCHEDULES 
+(a)(1)
+and (a)(2) Financial Statements and Financial Statement
+Schedules: 
+Audit
+Report of Independent Registered Public Accounting Firm 
+F-1 
+Consolidated
+Balance Sheets 
+F-2 
+Consolidated
+Statements of Operations 
+F-3 
+Consolidated
+Statements of Stockholders' Equity and Comprehensive Income
+F-4 
+Consolidated
+Statements of Cash Flows 
+F-5 
+Notes
+to Consolidated Financial Statements 
+F-7 
+All
+other
+schedules are omitted because the required information is not applicable or
+is
+not present in amounts sufficient to require submission of the schedule or
+because the information required is included in the Consolidated Financial
+Statements and Notes thereto. 
+(b)
+Exhibits. 
+The
+following exhibits are filed with or incorporated by reference into this report
+on Form 10-K: 
+Exhibit
+Number 
+Description 
+3.1
+Restated
+Certificate of Incorporation of St. Mary Land & Exploration Company as
+amended on May 25, 2005 (filed as Exhibit 3.1 to the registrant's
+Quarterly Report on Form 10-Q for the quarter ended June 30, 2005
+and
+incorporated herein by reference) 
+3.2
+Restated
+By-Laws of St. Mary Land & Exploration Company as amended on March 27,
+2003 (filed as Exhibit 3.2 to the registrant's Quarterly Report on
+Form
+10-Q for the quarter ended March 31, 2003 and incorporated herein
+by
+reference) 
+4.1
+St.
+Mary Land & Exploration Company Shareholder Rights Plan adopted on
+July 15, 1999 (filed as Exhibit 4.1 to the registrant's Quarterly
+Report
+on Form 10-Q/A for the quarter ended June 30, 1999 and incorporated
+herein
+by reference) 
+4.2
+First
+Amendment to Shareholders Rights Plan dated March 15, 2002 as adopted
+by
+the Board of Directors on July 19, 2001 (filed as Exhibit 4.2 to
+the
+registrant's Annual Report on Form 10-K for the year ended December
+31,
+2001 and incorporated herein by reference) 
+10.1 † 
+St.
+Mary Land & Exploration Company Stock Option Plan, As Amended on May
+22, 2003 (filed as Exhibit 99.1 to the registrant's Registration
+Statement
+on Form S-8 (Registration No. 333-106438) and incorporated herein
+by
+reference) 
+10.2†
+St.
+Mary Land & Exploration Company Incentive Stock Option Plan, As
+Amended on March 25, 1999, January 27, 2000, March 29, 2001, March
+27,
+2003 and May 22, 2003 (filed as Exhibit 99.2 to registrant's Registration
+Statement on Form S-8 (Registration No. 333-106438) and incorporated
+herein by reference) 
+10.3†
+Cash
+Bonus Plan (filed as Exhibit 10.5 to the registrant's Registration
+Statement on Form S-1 (Registration No. 33-53512) and incorporated
+herein
+by reference) 
+10.4†
+Summary
+Plan Description/Pension Plan dated December 30, 1994 (filed as Exhibit
+10.35 to the registrant's Annual Report on Form 10-K for the year
+ended
+December 31, 1994 and incorporated herein by reference) 
+10.5†
+Non-qualified
+Unfunded Supplemental Retirement Plan, as amended (filed as Exhibit
+10.8
+to the registrant's Registration Statement on Form S-1 (Registration
+No.
+33-53512) and incorporated herein by reference) 
+10.6†
+St.
+Mary Land & Exploration Company Employee Stock Purchase Plan (filed as
+Exhibit 10.48 filed to the registrant's Annual Report on Form 10-K
+(for
+the year ended December 31, 1997 and incorporated herein by
+reference) 
+10.7†
+First
+Amendment to St. Mary Land & Exploration Company Employee Stock
+Purchase Plan dated February 27, 2001 (filed as Exhibit 10.1 to the
+registrant's Quarterly Report on Form 10-Q for the quarter ended
+June 30,
+2001 and incorporated herein by
+reference) 
+65 
+Exhibit
+Number 
+Description 
+10.8†
+Form
+of Change of Control Severance Agreements (filed as Exhibit 10.1
+to the
+registrant's Quarterly Report on Form 10-Q for the quarter ended
+September
+30, 2001 and incorporated herein by reference) 
+10.9†
+Employment
+Agreement between Registrant and Mark A. Hellerstein (filed as Exhibit
+10.15 to the registrant's Registration Statement on Form S-1 (Registration
+No. 33-53512) and incorporated herein by reference) 
+10.10
+St.
+Mary Land & Exploration Company 5.75% Senior Convertible Notes Due
+2002 Indenture dated March 13, 2002 (filed as Exhibit 10.26 to the
+registrant's Annual Report on Form 10-K for the year ended December
+31,
+2001 and incorporated herein by reference) 
+10.11
+Amendment
+to and Extension of Office Lease dated as of December 14, 2001 (filed
+as
+Exhibit 10.45 to the registrant's Annual Report on Form 10-K for
+the year
+ended December 31, 2003 and incorporated herein by
+reference) 
+10.12†
+St.
+Mary Land & Exploration Company Non-Employee Director Stock
+Compensation Plan as adopted on March 27, 2003 (filed as Exhibit
+10.1 to
+the registrant's Quarterly Report on Form 10-Q for the quarter ended
+June
+30, 2003 and incorporated herein by reference) 
+10.13
+First
+Amendment to Credit Agreement dated January 27, 2003 among St. Mary
+Land
+& Exploration Company, Wachovia Bank, National Association as Issuing
+Bank and Administrative Agent, and the Lenders party thereto (filed
+as
+Exhibit 10.41 to the registrant's Annual Report on Form 10-K for
+the year
+ended December 31, 2003 and incorporated herein by
+reference) 
+10.14†
+Net
+Profits Interest Bonus Plan, As Amended on February 3, 2004 (filed
+as
+Exhibit 10.42 to the registrant's Annual Report on Form 10-K for
+the year
+ended December 31, 2003 and incorporated herein by
+reference) 
+10.15†
+St.
+Mary Land & Exploration Company Restricted Stock Plan as adopted on
+April 18, 2004 (filed as Exhibit 10.1 to the registrant's Quarterly
+Report
+on Form 10-Q for the quarter ended June 30, 2004 and incorporated
+herein
+by reference) 
+10.16
+Second
+Amendment to Credit Agreement dated September 20, 2004 among St.
+Mary Land
+& Exploration Company, Wachovia Bank, National Association as Issuing
+Bank and Administrative Agent, and the Lenders party thereto (filed
+as
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q for
+the
+quarter ended September 30, 2004 and incorporated herein by
+reference) 
+10.17
+Third
+Amendment to Credit Agreement dated October 20, 2004 among St. Mary
+Land
+& Exploration Company, Wachovia Bank, National Association as Issuing
+Bank and Administrative Agent, and the Lenders party thereto (filed
+as
+Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q for
+the
+quarter ended September 30, 2004 and incorporated herein by
+reference) 
+10.18†
+Form
+of Restricted Stock Unit Award Memorandum under the St. Mary Land
+&
+Exploration Company Restricted Stock Plan (filed as Exhibit 10.3
+to the
+registrant's Quarterly Report on Form 10-Q for the quarter ended
+September
+30, 2004 and incorporated herein by reference) 
+10.19†
+Attachment
+A to Form of Change of Control Severance Agreement (filed as Exhibit
+10.47
+to the registrants Annual Report on Form 10-K for the year ended
+December
+31, 2004 and incorporated herein by reference) 
+10.20†
+Second
+Amendment to the St. Mary Land & Exploration Employee Stock Purchase
+Plan dated February 18, 2005 (filed as Exhibit 10.48 to the registrants
+Annual Report on Form 10-K for the year ended December 31, 2004 and
+incorporated herein by reference) 
+10.21
+Amended
+and Restated Credit Agreement dated as of April 7, 2005 among St.
+Mary
+Land & Exploration Company, Wachovia Bank, National Association, as
+Administrative Agent, and the Lenders party thereto (filed as Exhibit
+10.1
+to the registrant's Quarterly Report on Form 10-Q for the quarter
+ended
+March 31, 2005 and incorporated herein by reference) 
+10.22
+Guaranty
+Agreement by St. Mary Energy Company in favor of Wachovia Bank, National
+Association, as Administrative Agent, dated April 7, 2005 (filed
+as
+Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q for
+the
+quarter ended March 31, 2005 and incorporated herein by
+reference) 
+66 
+Exhibit
+Number 
+Description 
+10.23
+Guaranty
+Agreement by Nance Petroleum Corporation in favor of Wachovia Bank,
+National Association, as Administrative Agent, dated April 7, 2005
+(filed
+as Exhibit 10.3 to the registrant's Quarterly Report on Form 10-Q
+for the
+quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.24
+Guaranty
+Agreement by NPC Inc. in favor of Wachovia Bank, National Association,
+as
+Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.4
+to the
+registrant's Quarterly Report on Form 10-Q for the quarter ended
+March 31,
+2005 and incorporated herein by reference) 
+10.25
+Pledge
+and Security Agreement between St. Mary Land & Exploration Company and
+Wachovia Bank, National Association, as Administrative Agent, dated
+April
+7, 2005 (filed as Exhibit 10.5 to the registrant's Quarterly Report
+on
+Form 10-Q for the quarter ended March 31, 2005 and incorporated herein
+by
+reference) 
+10.26
+Pledge
+and Security Agreement between Nance Petroleum Corporation and Wachovia
+Bank, National Association, as Administrative Agent, dated April
+7, 2005
+(filed as Exhibit 10.6 to the registrant's Quarterly Report on Form
+10-Q
+for the quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.27
+First
+Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit
+Mortgage, Assignment, Security Agreement, Fixture Filing and Financing
+Statement for the benefit of Wachovia Bank, National Association,
+as
+Administrative Agent, dated effective as of April 7, 2005 (filed
+as
+Exhibit 10.7 to the registrant's Quarterly Report on Form 10-Q for
+the
+quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.28
+Deed
+of Trust - St. Mary Land & Exploration to Wachovia Bank, National
+Association, as Administrative Agent, dated effective as of April
+7, 2005
+(filed as Exhibit 10.8 to the registrant's Quarterly Report on Form
+10-Q
+for the quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.29† 
+Amendment
+to Form of Change of Control Severance Agreement (filed as Exhibit
+10.9 to
+the registrant's Quarterly Report on Form 10-Q for the quarter ended
+March
+31, 2005 and incorporated herein by reference) 
+10.30†
+Net
+Profits Interest Bonus Plan, As Amended on December 15, 2005 (filed
+as
+Exhibit 10.1 to the registrant's Current Report on Form 8-K filed
+on
+December 19, 2005 and incorporated herein by reference) 
+10.31†
+Amendment
+to Restricted Stock Plan, dated December 15, 2005 (filed as Exhibit
+10.2
+to the registrant's Current Report on Form 8-K filed on December
+19, 2005
+and incorporated herein by reference) 
+10.32†
+Amendment
+to Employment Agreement of Mark A. Hellerstein, dated December 16,
+2005
+(filed as Exhibit 10.3 to the registrant's Current Report on Form
+8-K
+filed on December 19, 2005 and incorporated herein by
+reference) 
+10.33
+Summary
+of Charitable Contributions in Honor of Thomas E. Congdon (filed
+as
+Exhibit 10.4 to the registrant's Current Report on Form 8-K filed
+on
+December 19, 2005 and incorporated herein by reference) 
+10.34†
+Summary
+of 2006 Base Salaries for Named Executive Officers (filed as Exhibit
+10.5
+to the registrant's Current Report on Form 8-K filed on December
+19, 2005
+and incorporated herein by reference) 
+10.35*† 
+Summary
+of Compensation Arrangements for Non-Employee Directors 
+12.1*
+Computation
+of Ratio of Earnings to Fixed Charges 
+14.1
+Code
+of Business Conduct and Ethics (filed as Exhibit 14.1 to the registrant's
+Annual Report on Form 10-k for the year ended December 31, 2003 and
+incorporated herein by reference) 
+21.1*
+Subsidiaries
+of Registrant 
+23.1*
+Consent
+of Deloitte & Touche LLP 
+23.2*
+Consent
+of Ryder Scott Company, L.P. 
+23.3*
+Consent
+of Netherland, Sewell & Associates, Inc. 
+24.1*
+Power
+of Attorney (included in signature page
+hereof) 
+67 
+Exhibit
+Number 
+Description 
+31.1*
+Certification
+of Chief Executive Officer pursuant to Section 302 of the Sarbanes
+- Oxley
+Act of 2002 
+31.2*
+Certification
+of Chief Financial Officer pursuant to Section 302 of the Sarbanes
+- Oxley
+Act of 2002 
+32.1*
+Certification
+pursuant to U.S.C. Section 1350 as adopted pursuant to Section 906
+of the
+Sarbanes - Oxley Act of 2002 
+* 
+Filed with
+this Form
+10-K. 
+† 
+Exhibit
+constitutes a management contract or compensatory plan or arrangement
+(c)
+Financial Statement Schedules. 
+See Item
+15(a) above. 
+68 
+REPORT
+OF
+INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To
+the
+Board of Directors and Stockholders of 
+St.
+Mary
+Land & Exploration Company and Subsidiaries 
+We
+have
+audited the accompanying consolidated balance sheets of St. Mary Land &
+Exploration Company and subsidiaries (the “Company”) as of December 31, 2005 and
+2004, and the related consolidated statements of operations, stockholders’
+equity and comprehensive income, and cash flows for each of the three years
+in
+the period ended December 31, 2005. These financial statements are the
+responsibility of the Company’s management. Our responsibility is to express an
+opinion on these financial statements based on our audits. 
+We
+conducted our audits in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). Those standards require that we
+plan
+and perform the audit to obtain reasonable assurance about whether the financial
+statements are free of material misstatement. An audit includes examining,
+on a
+test basis, evidence supporting the amounts and disclosures in the financial
+statements. An audit also includes assessing the accounting principles used
+and
+significant estimates made by management, as well as evaluating the overall
+financial statement presentation. We believe that our audits provide a
+reasonable basis for our opinion. 
+In
+our
+opinion, such consolidated financial statements present fairly, in all material
+respects, the financial position of St. Mary Land & Exploration Company and
+subsidiaries as of December 31, 2005 and 2004, and the results of
+their operations and their cash flows for each of the three years in the period
+ended December 31, 2005, in conformity with accounting principles generally
+accepted in the United States of America. 
+As
+discussed in Note 9 to the consolidated financial statements, the Company
+changed its method of accounting for asset retirement obligations in 2003 with
+the implementation of Statement of Financial Accounting Standards No. 143
+“Accounting for Asset Retirement Obligations”. 
+We
+have
+also audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), the effectiveness of the Company’s internal
+control over financial reporting as of December 31, 2005, based on the criteria
+established in Internal Control—Integrated Framework issued by the
+Committee of Sponsoring Organizations of the Treadway Commission, and our report
+dated February 23, 2006, expressed an unqualified opinion on management’s
+assessment of the effectiveness of the Company’s internal control over financial
+reporting and an unqualified opinion on the effectiveness of the Company’s
+internal control over financial reporting. 
+/S/
+DELOITTE & TOUCHE LLP 
+Denver,
+Colorado 
+February
+23, 2006 
+F-1 
+PART
+I. FINANCIAL INFORMATION 
+ITEM
+1. FINANCIAL STATEMENTS 
+ST.
+MARY LAND & EXPLORATION COMPANY AND
+SUBSIDIARIES 
+CONSOLIDATED
+BALANCE SHEETS 
+(In
+thousands, except share amounts) 
+December
+31, 
+December
+31, 
+ASSETS 
+2005 
+2004 
+Current
+assets: 
+Cash
+and cash equivalents 
+$ 
+14,925 
+$ 
+6,418 
+Short-term
+investments 
+1,475
+1,412
+Accounts
+receivable 
+165,197
+104,964
+Prepaid
+expenses and other 
+7,283
+5,863
+Deferred
+income taxes 
+8,252
+-
+Accrued
+derivative asset 
+6,799
+8,270
+Total
+current assets 
+203,931
+126,927
+Property
+and equipment (successful efforts method), at cost: 
+Proved
+oil and gas properties 
+1,441,959
+1,124,810
+Less
+- accumulated depletion, depreciation and amortization 
+(497,621 
+) 
+(399,013 
+) 
+Unproved
+oil and gas properties, net of impairment allowance 
+of
+$9,862 in 2005 and $9,867 in 2004 
+44,383
+41,969
+Wells
+in progress 
+55,505
+35,515
+Other
+property and equipment, net of accumulated depreciation 
+of
+$8,046 in 2005 and $6,459 in 2004 
+5,340
+5,244
+1,049,566
+808,525
+Noncurrent
+assets: 
+Goodwill
+9,452
+-
+Accrued
+derivative asset 
+575
+115
+Other
+noncurrent assets 
+5,223
+9,893
+Total
+noncurrent assets 
+15,250
+10,008
+Total
+Assets 
+$ 
+1,268,747 
+$ 
+945,460 
+LIABILITIES
+AND STOCKHOLDERS' EQUITY 
+Current
+liabilities: 
+Accounts
+payable and accrued expenses 
+$ 
+164,957 
+$ 
+110,117 
+Accrued
+derivative liability 
+34,037
+2,502
+Deferred
+income taxes 
+-
+2,273
+Total
+current liabilities 
+198,994
+114,892
+Noncurrent
+liabilities: 
+Long-term
+credit facility 
+-
+37,000
+Convertible
+notes 
+99,885
+99,791
+Asset
+retirement obligation 
+66,078
+40,911
+Net
+Profits Plan liability 
+136,824
+30,561
+Deferred
+income taxes 
+128,296
+129,830
+Accrued
+derivative liability 
+64,137
+2,970
+Other
+noncurrent liabilities 
+5,213
+5,050
+Total
+noncurrent liabilities 
+500,433
+346,113
+Commitments
+and Contingencies (Note 6) 
+Stockholders'
+equity: 
+Common
+stock, $0.01 par value: authorized - 200,000,000 shares; 
+issued:
+57,011,740 shares in 2005 and 57,458,246 shares in 2004; 
+outstanding,
+net of treasury shares: 56,761,740 shares in 2005 
+and
+56,958,246 shares in 2004 
+570
+574
+Additional
+paid-in capital 
+123,278
+127,374
+Treasury
+stock, at cost: 250,000 shares in 2005 and 500,000 shares in
+2004 
+(5,148 
+) 
+(5,295 
+) 
+Deferred
+stock-based compensation 
+(5,593 
+) 
+(5,039 
+) 
+Retained
+earnings 
+510,812
+364,567
+Accumulated
+other comprehensive income (loss) 
+(54,599 
+) 
+2,274
+Total
+stockholders' equity 
+569,320
+484,455
+Total
+Liabilities and Stockholders' Equity 
+$ 
+1,268,747 
+$ 
+945,460 
+The
+accompanying notes are an integral part of these consolidated financial
+statements. 
+F-2 
+ST.
+MARY LAND & EXPLORATION COMPANY AND
+SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF OPERATIONS 
+(In
+thousands, except per share amounts) 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+Operating
+revenues: 
+Oil
+and gas production revenue 
+$ 
+733,544 
+$ 
+463,617 
+$ 
+387,553 
+Oil
+and gas hedge loss 
+(22,539 
+) 
+(50,299 
+) 
+(22,439 
+) 
+Marketed
+gas revenue 
+25,269
+15,551
+13,438
+Gain
+on sale of proved properties 
+222
+1,803
+7,278
+Other
+revenue 
+3,094
+2,427
+7,878
+Total
+operating revenues 
+739,590
+433,099
+393,708
+Operating
+expenses: 
+Oil
+and gas production expense 
+142,873
+95,518
+88,509
+Depletion,
+depreciation, amortization 
+and
+abandonment liability accretion 
+132,758
+92,223
+81,960
+Exploration
+44,931
+28,560
+25,318
+Impairment
+of proved properties 
+-
+494
+185
+Abandonment
+and impairment of unproved properties 
+5,780
+1,420
+3,796
+General
+and administrative 
+32,756
+22,004
+21,197
+Change
+in Net Profits Plan liability 
+106,263
+24,398
+5,317
+Marketed
+gas system operating expense 
+24,164
+14,230
+12,229
+Unrealized
+derivative loss 
+1,615
+260
+310
+Other
+expense 
+2,456
+2,077
+1,576
+Total
+operating expenses 
+493,596
+281,184
+240,397
+Income
+from operations 
+245,994
+151,915
+153,311
+Nonoperating
+income (expense): 
+Interest
+income 
+456
+557
+717
+Interest
+expense 
+(8,213 
+) 
+(6,244 
+) 
+(7,958 
+) 
+Income
+before income taxes and cumulative effect 
+of
+change in accounting principle 
+238,237
+146,228
+146,070
+Income
+tax expense 
+(86,301 
+) 
+(53,749 
+) 
+(55,930 
+) 
+Income
+before cumulative effect of change in accounting principle 
+151,936
+92,479
+90,140
+Cumulative
+effect of change in accounting principle, net of income
+tax 
+-
+-
+5,435
+Net
+income 
+$ 
+151,936 
+$ 
+92,479 
+$ 
+95,575 
+Basic
+weighted-average common shares outstanding 
+56,907
+57,702
+62,467
+Diluted
+weighted-average common shares outstanding 
+66,894
+66,894
+71,069
+Basic
+earnings per common share: 
+Income
+before cumulative effect of change in accounting principle 
+$ 
+2.67 
+$ 
+1.60 
+$ 
+1.44 
+Cumulative
+effect of change in accounting 
+principle,
+net of income tax 
+-
+-
+0.09
+Basic
+net income per common share 
+$ 
+2.67 
+$ 
+1.60 
+$ 
+1.53 
+Diluted
+earnings per common share: 
+Income
+before cumulative effect of change in accounting principle 
+$ 
+2.33 
+$ 
+1.44 
+$ 
+1.32 
+Cumulative
+effect of change in accounting 
+principle,
+net of income tax 
+-
+-
+.08
+Diluted
+net income per common share 
+$ 
+2.33 
+$ 
+1.44 
+$ 
+1.40 
+The
+accompanying notes are an integral part of these
+consolidated financial statements. 
+F-3 
+ST.
+MARY LAND & EXPLORATION COMPANY AND
+SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE
+INCOME 
+(In
+thousands, except share
+amounts) 
+Accumulated 
+Common
+Stock 
+Additional 
+Paid-in 
+Treasury
+Stock 
+Deferred
+Stock-Based 
+Retained 
+Other 
+Comprehensive 
+Total
+Stockholders' 
+Shares 
+Amount 
+Capital 
+Shares 
+Amount 
+Compensation 
+Earnings 
+Income
+(Loss) 
+Equity
+Balances,
+December 31, 2002 
+57,966,220
+$ 
+580 
+$ 
+140,398 
+(2,019,800 
+) 
+$ 
+(16,210 
+) 
+$ 
+- 
+$ 
+182,512 
+$ 
+(7,767 
+) 
+$ 
+299,513 
+Comprehensive
+income, net of tax: 
+Net
+income 
+-
+-
+-
+-
+-
+-
+95,575
+-
+95,575
+Unrealized
+net gain on marketable equity securities available for
+sale 
+-
+-
+-
+-
+-
+-
+-
+716
+716
+Change
+in derivative instrument fair value 
+-
+-
+-
+-
+-
+-
+-
+(21,873 
+) 
+(21,873 
+) 
+Reclassification
+to earnings 
+-
+-
+-
+-
+-
+-
+-
+13,846
+13,846
+Minimum
+pension liability adjustment 
+-
+-
+-
+-
+-
+-
+-
+197
+197
+Total
+comprehensive income 
+88,461
+Cash
+dividends declared, $ 0.05 per share 
+-
+-
+-
+-
+-
+-
+(3,150 
+) 
+-
+(3,150 
+) 
+Issuance
+of common stock under Employee Stock Purchase Plan 
+33,988
+-
+375
+-
+-
+-
+-
+-
+375
+Value
+of option right granted to Flying J 
+-
+-
+995
+-
+-
+-
+-
+-
+995
+Sale
+of common stock, including income tax
+benefit of stock option exercises 
+490,038
+4
+4,302
+-
+-
+-
+-
+-
+4,306
+Directors'
+stock compensation 
+-
+-
+-
+14,400
+153
+-
+-
+-
+153
+Balances,
+December 31, 2003 
+58,490,246
+$ 
+584 
+$ 
+146,070 
+(2,005,400 
+) 
+$ 
+(16,057 
+) 
+$ 
+- 
+$ 
+274,937 
+$ 
+(14,881 
+) 
+$ 
+390,653 
+Comprehensive
+income, net of tax: 
+Net
+income 
+-
+-
+-
+-
+-
+-
+92,479
+-
+92,479
+Change
+in derivative instrument fair value 
+-
+-
+-
+-
+-
+-
+-
+(14,795 
+) 
+(14,795 
+) 
+Reclassification
+to earnings 
+-
+-
+-
+-
+-
+-
+-
+31,849
+31,849
+Minimum
+pension liability adjustment 
+-
+-
+-
+-
+-
+-
+-
+101
+101
+Total
+comprehensive income 
+109,634
+Cash
+dividends declared, $ 0.05 per share 
+-
+-
+-
+-
+-
+-
+(2,849 
+) 
+-
+(2,849 
+) 
+Repurchase
+of common stock from Flying J 
+-
+-
+(19,406 
+) 
+-
+-
+-
+-
+-
+(19,406 
+) 
+Treasury
+stock purchases 
+-
+-
+-
+(978,600 
+) 
+(16,336 
+) 
+-
+-
+-
+(16,336 
+) 
+Retirement
+of treasury stock 
+(2,458,800 
+) 
+(24 
+) 
+(26,725 
+) 
+2,458,800
+26,749
+-
+-
+-
+-
+Issuance
+of common stock under Employee Stock Purchase Plan 
+27,748
+-
+375
+-
+-
+-
+-
+-
+375
+Sale
+of common stock, including income tax benefit of stock option
+exercises 
+1,399,052
+14
+17,832
+-
+-
+-
+-
+-
+17,846
+Deferred
+compensation related to issued restricted stock
+unit awards, net of forfeitures 
+-
+-
+8,122
+-
+-
+(8,122 
+) 
+-
+-
+-
+Accrued
+stock-based compensation 
+-
+-
+1,106
+-
+-
+-
+-
+-
+1,106
+Directors'
+stock compensation 
+-
+-
+-
+25,200
+349
+-
+-
+-
+349
+Amortization
+of deferred stock-based compensation 
+-
+-
+-
+-
+-
+3,083
+-
+-
+3,083
+Balances,
+December 31, 2004 
+57,458,246
+$ 
+574 
+$ 
+127,374 
+(500,000 
+) 
+$ 
+(5,295 
+) 
+$ 
+(5,039 
+) 
+$ 
+364,567 
+$ 
+2,274 
+$ 
+484,455 
+Comprehensive
+income, net of tax: 
+Net
+income 
+-
+-
+-
+-
+-
+-
+151,936
+-
+151,936
+Change
+in derivative instrument fair value 
+-
+-
+-
+-
+-
+-
+-
+(71,522 
+) 
+(71,522 
+) 
+Reclassification
+to earnings 
+-
+-
+-
+-
+-
+-
+-
+14,366
+14,366
+Minimum
+pension liability adjustment 
+-
+-
+-
+-
+-
+-
+-
+283
+283
+Total
+comprehensive income 
+95,063
+Cash
+dividends declared, $ 0.10 per share 
+-
+-
+-
+-
+-
+-
+(5,691 
+) 
+-
+(5,691 
+) 
+Treasury
+stock purchases 
+-
+-
+-
+(1,175,282 
+) 
+(28,902 
+) 
+-
+-
+-
+(28,902 
+) 
+Retirement
+of treasury stock 
+(1,411,356 
+) 
+(14 
+) 
+(28,729 
+) 
+1,411,356
+28,743
+-
+-
+-
+-
+Issuance
+of common stock under Employee Stock
+Purchase Plan 
+28,447
+-
+601
+-
+-
+-
+-
+-
+601
+Sale
+of common stock, including income tax
+benefit of stock option exercises 
+936,403
+10
+16,619
+-
+-
+-
+-
+-
+16,629
+Deferred
+compensation related to issued restricted stock
+unit awards, net of forfeitures 
+-
+-
+3,404
+-
+-
+(3,404 
+) 
+-
+-
+-
+Accrued
+stock-based compensation 
+-
+-
+4,009
+-
+-
+-
+-
+-
+4,009
+Directors'
+stock compensation 
+-
+-
+-
+13,926
+306
+(306 
+) 
+-
+-
+-
+Amortization
+of deferred stock-based compensation 
+-
+-
+-
+-
+-
+3,156
+-
+-
+3,156
+Balances,
+December 31, 2005 
+57,011,740
+$ 
+570 
+$ 
+123,278 
+(250,000 
+) 
+$ 
+(5,148 
+) 
+$ 
+(5,593 
+) 
+$ 
+510,812 
+$ 
+(54,599 
+) 
+$ 
+569,320 
+The
+accompanying notes are an integral part of these
+consolidated financial statements. 
+F-4 
+ST.
+MARY LAND & EXPLORATION COMPANY AND
+SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF CASH FLOWS 
+(In
+thousands) 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+Reconciliation
+of net income to net cash provided 
+by
+operating activities: 
+Net
+income 
+$ 
+151,936 
+$ 
+92,479 
+$ 
+95,575 
+Adjustments
+to reconcile net income to net cash 
+provided
+by operating activities: 
+Gain
+on sale of proved properties 
+(222 
+) 
+(1,803 
+) 
+(7,278 
+) 
+Depletion,
+depreciation, amortization 
+and
+abandonment liability accretion 
+132,758
+92,223
+81,960
+Exploratory
+dry hole expense 
+8,104
+4,162
+8,482
+Impairment
+of proved properties 
+-
+494
+185
+Abandonment
+and impairment of unproved properties 
+5,780
+1,420
+3,796
+Unrealized
+derivative loss 
+1,615
+260
+310
+Change
+in Net Profits Plan liability 
+106,263
+24,398
+5,317
+Deferred
+and accrued stock-based compensation 
+7,165
+4,189
+-
+Income
+tax benefit from the exercise of stock options 
+6,037
+3,816
+1,151
+Deferred
+income taxes 
+5,547
+31,217
+23,692
+Other
+281
+(1,948 
+) 
+2,088
+Cumulative
+effect of change in accounting principle, net of tax 
+-
+-
+(5,435 
+) 
+Changes
+in current assets and liabilities, net of acquisitions: 
+Accounts
+receivable 
+(57,113 
+) 
+(39,880 
+) 
+(29,685 
+) 
+Prepaid
+expenses and other 
+(1,210 
+) 
+157
+490
+Accounts
+payable and accrued expenses 
+42,438
+25,978
+23,671
+Net
+cash provided by operating activities 
+409,379
+237,162
+204,319
+Cash
+flows from investing activities: 
+Proceeds
+from sale of oil and gas properties 
+1,213
+2,829
+23,497
+Capital
+expenditures 
+(270,881 
+) 
+(199,385 
+) 
+(123,823 
+) 
+Acquisition
+of oil and gas properties, including related 
+$71,594
+loan to Flying J in 2003 
+(73,905 
+) 
+(68,805 
+) 
+(76,413 
+) 
+Deposits
+to short-term investments available-for-sale 
+(1,502 
+) 
+(1,470 
+) 
+(12,529 
+) 
+Receipts
+from short-term investments available-for-sale 
+1,427
+12,500
+2,450
+Receipts
+from restricted cash 
+-
+10,353
+11,500
+Deposits
+to restricted cash 
+-
+-
+(21,853 
+) 
+Other
+3,869
+(3,028 
+) 
+232
+Net
+cash used in investing activities 
+(339,779 
+) 
+(247,006 
+) 
+(196,939 
+) 
+Cash
+flows from financing activities: 
+Proceeds
+from credit facility 
+284,090
+181,500
+142,020
+Repayment
+of credit facility 
+(321,090 
+) 
+(155,500 
+) 
+(145,020 
+) 
+Proceeds
+from sale of common stock 
+11,193
+14,030
+3,530
+Repurchase
+of common stock 
+(28,902 
+) 
+(35,743 
+) 
+-
+Dividends
+paid 
+(5,691 
+) 
+(2,849 
+) 
+(3,150 
+) 
+Other
+(693 
+) 
+(3 
+) 
+(1,087 
+) 
+Net
+cash provided by (used in) financing activities 
+(61,093 
+) 
+1,435
+(3,707 
+) 
+Net
+change in cash and cash equivalents 
+8,507
+(8,409 
+) 
+3,673
+Cash
+and cash equivalents at beginning of period 
+6,418
+14,827
+11,154
+Cash
+and cash equivalents at end of period 
+$ 
+14,925 
+$ 
+6,418 
+$ 
+14,827 
+The
+accompanying notes are an integral part of these
+consolidated financial statements. 
+F-5 
+ST.
+MARY LAND & EXPLORATION COMPANY AND
+SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF CASH FLOWS (Continued) 
+Supplemental
+schedule of additional cash flow information and noncash investing
+and
+financing activities: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(in
+thousands) 
+Cash
+paid for interest, net of capitalized interest 
+$ 
+8,458 
+$ 
+6,887 
+$ 
+7,555 
+Cash
+paid for income taxes 
+$ 
+65,752 
+$ 
+14,787 
+$ 
+28,858 
+Included
+in the accounts payable and accrued expenses account balances as
+of
+December 31, 2005 and
+2004 are $51.0 million and $39.2 million, respectively, of additions
+to
+oil and gas properties. These
+oil and gas property additions are reflected in cash used in investing
+activities in the periods
+that the payables are settled. 
+In
+March 2005 and June 2004 the Company issued 194,508 and 465,722
+restricted
+stock units, respectively, pursuant
+to the Company's restricted stock plan. The total value of the
+ssuances
+were $4.9 million and $8.3
+million, respectively. 
+In
+May 2005, May 2004, January 2004, and January 2003 the Company
+issued
+13,926, 16,800, 8,400 and 14,400 shares,
+respectively, of common stock from treasury to its non-employee
+directors.
+The Company recorded compensation
+expense related to the issuances of $179,000 and $349,000 and $153,000
+for
+the years ended December
+31, 2005, 2004 and 2003
+respectively. 
+In
+August 2004 the Company closed a transaction whereby it exchanged
+oil and
+gas properties valued at $1.4 million
+together with $769,000 of cash for oil and gas properties valued
+at $2.2
+million. 
+In
+January 2003 the Company issued 6,761,636 restricted shares of
+common
+stock to Flying J Oil & Gas Inc. and Big
+West Oil & Gas Inc. (collectively, "Flying J") and entered into a put
+and call option agreement, valued at $995,000
+for financial reporting purposes, with Flying J with respect to
+those
+shares in connection with the acquisition
+of oil and gas properties and related assets and liabilities.
+The
+accompanying notes are an integral part of these
+consolidated financial statements. 
+F-6 
+ST. MARY
+LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER
+31, 2005 
+Note
+1 - Summary of Significant Accounting Policies 
+Description
+of Operations 
+St. Mary
+Land & Exploration Company (“St. Mary” or the "Company") is an
+independent energy company engaged in the exploration, exploitation,
+development, acquisition and production of natural gas and crude oil.
+The
+Company’s operations are conducted entirely in the Continental United States and
+the Gulf of Mexico. 
+Basis
+of Presentation 
+The
+consolidated financial statements include the accounts of the Company and its
+wholly owned subsidiaries. Subsidiaries that are not wholly owned are accounted
+for using full consolidation with minority interest or by the equity or cost
+method as appropriate. Equity method investments are included in other
+noncurrent assets, and minority interest is included in other noncurrent
+liabilities in the accompanying consolidated balance sheets. All significant
+intercompany accounts and transactions have been eliminated. 
+Common
+stock and additional paid-in capital amounts have been reclassified for all
+periods presented to reflect a stock dividend distributed in March
+2005. 
+Use
+of Estimates in the Preparation of Financial Statements 
+The
+preparation of financial statements in conformity with accounting principles
+generally accepted in the United States requires management to make estimates
+and assumptions that affect the reported amounts of oil and gas reserves, assets
+and liabilities and disclosure of contingent assets and liabilities at the
+date
+of the financial statements and the reported amounts of revenues and expenses
+during the reporting period. Actual results could differ from those estimates.
+Estimates of oil and gas reserve quantities provide the basis for calculations
+of depletion, depreciation, and amortization (“DD&A”), impairment, goodwill,
+and the Net Profits Plan liability, each of which represents a significant
+component of the consolidated financial statements. 
+Cash
+and Cash Equivalents 
+The
+Company considers all liquid investments purchased with an initial maturity
+of
+three months or less to be cash equivalents. The
+carrying value of cash and cash equivalents approximates fair value due to
+the
+short-term nature of these instruments. 
+Short-term
+Investments 
+The
+Company’s short-term investments consists of investment-grade marketable debt,
+which is classified as held-to-maturity or available-for-sale. Securities
+categorized as held-to-maturity are stated at amortized cost whereas
+available-for-sale securities are marked-to-market. As of December 31, 2005
+and
+2004, the Company held $1.5 million and $1.4 million, respectively, of
+short-term investments. 
+Concentration
+of Credit Risk 
+Substantially
+all of the Company's receivables are within the oil and gas industry, primarily
+from purchasers of oil and gas and from joint interest owners. Although
+diversified among many companies, collectability is dependent upon the financial
+wherewithal of each individual company as well as the general economic
+conditions of the industry. The receivables are not collateralized. To date
+the
+Company has had minimal bad debts. 
+F-7 
+The
+Company has accounts with separate banks in Denver, Colorado; Shreveport,
+Louisiana; Tulsa, Oklahoma; Houston, Texas; and Billings, Montana. At December
+31, 2005, 2004 and 2003, the Company had $36.8 million, $22.2 million,
+and $23.5 million respectively, invested in money market funds, corporate
+commercial paper, repurchase agreements and U.S. Treasury obligations. The
+difference between the investment amount and the cash and cash equivalents
+amount on the consolidated balance sheets, represents uncleared disbursements.
+The Company’s policy is to invest in highly rated instruments and to limit the
+amount of credit exposure at each individual institution. 
+The
+Company currently uses ten separate counterparties for its oil and gas commodity
+and interest rate derivatives. The counterparties to the Company’s derivative
+instruments are all highly rated entities. 
+Oil
+and Gas Producing Activities 
+The
+Company follows the successful efforts method of accounting for its oil and
+gas
+properties. Under this method of accounting, all property acquisition costs
+and
+costs of exploratory and development wells are capitalized when incurred,
+pending determination of whether the well has found proved reserves. If an
+exploratory well does not find proved reserves, the costs of drilling the well
+are charged to expense. Exploratory dry hole costs are included in cash flows
+from investing activities as part of capital expenditures within the
+consolidated statements of cash flows. The costs of development wells are
+capitalized whether productive or nonproductive. 
+Geological
+and geophysical costs and the costs of carrying and retaining unproved
+properties are expensed as incurred. DD&A of capitalized costs of proved oil
+and gas properties is provided on a field-by-field basis using the units of
+production method based upon proved reserves. The computation of DD&A takes
+into consideration restoration, dismantlement and abandonment costs and the
+anticipated proceeds from equipment salvage. As
+of
+December 31, 2005, the Company’s capitalized proved oil and gas properties
+included $76.1 million of estimated salvage value, which is excluded from
+the depletable property costs when calculating DD&A. 
+The
+Company reviews its long-lived assets for impairments when events or changes
+in
+circumstances indicate that an impairment may have occurred. The impairment
+test
+for proved properties compares the expected undiscounted future net revenues
+on
+a field-by-field
+basis
+with the related net capitalized costs, including costs associated with asset
+retirement obligations, at the end of each period. Expected future cash flows
+are calculated on all proved reserves using a discount rate and price forecasts
+selected by the Company’s management. The discount rate is a rate that
+management believes is representative of current market conditions. The price
+forecast is based on NYMEX strip pricing for the first three years and is then
+escalated to and capped at specified maximum prices. Operating costs are also
+adjusted as deemed appropriate for these estimates. When the net capitalized
+costs exceed the undiscounted future net revenues of a field, the cost of the
+field is reduced to fair value, which is determined using discounted future
+net
+revenues. An impairment allowance is provided on unproved property when the
+Company determines the property will not be developed or the carrying value
+is
+not realizable. 
+Sales
+of Proved and Unproved Properties 
+The
+sale
+of a partial interest in a proved property is accounted for as normal
+retirement, and no gain or loss is recognized as long as this treatment does
+not
+significantly affect the units-of-production depletion rate. A gain or loss
+is
+recognized for all other sales of producing properties and is included in the
+results of operations. 
+The
+sale
+of a partial interest in an unproved property is accounted for as a recovery
+of
+cost when substantial uncertainty exists as to recovery of the cost applicable
+to the interest retained. A gain on the sale is recognized to the extent the
+sales price exceeds the carrying amount of the unproved property. A gain or
+loss
+is recognized for all other sales of nonproducing properties and is included
+in
+the results of operations. 
+Other
+Property and Equipment 
+Other
+property and equipment such as office furniture and equipment, automobiles
+and
+computer hardware and software are recorded at cost. Costs of renewals and
+improvements that substantially extend the useful lives of the assets are
+capitalized. Maintenance and repair costs are expensed when incurred.
+Depreciation is provided using the straight-line method over the estimated
+useful lives of the assets from three to 15 years. When other property and
+equipment is sold or retired, the capitalized costs and related accumulated
+depreciation are removed from the accounts. 
+F-8 
+Gas
+Balancing 
+The
+Company uses the sales method of accounting for our gas revenue whereby we
+recognize sales revenue on all gas sold to our purchasers, regardless of whether
+the sales are proportionate to our ownership in the property. An asset or a
+liability is recognized to the extent that we have an imbalance in excess of
+the
+remaining gas reserves on the underlying properties. The Company’s gas imbalance
+position at December 31, 2005 and 2004 resulted in the recording of $1.6 million
+and $1.5 million, respectively, to receivables, and $869,000 and $726,000,
+respectively, to payables. 
+Derivative Financial
+Instruments 
+The
+Company seeks to protect its rate of return on acquisitions of producing
+properties and other production by hedging cash flows. The Company intends
+for
+derivative instruments used for this purpose to be designated as, and to qualify
+as cash flow hedging instruments under SFAS No. 133, “Accounting for Derivative
+Instruments and Hedging Activities,” and related pronouncements. The Company
+seeks to minimize basis risk and indexes the majority of its oil hedges to
+NYMEX
+prices and the majority of its gas hedges to various regional index prices
+associated with pipelines in proximity to the Company's areas of gas production.
+For additional discussion of derivatives, please see Note
+10 -
+Derivative Financial Instruments. 
+Fair
+Value of Financial Instruments 
+The
+Company’s financial instruments including cash and cash equivalents, accounts
+receivable and accounts payable are carried at cost, which approximates fair
+value due to the short-term maturity of these instruments. The recorded value
+of
+the Company’s credit facility approximates its fair value as it bears interest
+at a floating rate; however, no amounts are outstanding as of December 31,
+2005.
+The Company’s interest rate swaps are recorded at fair value as discussed in
+Note 10 - Derivative Financial Instruments. The Company’s 5.75% Senior
+Convertible Notes due 2022 (the “Convertible Notes”) are recorded at cost, and
+the fair value is disclosed in Note 5 - Long-Term Debt. The Company has other
+financial instruments and investments in available-for-sale securities that
+are
+marked-to-market with changes in fair value being recorded in accumulated other
+comprehensive income. Since considerable judgment is required to develop
+estimates of fair value, the estimates provided are not necessarily indicative
+of the amounts the Company could realize upon the sale or refinancing of such
+instruments. 
+Net
+Profits Plan 
+The
+Company records the estimated liability of future payments for its Net Profits
+Plan. The estimated liability is calculated based on a
+number
+of assumptions, including estimates of oil and gas reserves, recurring and
+workover lease operating expense, production and ad valorem tax rates, present
+value discount factors and pricing assumptions. The estimates the Company uses
+in calculating the liability are modified from period-to-period based on the
+most current information attributable to the underlying assumptions. Changes
+in
+the estimated liability of future payments associated with the Net Profits
+Plan
+are recorded as increases or decreases to expense in the current period as
+a
+separate line item in the consolidated statements of operations. The estimated
+Net Profits Plan liability is recorded separately as a noncurrent liability
+in
+the accompanying consolidated balance sheets. 
+The
+amounts due and payable in each period under the Net Profits Plan as cash
+compensation related to periodic operations are recognized as compensation
+expense and are included within general and administrative expense and
+exploration expense. The corresponding current liability is included in accounts
+payable and accrued expenses in the accompanying consolidated balance sheets.
+This treatment provides for a consistent matching of cash expense with net
+cash
+flows from the oil and gas properties in each respective pool of the Net Profits
+Plan. For additional discussion, please see Note 7 - Compensation Plans under
+the heading Net
+Profits Plan. 
+F-9 
+Income
+Taxes 
+Deferred
+income taxes are provided on the difference between the tax basis of an asset
+or
+liability and its carrying amount in the financial statements. This difference
+will result in taxable income or deductions in future years when the reported
+amount of the asset or liability is recovered or settled,
+respectively. 
+Earnings
+per Share 
+Basic
+net
+income per common share of stock is calculated by dividing net income available
+to common stockholders by the weighted-average of common shares outstanding
+during each period. 
+Diluted
+net income per common share of stock is calculated by dividing adjusted net
+income by the weighted-average of common shares outstanding, including the
+effect of other dilutive securities. Adjusted net income is used for the
+if-converted method and is derived by adding interest expense paid on the
+Convertible Notes back to net income and then adjusting for nondiscretionary
+items that are based on income and that would have changed had the Convertible
+Notes been converted at the beginning of the period. The Company’s potentially
+dilutive securities consist of in-the-money outstanding options to purchase
+the
+Company’s common stock, shares into which the Convertible Notes may be converted
+and unvested restricted stock units. 
+The
+shares underlying the grants of restricted stock units are included
+in the diluted earnings per share calculation beginning with the grant date
+of
+units under the Restricted Stock Plan regardless of whether the shares are
+vested or unvested. Following the lapse of the restriction period, the shares
+underlying the units will be issued and therefore included in the issued and
+outstanding share count. 
+The
+treasury stock method 
+is used
+to measure the dilutive impact of stock options. The following table details
+the
+weighted-average dilutive and anti-dilutive securities related to stock options
+and RSUs for the periods presented: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+Dilutive
+2,293,768 
+1,499,288 
+910,110 
+Anti-dilutive 
+- 
+186 
+1,426,764 
+The
+dilutive effect of stock options and restricted stock units is considered in
+the
+detailed calculations below. There were no anti-dilutive securities related
+to
+restricted stock units for any periods presented. 
+Shares
+associated with the conversion feature of the Convertible Notes are accounted
+for using the if-converted method as described above. A total of 7,692,307
+potentially dilutive shares related to the Convertible Notes were included
+in
+the calculation of diluted net income per common share for the years ended
+December 31, 2005, 2004 and 2003. The Convertible Notes were issued in
+March 2002. 
+During
+the first quarter of 2003, the Company issued 6,761,636
+shares of common stock as part of an acquisition. In February 2004 the Company
+repurchased and retired these shares (see Note 11-Repurchase of Common Stock).
+These shares were considered outstanding from January 29, 2003, to February
+9,
+2004, for purposes of calculating basic and diluted net income per common share
+and were weighted accordingly in the calculation of common shares outstanding.
+F-10 
+The
+following table sets forth the calculation of basic and diluted earnings per
+share: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands, except per share amounts) 
+Income
+before cumulative effect of change in accounting principle 
+$ 
+151,936 
+$ 
+92,479 
+$ 
+90,140 
+Cumulative
+effect of change in accounting principle, net of
+income tax 
+- 
+- 
+5,435 
+Net
+income 
+151,936 
+92,479 
+95,575 
+Adjustments
+to net income for dilution: 
+Add:
+interest expense avoided if Convertible Notes are
+converted to equity 
+6,337 
+6,354 
+6,337 
+Less:
+other adjustments 
+(64 
+) 
+(64 
+) 
+(63 
+) 
+Less:
+income tax effect of dilutive items 
+(2,275 
+) 
+(2,312 
+) 
+(2,403 
+) 
+Net
+income adjusted for the effect of dilution 
+$ 
+155,934 
+$ 
+96,457 
+$ 
+99,446 
+Basic
+weighted-average common shares outstanding 
+56,907 
+57,702 
+62,467 
+Add:
+dilutive effect of stock options and RSUs 
+2,295 
+1,500 
+910 
+Add:
+dilutive effect of Convertible Notes using the if-converted
+method 
+7,692 
+7,692 
+7,692 
+Diluted
+weighted-average common shares outstanding 
+66,894 
+66,894 
+71,069 
+Basic
+earnings per common share: 
+Income
+before cumulative effect of change in accounting
+principle 
+$ 
+2.67 
+$ 
+1.60 
+$ 
+1.44 
+Cumulative
+effect of change in accounting principle, net of income
+tax 
+- 
+- 
+0.09 
+Total 
+$ 
+2.67 
+$ 
+1.60 
+$ 
+1.53 
+Diluted
+earnings per common share: 
+Income
+before cumulative effect of change in accounting
+principle 
+$ 
+2.33 
+$ 
+1.44 
+$ 
+1.32 
+Cumulative
+effect of change in accounting principle, net of income
+tax 
+- 
+- 
+0.08 
+Total 
+$ 
+2.33 
+$ 
+1.44 
+$ 
+1.40 
+Stock-Based
+Compensation 
+At
+December 31, 2005, the Company had stock-based employee compensation plans
+that
+included restricted stock units (“RSU s”)
+and
+stock options issued to employees and non-employee directors as more fully
+described in Note 7 - Compensation Plans. The Company has historically accounted
+for stock-based compensation using the intrinsic value recognition and
+measurement principles detailed in Accounting Principles Board Opinion No.
+25,
+“Accounting for Stock Issued to Employees” and related interpretations. No
+stock-based employee compensation expense relating to stock options has been
+reflected in the Company’s consolidated statements of operations for any period
+presented as all options granted under the plans had an exercise price equal
+to
+the market value of the underlying common stock on the date of grant. The
+Company currently uses the Black-Scholes option valuation model to calculate
+required disclosures under SFAS No. 123, “Accounting for Stock-Based
+Compensation.” As of January 1, 2006, the Company has adopted the provisions of
+SFAS No. 123(R), “Share-Based Payment.” This statement requires the Company to
+record expense associated with the fair value of stock-based compensation.
+As a
+result of the adoption of this statement, the Company expects to record
+compensation expense associated with unvested stock options totaling $2.2
+million in future periods under the modified-prospective adoption method. The
+Company has recorded expense of costs associated with the issuance of restricted
+stock units since the plan was adopted in 2004 and units were first granted.
+Going forward, this expense will decrease on a relative per share basis for
+all
+units that have already been issued, because the accounting standard requires
+cost recognition using fair value estimates of the restricted stock units,
+rather than intrinsic value used under APB 25. 
+F-11 
+The
+following table illustrates the pro forma effect on net income and earnings
+per
+share if the Company had applied the fair value recognition provisions of SFAS
+No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee
+compensation: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands, except per share amounts) 
+Net
+income 
+As
+reported: 
+$ 
+151,936 
+$ 
+92,479 
+$ 
+95,575 
+Add:
+stock-based employee compensation 
+expense
+included in reported net income, 
+net
+of related tax effects 
+4,453 
+2,650 
+- 
+Less:
+stock-based employee compensation 
+expense
+determined under fair value 
+method
+for all awards, net of 
+related
+income tax effects 
+(6,282 
+) 
+(5,839 
+) 
+(5,859 
+) 
+Pro
+forma 
+$ 
+150,107 
+$ 
+89,290 
+$ 
+89,716 
+Pro
+forma basic earnings per share 
+Income
+before cumulative effect of change in accounting principle
+$ 
+2.64 
+$ 
+1.54 
+$ 
+1.34 
+Cumulative
+effect of change in accounting principle, net of income
+tax 
+- 
+- 
+0.09 
+Total 
+$ 
+2.64 
+$ 
+1.54 
+$ 
+1.43 
+Pro
+forma diluted earnings per share 
+Income
+before cumulative effect of change in accounting principle
+$ 
+2.30 
+$ 
+1.39 
+$ 
+1.24 
+Cumulative
+effect of change in accounting principle, net of income
+tax 
+- 
+- 
+0.08 
+Total 
+$ 
+2.30 
+$ 
+1.39 
+$ 
+1.32 
+For
+purposes of pro forma disclosures, the estimated fair values of the options
+are
+amortized to expense over the options’ vesting periods. The effects of applying
+SFAS No. 123 in the pro forma disclosure are not necessarily indicative of
+actual future amounts. 
+Comprehensive
+Income 
+Comprehensive
+income consists of net income, unrealized gains and losses on marketable equity
+securities the effective portion of derivative instruments classified as cash
+flow hedges, and accrued pension benefit obligation in excess of plan assets.
+Comprehensive income is presented net of income taxes in the consolidated
+statements of stockholders’ equity and comprehensive income. 
+F-12 
+The
+balances of components comprising accumulated other comprehensive income and
+loss are presented in the following table: 
+Minimum 
+Other 
+Derivative 
+Pension 
+Comprehensive 
+Instruments 
+Liability 
+Income
+(Loss) 
+For
+the period ending December 31, 2004 
+Before
+tax amount 
+$ 
+27,401 
+$ 
+168 
+$ 
+27,569 
+Tax
+(expense) benefit 
+(10,347 
+) 
+(67 
+) 
+(10,414 
+) 
+After
+tax amount 
+$ 
+17,054 
+$ 
+101 
+$ 
+17,155 
+For
+the period ending December 31, 2005 
+Before
+tax amount 
+$ 
+(92,097 
+) 
+$ 
+455 
+$ 
+(91,642 
+) 
+Tax
+(expense) benefit 
+34,941 
+(172 
+) 
+34,769 
+After
+tax amount 
+$ 
+(57,156 
+) 
+$ 
+283 
+$ 
+(56,873 
+) 
+Major
+Customers 
+During
+2005 one customer individually accounted for 13 percent of the Company’s total
+oil and gas production revenue. During 2004 one customer individually accounted
+for 20 percent of the Company’s total oil and gas production revenue.
+During
+2003 three
+customers individually accounted for 14 percent, 13 percent and 11 percent
+of the Company’s total oil and gas production revenue. 
+Industry
+Segment and Geographic Information 
+The
+Company operates in one industry segment, which is the exploration, development,
+production and sale of natural gas and crude oil, and all of the Company’s
+operations are conducted in the Continental United States and the Gulf of
+Mexico. Consequently, the Company currently reports as a single industry
+segment. The activities of our gas marketing personnel directly support the
+underlying sale of oil and gas production and are not viewed by management
+as a
+discrete reporting segment. 
+Stock
+Dividend 
+In
+March
+2005 the Company’s Board of Directors approved a two-for-one stock split in the
+form of a stock dividend whereby one additional share of common stock was
+distributed for each common share outstanding. The stock dividend was
+distributed on March 31, 2005, to shareholders of record as of the close of
+business on March 21, 2005. All share and per share amounts for all
+prior periods presented herein have been reclassified to reflect this stock
+split. 
+Goodwill 
+Goodwill
+is measured as the excess of the acquisition costs over the sum of the amounts
+assigned to the identifiable assets acquired less liabilities assumed. Goodwill
+was recorded as a result of the acquisition of Agate Petroleum, Inc. in
+January 2005. Goodwill is reviewed for impairment annually or more
+frequently if impairment indicators arise. The goodwill review is conducted
+at
+the reporting unit level. Each reporting unit is defined as the oil and gas
+properties in a region. 
+Suspended
+Well Costs 
+In
+2005,
+the Company adopted FASB Staff Position No. FAS 19-1, “Accounting for Suspended
+Well Costs,” (“FSP FAS 19-1”). Upon adoption of the FSP FAS 19-1 the Company
+evaluated all existing capitalized exploratory well costs under the provisions
+of the FSP FAS 19-1. As a result, the Company determined that no suspended
+well
+costs should be impaired. 
+F-13 
+Off 
+-
+Balance Sheet 
+Arrangements 
+As
+part
+of its ongoing business, the Company has not participated in transactions that
+generate relationships with unconsolidated entities or financial partnerships,
+such as entities often referred to as structured finance or special purpose
+entities ("SPEs"), or SPEs which would have been established for the purpose
+of
+facilitating off-balance sheet arrangements or other contractually narrow or
+limited purposes. As of December 31, 2005, the Company has not
+been involved in any unconsolidated SPE transactions. 
+Note
+2 - Accounts Receivable and Accounts Payable and Accrued
+Expenses 
+Accounts
+receivable are comprised of the following: 
+As
+of December 31, 
+2005 
+2004 
+(In
+thousands) 
+Accrued
+oil and gas sales 
+$ 
+138,521 
+$ 
+79,107 
+Due
+from joint interest owners 
+21,696 
+20,587 
+Other 
+4,980 
+5,270 
+Total
+accounts receivable 
+$ 
+165,197 
+$ 
+104,964 
+Accounts
+payable and accrued expenses are comprised of the following: 
+As
+of December 31, 
+2005 
+2004 
+(In
+thousands) 
+Accrued
+drilling costs 
+$ 
+40,071 
+$ 
+33,998 
+Revenue
+payable 
+61,924 
+41,875 
+Accrued
+lease operating expense 
+9,738 
+13,066 
+Accrued
+taxes 
+6,202 
+800 
+Accrued
+interest 
+1,861 
+1,779 
+Joint
+owner advances 
+2,955 
+448 
+Accrued
+compensation 
+16,618 
+5,555 
+Trade
+payables 
+14,265 
+7,506 
+Oil
+hedge accrual 
+1,000 
+3,027 
+Other 
+10,323 
+2,063 
+Total
+account payable and accrued expenses 
+$ 
+164,957 
+$ 
+110,117 
+Note
+3 - Acquisitions and Divestitures 
+Agate
+Acquisition 
+On
+January 5, 2005, the Company acquired Agate Petroleum, Inc. (“Agate”)
+in exchange for $40.0 million in cash. The Company allocated the purchase
+price based on the estimated fair values of the acquired assets and liabilities.
+The Company finalized the purchase price allocation in 2005 as all amounts
+related to receivables and payables were determined with certainty. The final
+allocation did not result in any material adjustments to the preliminary
+purchase price. The Company acquired $4.6 million in cash from Agate, and
+the allocation of the purchase price resulted in recording $41.9 million to
+proved and unproved oil and gas properties, $1.1 million to net current
+liabilities, $9.5 million to goodwill, a deferred income tax liability of
+$13.5 million and a $1.4 million asset retirement obligation. The
+acquisition was accounted for using the purchase method of accounting and was
+funded with cash on hand and borrowings under the Company’s credit facility.
+Operating results from the acquired properties have been included in the
+consolidated statements of operations from the date of closing. 
+F-14 
+The
+goodwill and deferred income tax liability result from the use of present value
+considerations in the economic decision process that cannot be applied to the
+amounts recorded for deferred income taxes from acquiring oil and gas assets
+in
+a transaction in which the tax basis of the assets acquired is lower than the
+book basis fair value. The strategic benefits to the Company that support the
+recognition of goodwill in this acquisition include the mix of complementary
+high-quality assets in two of our existing core areas, lower-risk exploitation
+opportunities, and increased cash flow from operations available for investing
+activities. 
+Wold
+Acquisition 
+On
+August 1, 2005, the Company acquired oil and gas properties primarily
+in the Wind River and Powder River Basins of Wyoming from Wold Oil Properties,
+Inc. (“Wold”) for $37.1 million in cash. The Company allocated the purchase
+price based on the fair values of the acquired assets and liabilities. The
+allocation of the purchase price resulted in recording $43.9 million to
+proved and unproved oil and gas properties, a $7.0 million asset retirement
+obligation, and a net $232,000 to other assets. The $7.0 million asset
+retirement obligation includes approximately $4.7 million related to shut
+in and temporarily abandoned wells included in the acquisition. The Company
+finalized the allocation of the purchase price as all post-closing adjustments
+were determined with certainty prior to the end of 2005. The acquisition was
+accounted for using the purchase method of accounting and was funded with cash
+on hand and borrowings under the Company’s credit facility. Operating results
+from the acquired properties have been included in the consolidated statement
+of
+operations from the date of closing. 
+Goldmark
+Acquisition 
+On
+November 1, 2004, the Company acquired Goldmark Engineering Inc. along with
+proved and unproved oil and gas properties from various other parties
+(collectively, “Goldmark”) in exchange for $23.5 million of cash. The
+allocation of the purchase price was $29.6 million of proved reserves and
+unproved acreage, $1.2 million of cash, $753,000 of other assets, $446,000
+of payables, a $2.8 million asset retirement liability, and a
+$4.8 million deferred tax liability. 
+Border
+Acquisition 
+On
+December 15, 2004, the Company completed the acquisition of proved and unproved
+oil and gas properties from Border Company and other parties in exchange for
+$34.8 million in cash. The allocation of the purchase price was $35.5
+million of proved reserves and unproved acreage and a $649,000 asset retirement
+obligation. 
+Sales
+of Properties 
+Throughout
+2005, the Company sold interests in certain properties, received cash proceeds
+of $1.2 million and recognized a gain of approximately $222,000 from these
+sales. Throughout 2004 and 2003, the Company sold interests in certain
+properties and received $2.8 million and $23.5 million, respectively, in net
+proceeds and recognized a gain of approximately $1.8 million and $7.3
+million, respectively, from these sales. 
+F-15 
+Note
+4 - Income Taxes 
+The
+provision for income taxes consists of the following: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Current
+taxes: 
+Federal 
+$ 
+75,848 
+$ 
+21,143 
+$ 
+29,582 
+State 
+4,906 
+1,389 
+2,656
+Deferred
+taxes 
+5,547 
+31,217 
+23,692
+Total
+income tax expense 
+$ 
+86,301 
+$ 
+53,749 
+$ 
+55,930 
+As
+a
+result of the exercise of stock options, the Company was able to reduce its
+income tax payable in each year presented. The tax benefit to the Company of
+stock option exercises was $6.0 million in 2005, $3.8 million in 2004, and
+$1.2
+million in 2003.The components of the net deferred tax liability are as
+follows: 
+December
+31, 
+2005 
+2004 
+(In
+thousands) 
+Deferred
+tax liabilities: 
+Oil
+and gas properties 
+$ 
+204,745 
+$ 
+146,427 
+Interest
+on Convertible Notes 
+5,600 
+4,192 
+Unrealized
+derivative gain included in accumulated other comprehensive
+income 
+- 
+2,246 
+Other 
+2,750 
+435 
+Total
+deferred tax liabilities 
+213,095 
+153,300 
+Deferred
+tax assets: 
+Net
+Profits Plan liability 
+51,712 
+11,598 
+Unrealized
+derivative loss included in accumulated other comprehensive
+income 
+33,441 
+1,033 
+Stock
+compensation 
+4,585 
+1,590 
+State
+tax net operating loss carryforward or carryback 
+2,928 
+2,981 
+State
+and federal income tax benefit 
+1,587 
+1,100 
+Deferred
+capital loss 
+761 
+758 
+Employee
+benefits and other 
+609 
+969 
+Federal
+net operating loss carryforward 
+- 
+2,882 
+Total
+deferred tax assets 
+95,623 
+22,911 
+Valuation
+allowance 
+(2,572 
+) 
+(1,714 
+) 
+Net
+deferred tax assets 
+93,051 
+21,197 
+Total
+net deferred tax liabilities 
+120,044 
+132,103 
+Less:
+current deferred income tax liabilities 
+(1,328 
+) 
+(2,357 
+) 
+Add:
+current deferred income tax assets 
+9,580 
+84 
+Non-current
+net deferred tax liabilities 
+$ 
+128,296 
+$ 
+129,830 
+Current
+federal income tax payable 
+$ 
+3,346 
+$ 
+939 
+Current
+state refundable income tax 
+$ 
+- 
+$ 
+139 
+Current
+state income tax payable 
+$ 
+2,856 
+$ 
+- 
+At
+December 31, 2005, the Company had state net operating loss carryforwards of
+approximately $40.1 million and state tax credits of $125,000, which expire
+between 2006 and 2024. A portion of the Company’s valuation allowance relates to
+state net operating loss carryforwards, state tax credits, and state and federal
+income tax benefit amounts that the Company anticipates will expire before
+they
+can be utilized. The Company has concluded that permanent items included in
+the
+calculation of income tax for certain states may impact its ability to deduct
+net operating losses and realize federal income tax deduction benefits of those
+states and has adjusted its valuation allowances accordingly. The remaining
+portion of the valuation allowance relates to the Net Profits Plan liability
+and
+reflects an estimate of future executive compensation that may not be deductible
+for income tax as a result of payments under the plan. 
+F-16 
+Federal
+income tax expense and benefit differs from the amount that would be provided
+by
+applying the statutory U.S. federal income tax rate to income before income
+taxes for the following reasons: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Federal
+statutory taxes 
+$ 
+83,307 
+$ 
+51,180 
+$ 
+49,668 
+Increase
+(reduction) in taxes resulting from: 
+State
+taxes (net of federal benefit) 
+4,185 
+2,586 
+5,812 
+Domestic
+production activities deduction 
+(1,717 
+) 
+- 
+- 
+Statutory
+depletion 
+(224 
+) 
+(224 
+) 
+(224 
+) 
+Other 
+(108 
+) 
+(665 
+) 
+559 
+Change
+in valuation allowance 
+858 
+872 
+115 
+Income
+tax expense from operations 
+$ 
+86,301 
+$ 
+53,749 
+$ 
+55,930 
+Acquisitions,
+drilling and basis differentials impacting the prices received for crude oil
+and
+natural gas affect the apportionment of taxable income to the states where
+the
+Company owns properties. As these factors change, the Company’s state income tax
+rate changes. This change applied to the Company’s total temporary differences
+will impact the total income tax reported in the current year and is reflected
+in state taxes in the table above. Items affecting state appointment factors
+are
+evaluated upon completion of the prior year income tax return after significant
+acquisitions are closed and at the end of the year. 
+Note
+5 - Long-term Debt 
+Revolving
+Credit Facility 
+The
+Company executed an Amended and Restated Credit Agreement on
+April 7, 2005, to replace its previous credit facility. The new credit
+facility specifies a maximum loan amount of $500 million and has a maturity
+date of April 7, 2010. Borrowings under the facility are secured by a
+pledge in favor of the lenders of collateral that includes certain oil and
+gas
+properties and the common stock of the material subsidiaries of the Company.
+The
+borrowing base under the credit facility as authorized by the bank group is
+currently $500 million, and is subject to regular semi-annual
+redeterminations. The borrowing base redetermination process considers the
+value
+of St. Mary’s oil and gas properties and other assets, as determined by the bank
+syndicate. The Company has elected an aggregate commitment amount of
+$200 million under the credit facility. The Company must comply with
+certain financial and non-financial covenants. Interest and commitment fees
+are
+accrued based on the borrowing base utilization percentage table below.
+Euro-dollar loans accrue interest at LIBOR plus the applicable margin from
+the
+utilization table, and Alternative Base Rate (ABR) loans accrue interest at
+prime plus the applicable margin from the utilization table. Commitment fees
+are
+accrued on the unused portion of the aggregate commitment amount and are
+included in interest expense in the consolidated statements of
+operations. 
+Borrowing
+base 
+utilization
+percentage 
+< 50%
+> 50% < 75%
+> 75% < 90%
+> 90%
+Euro-dollar
+loans 
+1.000% 
+1.250% 
+1.500% 
+1.750% 
+ABR
+loans 
+0.000% 
+0.250% 
+0.250% 
+0.500% 
+Commitment
+fee rate 
+0.250% 
+0.300% 
+0.375% 
+0.375% 
+F-17 
+The
+Company had no outstanding loans under its revolving credit agreement on either
+December 31, 2005 or February 15, 2006. 
+5.75%
+Senior Convertible Notes Due 2022 
+As
+of
+December 31, 2005, the Company also had $100.0 million in outstanding
+borrowings in the form of convertible notes. The Convertible Notes provide
+for
+the payment of contingent interest of up to an additional one-half of one
+percent during six-month interest periods based on the Convertible Notes market
+price before the beginning of the particular six-month period. Under that
+provision, interest was accrued at a total rate of 6.25 percent for 2005.
+Based on the trading price of the Convertible Notes over the determination
+period, the Company will be subject to the contingent interest payments for
+the
+period from September 16, 2005, to March 15, 2006. 
+The
+Convertible Notes are general unsecured obligations and rank on parity in right
+of payment with all existing and future unsecured senior indebtedness and other
+general unsecured obligations. They are senior in right of payment to all future
+subordinated indebtedness. The Convertible Notes are convertible at any time
+into the Company’s common stock at a conversion price of $13.00 per share,
+subject to adjustment. The Company can redeem the Convertible Notes with cash
+in
+whole or in part at a repurchase price of 100 percent of the principal amount
+plus accrued and unpaid interest
+(including contingent interest) beginning on March 20, 2007. The note holders
+have the option of requiring the Company to repurchase the Convertible Notes
+for
+cash at 100 percent of the principal amount plus accrued and unpaid interest
+(including contingent interest) upon (1) a change in control of St. Mary or
+(2) on March 20, 2007, March 15, 2012, and March 15, 2017. If the note
+holders require repurchase on March 20, 2007, the Company may elect to pay
+the
+repurchase price with cash, shares of its common stock valued at a discount
+at
+the time of repurchase, or any combination of cash and its discounted common
+stock. The shares of common stock used in any repurchase will be discounted
+at
+95 percent of market price if 33 percent or less of the repurchase price is
+in
+shares of our common stock; otherwise, the stock will be discounted at 93
+percent of market value. St. Mary is not restricted from paying dividends,
+incurring debt, or issuing or repurchasing its securities under the indenture
+for the Convertible Notes. There are no financial covenants in the indenture.
+Based on the market price of the Convertible Notes, the estimated fair value
+of
+the Convertible Notes was approximately $ 286
+million
+as of December 31, 2005, and approximately $172 million as of December 31,
+2004. 
+Weighted-Average
+Interest Rate Paid and Capitalized Interest 
+The
+weighted-average interest rate paid in 2005 and 2004 was 7.1 percent, including
+commitment fees paid on the unused portion of the credit facility aggregate
+commitment, amortization of deferred financing costs, amortization of the
+contingent interest embedded derivative and the effect of interest rate swaps.
+The impact of these items over a lower average outstanding loan balance results
+in a higher weighted-average interest rate. The Company capitalized interest
+costs of $1.9 million, $1.4 million, and $780,000 for the years ended December
+31, 2005, 2004, and 2003, respectively. 
+Note
+6 - Commitments and Contingencies 
+The
+Company leases office space under various operating leases with terms extending
+as far as May 31, 2012. Rent expense, net of sublease income, was $1.3
+million, $1.5 million, and $1.3 million in 2005, 2004 and 2003,
+respectively. The Company also leases office equipment under various operating
+leases. The Company has a non-cancelable sublease of approximately
+$1.2 million through 2012. The annual minimum lease payments for the next
+five years and thereafter are presented below: 
+F-18 
+Years
+Ending December 31, 
+(In
+thousands) 
+2006 
+2,447 
+2007 
+1,570 
+2008 
+1,370 
+2009 
+1,238 
+2010 
+1,192 
+Thereafter 
+1,507 
+Total 
+$ 
+9,324 
+The
+Company is subject to litigation and claims that have arisen in the ordinary
+course of business. The Company accrues for such items when a liability is
+both
+probable and the amount can be reasonably estimated. In the opinion of
+management, the results of such litigation and claims will not have a material
+effect on the results of operations or the financial position of the Company.
+Management believes it has sufficiently provided for such items to the extent
+necessary in the consolidated balance sheets. 
+Note
+7 - Compensation Plans 
+Cash
+Bonus Plan 
+The
+Company has a cash bonus plan that allows participants to receive up to 50
+percent of their aggregate base salary. Any awards under the cash bonus plans
+are based on a combination of Company and individual performance. The Company
+accrued $7.4 million for cash bonuses in 2005 that will be paid in 2006, and
+$2.0 million for cash bonuses in 2004 that were paid in 2005. 
+Net
+Profits Plan 
+Under
+the
+Company’s Net Profits Plan, oil and gas wells that are completed or acquired
+during a year are designated within a specific pool. Key employees designated
+as
+participants by the Company’s Compensation Committee of the Board of Directors,
+upon recommendation by senior management, and employed by the Company on the
+last day of that year become entitled to bonus payments after the Company has
+received net cash flows returning 100 percent of all costs associated with
+that pool. Thereafter, ten percent of future net cash flows generated by
+the pool are allocated among the participants and distributed at least annually.
+The portion of net cash flows from the pool to be allocated among the
+participants increases to 20 percent after the Company has recovered
+200 percent of the total costs for the pool, including payments made under
+the Net Profits Plan at the ten percent level. The Net Profits Plan has
+been in place since 1991. Pool years prior to and including 2005 are fully
+vested. Pool years beginning in 2006 will carry a vesting period of three years
+and a maximum benefit to full participants from a particular year’s pool of
+300 percent of each participating individual’s salary paid to such
+individual during the year to which the pool relates. A partial interest
+participant’s benefit is prorated proportionally from the 300
+percent. 
+Expense
+for distributions made or accrued under the Net Profits Plan related to current
+period operations for the years ended 2005, 2004, and 2003 were $20.8 million,
+$8.0 million, and $8.9 million, respectively. These amounts relate to the
+current period realized results from oil and gas operations for the properties
+associated with the respective pools that have achieved payout
+status. 
+In
+a
+separate calculation, the Company records the estimated liability for future
+payments under the Net Profits Plan based on the discounted value of estimated
+future payments associated with each individual pool. The calculation of this
+liability is a significant management estimate utilizing a discount rate of
+predominately 15 percent, and is intended to represent the best estimate of
+the present value of expected future payments under the Net Profits Plan. The
+Company’s estimate of its liability is highly dependent on the price assumptions
+and discount rates used in the calculations. The price assumptions are currently
+formulated by applying a price that is derived from a rolling average of actual
+prices realized from the prior 24 months together with adjusted NYMEX strip
+prices for the ensuing 12 months. This calculation is supplemented with
+hedge prices for the percentage of forecast production hedged. The forecast
+expense associated with this significant management estimate increased
+substantially in 2005 as a result of the significant increase of oil and gas
+prices during the year, together with the impact of pricing that is assured
+to
+the Company as a result of executing its expanded hedging strategy. In addition,
+these higher prices have moved more pools to payout status. The Company
+continually evaluates the assumptions used in this calculation in order to
+include the current market environment for oil and gas prices, discount rates
+and overall market conditions. The calculation of the estimated liability for
+the Net Profits Plan is highly sensitive to our price estimates and discount
+rate assumptions. For example, if we changed the prices in our calculation
+by
+ten percent, the liability recorded at December 31, 2005, would differ by
+approximately $26 million, and a one percent change in the discount rate would
+result in a change of approximately $5 million. Actual cash payments to be
+made
+in future periods are dependent on realized actual production, prices, and
+costs
+associated with the individual pools of the Net Profits Plan. Consequently,
+actual cash payments will be inherently different from the amounts
+estimated. 
+F-19 
+The
+following table presents the changes in the estimated liability attributable
+to
+the Net Profits Plan: 
+As
+of December 31, 
+2005 
+2004 
+(In
+thousands) 
+Beginning
+liability for Net Profits Plan 
+$ 
+30,561 
+$ 
+6,163 
+Increase
+in liability 
+127,064 
+32,410 
+Reduction
+in liability for cash payments made or accrued and recognized as
+compensation expense under the Net Profits Plan 
+(20,801 
+) 
+(8,012 
+) 
+Ending
+liability for Net Profits Plan 
+$ 
+136,824 
+$ 
+30,561 
+The
+Company records changes in the present value of estimated future payments under
+the Net Profits Plan as a separate item in the consolidated statements of
+operations. The change in the estimated liability is recorded as an increase
+or
+decrease to expense in the current period. The amount recorded as an increase
+or
+decrease to expense associated with the change in the estimated liability is
+not
+allocated to general and administrative costs or exploration costs because
+it is
+an estimate at the current time of the adjustment to the liability that is
+associated with the future net cash flows from oil and gas properties in the
+respective pools rather than current period realized performance. The table
+below presents the estimated allocation of the change in the liability if the
+Company did allocate the adjustment to these specific line items: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+General
+and administrative expense 
+$ 
+51,419 
+$ 
+14,609 
+$ 
+3,982 
+Exploration
+expense 
+54,844 
+9,789 
+1,335 
+Total 
+$ 
+106,263 
+$ 
+24,398 
+$ 
+5,317 
+401(k)
+Plan 
+The
+Company has a defined contribution pension plan (the "401(k) Plan") that is
+subject to the Employee Retirement Income Security Act of 1974. The 401(k)
+Plan
+allows eligible employees to contribute up to 60 percent of their base salaries.
+The Company matches each employee's contributions up to six percent of the
+employee's base salary and may make additional contributions at its discretion.
+The Company’s contributions to the 401(k) Plan were $966,000, $834,000, and
+$746,000 for the years ended December 31, 2005, 2004, and 2003, respectively.
+No
+discretionary contributions were made by the Company to the 401(k) Plan in
+any
+of these three years. 
+Employee
+Stock Purchase Plan 
+Under 
+the
+St. Mary Land & Exploration Company Employee Stock Purchase Plan (“the
+ESPP”), eligible employees may purchase shares of the Company’s common stock
+through payroll deductions of up to 15 percent of eligible compensation. The
+purchase price of the stock is 85 percent of the lower of the fair market value
+of the stock on the first or last day of the purchase period, and shares issued
+under the ESPP are restricted for a period of 18 months from the date issued.
+The ESPP is intended to qualify under Section 423 of the Internal Revenue Code.
+The Company has set aside 2,000,000 shares of its common stock to be available
+for issuance under the ESPP. Shares issued under the ESPP totaled 28,447
+in
+2005, 
+27,748
+in 2004, and 33,988 in 2003. Total proceeds to the Company for the issuance
+of
+these shares were $ 601,000
+in 2005, 
+$375,000
+in 2004, and $375,000 in 2003. 
+F-20 
+Stock
+Option Plans 
+The
+Company has a Stock Option Plan and an Incentive Stock Option Plan
+(collectively, the “Option Plans”). The Option Plans grant options to purchase
+shares of the Company’s common stock to eligible employees, contractors, and
+current and former members of the Board of Directors. There are 11.2 million
+shares of the Company’s common stock reserved for issuance under the Option
+Plans. This number is reduced to the extent that restricted stock or restricted
+stock units are granted under the Restricted Stock Plan. All options granted
+to
+date under the Option Plans have been granted at exercise prices equal to the
+respective market prices of the Company’s common stock on the grant dates. There
+were 1,063,617 
+shares
+available for grant under the Option Plans (including the Restricted Stock
+Plan,
+as described later) as of December 31, 2005. 
+A
+summary
+of activity associated with the Company’s Stock Option Plans during the last
+three years follows: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+Weighted- 
+Weighted- 
+Weighted- 
+Average 
+Average 
+Average 
+Exercise 
+Exercise 
+Exercise 
+Shares 
+Price 
+Shares 
+Price 
+Shares 
+Price 
+Outstanding,
+start of year 
+5,651,350 
+$ 
+12.06 
+7,050,256 
+$ 
+11.55 
+6,123,132 
+$ 
+10.67 
+Granted
+- 
+- 
+117,356 
+18.90 
+1,716,862 
+13.35 
+Exercised
+(936,403 
+) 
+11.31 
+(1,399,052 
+) 
+10.03 
+(490,038 
+) 
+6.44 
+Forfeited 
+(16,704 
+) 
+13.24 
+(117,210 
+) 
+12.50 
+(299,700 
+) 
+12.00 
+Outstanding,
+end of year 
+4,698,243 
+12.21 
+5,651,350 
+12.06 
+7,050,256 
+11.55 
+Exercisable,
+end of year 
+4,121,424 
+12.07 
+4,441,362 
+11.76 
+4,882,492 
+11.18 
+Weighted-average
+fair value of options granted during the year 
+$ 
+- 
+$ 
+8.44 
+$ 
+6.14 
+F-21 
+A
+summary
+of additional information related to options outstanding as of
+December 31, 2005, follows: 
+Options
+Outstanding 
+Options
+Exercisable 
+Range
+of 
+Exercise Prices 
+Number 
+Outstanding 
+Weighted-Average
+Remaining 
+Contractual Life 
+Weighted-Average
+Exercise Price 
+Number 
+Exercisable 
+Weighted-Average
+Exercise Price 
+$ 4.62 
+- 
+5.13 
+145,270 
+3.0
+years 
+4.63 
+145,270 
+4.63 
+5.13 
+- 
+8.75 
+666,394 
+4.0
+years 
+6.91 
+666,394 
+6.91 
+8.75 
+- 
+11.95 
+1,175,680 
+6.4
+years 
+11.35 
+925,680 
+11.29 
+11.95 
+- 
+12.90 
+1,075,639 
+7.2
+years 
+12.46 
+971,363 
+12.43 
+12.90 
+- 
+14.25 
+794,806 
+7.8
+years 
+13.88 
+631,579 
+13.87 
+14.25 
+- 
+16.72 
+772,050 
+5.2
+years 
+16.66 
+742,050 
+16.66 
+16.72 
+- 
+20.87 
+68,404 
+9.0
+years 
+20.87 
+39,088 
+20.87 
+Total 
+4,698,243 
+4,121,424 
+SFAS
+No.
+123 establishes a fair value method of accounting for stock-based compensation
+plans through either recognition or disclosure. The Company accounts for
+stock-based compensation under the intrinsic value method pursuant to APB No.
+25
+and has elected to adopt SFAS No. 123 through compliance with the disclosure
+requirements set forth in the Statement. Because the exercise price of the
+Company’s stock options equals the market price of the underlying stock on the
+date of grant, no compensation expense is recognized under APB No. 25. Pro
+forma
+information regarding net income and earnings per share is required by SFAS
+No.
+123 and has been determined as if the Company had accounted for its employee
+stock options under the fair value method of that Statement. This pro forma
+information is prominently disclosed in Note 1 - Summary of Significant
+Accounting Policies. 
+The
+fair
+value of options was measured at the date of grant using the Black-Scholes
+option-pricing model. The fair values of options granted and employee stock
+purchase plan shares issued were estimated using the following weighted-average
+assumptions: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+Risk
+free interest rate: 
+Stock
+options 
+- 
+4.1% 
+3.6% 
+Employee
+stock purchase plan 
+2.5 % 
+3.1% 
+3.7% 
+Dividend
+yield: 
+Stock
+options 
+- 
+0.3% 
+0.4% 
+Employee
+stock purchase plan 
+0.4% 
+0.3% 
+0.4% 
+Volatility
+factor of the expected market 
+price
+of the Company's common stock: 
+Stock
+options 
+- 
+35.9% 
+39.9% 
+Employee
+stock purchase plan 
+36.3% 
+23.8% 
+20.2% 
+Expected
+life of the options (in years) 
+Stock
+options 
+- 
+9.0 
+7.0 
+Employee
+stock purchase plan 
+0.5 
+0.5 
+0.5 
+The
+Black-Scholes option valuation model was developed for use in estimating the
+fair value of traded options that have no vesting restrictions and are fully
+transferable. In addition, option valuation models require the input of highly
+subjective assumptions including the expected stock price volatility. The
+Company’s stock options have characteristics significantly different from those
+of traded options, and because changes in the subjective input assumptions
+can
+materially affect the fair value estimate, it is management’s opinion that the
+valuations afforded by the existing models are different from the value that
+the
+options would realize if traded in the market. 
+F-22 
+Restricted
+Stock Plan 
+In
+May 2004 the Restricted Stock Plan was approved by the Company’s
+stockholders. This established a long-term incentive program whereby grants
+of
+restricted stock or restricted stock units (“RSUs”) may be awarded to eligible
+employees, consultants, and members of the Board of Directors. Restrictions
+and
+vesting periods for the awards are determined at the discretion of the Board
+of
+Directors and are set forth in the award agreements. Each RSU represents a
+right
+for one share of the Company’s common stock to be delivered upon settlement of
+the award at the end of a specified restriction period. The total number of
+shares of the Company’s common stock reserved for issuance under the Restricted
+Stock Plan is 11,200,000. This number is reduced to the extent that stock
+options are granted under the Company’s Option Plans. 
+St.
+Mary
+issued 194,508 RSUs on March 15, 2005, related to 2004 performance.
+The total expense associated with this issuance was $4.9 million as
+measured on the grant date. The total unvested portion of the measured expense
+was initially recorded as deferred stock-based compensation and is being charged
+to compensation expense based on the vesting schedule. The granted RSUs vest
+25 percent immediately upon grant and 25 percent on each of the next
+three anniversary dates of the grant. The vested shares underlying the RSU
+grants will be issued on the third anniversary of the grant, at which time
+the
+shares carry no further restrictions. As of December 31, 2005, there were a
+total of 632,809 RSUs outstanding, of which 276,746 were vested. Total
+compensation expense related to the RSUs for the year ended December
+31, 2005, was $7.0 million. This amount includes $4.0 million of
+compensation expense related to the 2005 plan year for the estimated value
+of
+grants expected to be issued in 2006. 
+Non
+-Employee Director Stock Compensation Plan 
+In
+May
+2003, stockholders approved a Non-Employee Director Stock Compensation Plan
+to
+authorize the issuance of up to 60,000 shares of St. Mary’s common stock to
+non-employee directors as part of their compensation over an anticipated period
+of up to five years. The purpose of the plan is to attract, retain, and motivate
+non-employee directors. As of December 31, 2005, 39,126 shares have
+been issued under this plan. 
+Note
+8 - Pension Benefits 
+The
+Company has a non-contributory pension plan covering substantially all employees
+who meet age and service requirements (the “Qualified Pension Plan”). The
+Company also has a supplemental non-contributory pension plan covering certain
+management employees (the “Nonqualified Pension Plan”). 
+F-23 
+Obligations
+and Funded Status for Both Plans 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Change
+in benefit obligations: 
+Projected
+benefit obligation at beginning of year 
+$ 
+10,174 
+$ 
+8,048 
+$ 
+6,330 
+Service
+cost 
+1,385 
+1,139 
+963 
+Interest
+cost 
+535 
+489 
+428 
+Actuarial
+loss 
+(4 
+) 
+1,236 
+620 
+Benefits
+paid 
+(190 
+) 
+(738 
+) 
+(293 
+) 
+Projected
+benefit obligation at end of year 
+$ 
+11,900 
+$ 
+10,174 
+$ 
+8,048 
+Change
+in plan assets: 
+Fair
+value of plan assets at beginning of year 
+$ 
+4,675 
+$ 
+3,694 
+$ 
+2,478 
+Actual
+return on plan assets 
+412 
+434 
+608 
+Employer
+contribution 
+1,058 
+1,285 
+901 
+Benefits
+paid 
+(190 
+) 
+(738 
+) 
+(293 
+) 
+Fair
+value of plan assets at end of year 
+$ 
+5,955 
+$ 
+4,675 
+$ 
+3,694 
+Funded
+status: 
+$ 
+(5,945 
+) 
+$ 
+(5,499 
+) 
+$ 
+(4,354 
+) 
+Unrecognized
+net loss 
+3,450 
+3,754 
+2,874 
+Unrecognized
+prior service cost 
+- 
+- 
+(15 
+) 
+Accrued
+benefit cost 
+$ 
+(2,495 
+) 
+$ 
+(1,745 
+) 
+$ 
+(1,495 
+) 
+Amounts
+Recognized in the Consolidated Balance Sheets for Both Plans 
+As
+of December 31, 
+2005 
+2004 
+(In
+thousands) 
+Accrued
+benefit cost 
+$ 
+2,495 
+$ 
+1,745 
+Accumulated
+other comprehensive income 
+290 
+746 
+Net
+amount recognized 
+$ 
+2,785 
+$ 
+2,491 
+Information
+for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan
+Assets for Both Plans 
+As
+of December 31, 
+2005 
+2004 
+(In
+thousands) 
+Projected
+benefit obligation 
+$ 
+11,900 
+$ 
+10,174 
+Accumulated
+benefit obligation 
+$ 
+8,429 
+$ 
+7,143 
+Fair
+value of plan assets 
+$ 
+5,955 
+$ 
+4,675 
+The
+Company’s accumulated benefit obligation for the Qualified Pension Plan was
+$ 7.3
+million at December 31, 2005, and $5.9 million at December 31, 2004.
+The accumulated benefit obligation exceeds plan assets by $1.3 million. The
+tax-adjusted liability of $180,000 was recorded in other comprehensive income
+at
+December 31, 2005. 
+The
+Company’s accumulated benefit obligation for the Nonqualified Pension Plan was
+$ 1.1 
+million
+at December 31, 2005, and $1.2 million at December 31, 2004.
+There are no plan assets in the Nonqualified Pension Plan due to the nature
+of
+the plan. 
+F-24 
+Components
+of Net Periodic Benefit Cost for Both Plans 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Components
+of net periodic benefit cost: 
+Service
+cost 
+$ 
+1,385 
+$ 
+1,139 
+$ 
+963 
+Interest
+cost 
+535 
+489 
+428 
+Expected
+return on plan assets 
+(354 
+) 
+(295 
+) 
+(172 
+) 
+Amortization
+of prior service cost 
+- 
+(16 
+) 
+(25 
+) 
+Amortization
+of net actuarial loss 
+241 
+218 
+329 
+Net
+periodic benefit cost 
+$ 
+1,807 
+$ 
+1,535 
+$ 
+1,523 
+Prior
+service costs are amortized on a straight-line basis over the average remaining
+service period of active participants. Gains and losses in excess of ten percent
+of the greater of the benefit obligation and the market-related value of assets
+are amortized over the average remaining service period of active
+participants. 
+Additional
+Information 
+The
+minimum liability included in other accumulated comprehensive income, net of
+taxes, decreased by $ 283,000, 
+$101,000
+and $197,000 for the years ended December 31, 2005, 2004 and 2003,
+respectively. 
+Assumptions 
+Weighted-average
+assumptions to measure the Company’s projected benefit obligation and net
+periodic benefit cost are as follows: 
+As
+of December 31, 
+2005 
+2004 
+Projected
+benefit obligation 
+Discount
+rate 
+5.50% 
+5.75% 
+Expected
+return on plan assets 
+7.50% 
+8.00% 
+Rate
+of compensation increase 
+5.93% 
+4.00% 
+Net
+periodic benefit cost 
+Discount
+rate 
+5.75% 
+6.25% 
+Expected
+return on plan assets 
+7.50% 
+8.00% 
+Rate
+of compensation increase 
+5.93% 
+3.50% 
+Plan
+Assets 
+The
+Company’s weighted-average asset allocation for the Qualified Plan is as
+follows: 
+Target 
+As
+of December 31, 
+Asset
+Category 
+2006 
+2005 
+2004 
+Equity
+securities 
+60 % 
+61.6% 
+63.0% 
+Debt
+securities 
+40% 
+38.2% 
+34.7% 
+Other 
+- 
+0.2% 
+2.3% 
+Total 
+100.0% 
+100.0% 
+100.0% 
+F-25 
+Equity
+securities do not include any shares of the Company’s common stock for any
+period presented. There is no asset allocation for the Nonqualified Pension
+Plan
+since that plan does not have its own assets. An expected return on plan assets
+of 7.5 percent was used to calculate the Company’s obligation under the
+Qualified Plan. Factors considered in determining the expected return
+include the 60 percent equity and 40 percent debt securities mix of investment
+for plan assets and the long-term historical rate of return provided by the
+equity and debt securities markets. The estimated rate of return on plan
+assets was 7.8 percent for 2005 and 10.4 percent for 2004. The difference
+in investment income using the projected rate of return compared to the actual
+rates of return for the past two years was not material and will not have a
+material effect on the statements of operation or on cash flows from operating
+activities in future years. 
+Contributions 
+The
+Company contributed $1.1 million, $1.3 million, and $901,000, to the pension
+plans in the years ended December 31, 2005, 2004, and 2003,
+respectively. St. Mary expects to contribute approximately $1.4 million to
+the pension plans in 2006. 
+Benefit
+Payments 
+The
+Plans
+made actual benefit payments of $190,000, $738,000, and $293,000 in the years
+ended December 31, 2005, 2004, and 2003, respectively. Expected benefit payments
+over the next ten years follows: 
+Years
+Ended December 31, 
+(in
+thousands) 
+2006 
+$ 
+310 
+2007 
+$ 
+413 
+2008 
+$ 
+534 
+2009 
+$ 
+732 
+2010 
+$ 
+793 
+2011
+through 2015 
+$ 
+10,181 
+Note
+9 - Asset Retirement Obligations 
+The
+Company recognizes an estimated liability for future costs associated with
+the
+abandonment of its oil and gas properties. A liability for the fair value of
+an
+asset retirement obligation and a corresponding increase to the carrying value
+of the related long-lived asset are recorded at the time a well is completed
+or
+acquired. The increase in carrying value is included in proved oil and gas
+properties in the consolidated balance sheets. The Company depletes the amount
+added to proved oil and gas property costs and recognizes accretion expense
+in
+connection with the discounted liability over the remaining estimated economic
+lives of the respective oil and gas properties. 
+The
+Company’s estimated asset retirement obligation liability is based on historical
+experience in abandoning wells, estimated economic lives, estimates as to the
+cost to abandon the wells in the future, and federal and state regulatory
+requirements. The liability is discounted using a credit-adjusted risk-free
+rate
+estimated at the time the liability is incurred or revised. The credit-adjusted
+risk-free rates used to discount the Company’s abandonment liabilities range
+from 6.50 percent to 7.25 percent. Revisions to the liability are due
+to increases in estimated abandonment costs and changes in well economic
+lives. 
+A
+reconciliation of the Company's asset retirement obligation liability is as
+follows: 
+As
+of December 31, 
+2005 
+2004 
+(In
+thousands) 
+Beginning
+asset retirement obligation 
+$ 
+40,911 
+$ 
+25,485 
+Liabilities
+incurred 
+13,188 
+7,187 
+Liabilities
+settled 
+(955 
+) 
+(620 
+) 
+Accretion
+expense 
+3,279 
+1,984 
+Revision
+to estimated cash flows 
+9,655 
+6,875 
+Ending
+asset retirement obligation 
+$ 
+66,078 
+$ 
+40,911 
+F-26 
+Note
+10 - Derivative Financial Instruments 
+To
+mitigate a portion of the potential exposure to adverse market changes, the
+Company has entered into various derivative contracts. The
+Company realized a net loss of $24.4 million, $49.8 million, and $22.7
+million from its derivative contracts for the years ended
+December 31, 2005, 2004, and 2003 respectively. 
+The
+following table summarizes derivative instrument gain (loss)
+activity: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Derivative
+contract settlements included in oil and gas hedge loss 
+$ 
+(22,539 
+) 
+$ 
+(50,299 
+) 
+$ 
+(22,439 
+) 
+Ineffective
+portion of hedges qualifying for hedge accounting included in derivative
+gain (loss) 
+(1,754 
+) 
+113 
+(246 
+) 
+Non-qualified
+derivative contracts included in derivative gain (loss) 
+139 
+(373 
+) 
+(64 
+) 
+Interest
+rate derivative contract settlements 
+(247 
+) 
+795 
+- 
+Total
+loss 
+$ 
+(24,401 
+) 
+$ 
+(49,764 
+) 
+$ 
+(22,749 
+) 
+Oil
+and Gas Commodity Hedges 
+The
+Company has in place derivative contracts, which included swap and collar
+arrangements, for the sale of oil and natural gas. Including oil and natural
+gas
+collar arrangements entered into subsequent to December 31, 2005, the
+Company has hedge contracts in place through 2011 for a total of approximately
+13.0 million Bbls and 73.7 million MMBTU of anticipated production.
+The
+Company anticipates that all forecasted transactions will occur by the end
+of
+their originally specified periods. All contracts are entered into for other
+than trading purposes. 
+The
+Company attempts to qualify its oil and natural gas derivative instruments
+as
+cash flow hedges for accounting purposes. As of December 31, 2005, all oil
+and natural gas derivative instruments qualified as cash flow hedges for
+accounting purposes. T he
+estimated fair value of oil
+and
+natural gas derivative contracts designated
+and qualifying as cash flow hedges under SFAS No. 133 was a net
+liability of $90 million at December
+31, 2005.
+Gains
+or
+losses from the settlement of oil and gas derivative contracts are reported
+in
+the total operating revenues section on the consolidated statements of
+operations. Changes in the fair value of derivative instruments designated
+as
+cash flow hedges, to the extent they are effective in offsetting cash flows
+attributable to the hedged risk, are recorded in other comprehensive income
+until the hedged item is recognized in earnings. Any change in fair value
+resulting from ineffectiveness is recognized currently in derivative gain (loss)
+in the consolidated statement of operations. 
+The
+Company seeks to minimize ineffectiveness by entering into oil derivative
+contracts indexed to NYMEX and gas contracts indexed to regional index prices
+associated with pipelines in proximity to the Company’s areas of production. As
+the Company’s derivative contracts contain the same index as the Company’s sale
+contracts, this results in hedges that are highly correlated with the underlying
+hedged item. 
+F-27 
+Derivative
+gain or loss for the years ended December 31, 2005, 2004, and 2003, includes
+a
+net loss of $1.8 million, a net gain of $113,000, and a net loss of
+$246,000, respectively, from ineffectiveness related to oil and natural gas
+derivative contracts. 
+As
+of
+December
+31, 2005,
+the
+amount of unrealized loss net of deferred income taxes to be reclassified from
+accumulated other comprehensive income to oil and gas production operating
+revenues in the next twelve months was $17.0 million. 
+Interest
+Rate Derivative Contracts 
+In
+October 2003 the Company entered into fixed-to-floating interest rate swaps
+for
+a total notional amount of $50 million through March 20, 2007. Under
+the swaps, St. Mary will be paid a fixed interest rate of 5.75 percent and
+will pay a variable interest rate of 235 basis points above the six-month
+LIBOR rate as determined on the semi-annual settlement date. The payment dates
+of the swaps match exactly with the interest payment dates of the Convertible
+Notes. 
+The
+Company entered into a floating-to-fixed interest rate swap on
+April 13, 2005, for a total notional amount of $50 million
+through March 20, 2007, that effectively offsets the fixed-to-floating
+interest rate swaps described above. Under the swap, St. Mary will be paid
+a
+variable interest rate of 235 basis points above the six-month LIBOR rate
+as determined on the semi-annual settlement date and will pay a fixed interest
+rate of 6.85 percent. The payment dates of the swap match exactly with the
+interest payment dates of the Convertible Notes and the fixed-to-floating
+interest rate swaps. The impact of this instrument, when combined with the
+other
+interest rate swaps, is that the Company has fixed its net liability related
+to
+the interest rate swaps and will pay a 1.1 percent interest factor on
+$50 million of notional debt through March 2007. 
+During
+the year ended December 31, 2005, the Company made payments of $247,000,
+and during the year ended December 31 , 2004,
+the
+Company received payments of $795,000 under the swap arrangements. These
+payments are included in the Company’s interest expense. 
+The
+fair
+value of the interest rate derivatives was a liability of $646,000 as of
+December 31, 2005. The Company recorded a net derivative loss in the
+consolidated statements of operations of $213,000, $328,000, and $104,000 for
+the years ended December 31, 2005, 2004, and 2003, respectively, from
+mark-to-market adjustments for these derivatives. These swaps do not qualify
+for
+fair value hedge treatment under SFAS No. 133 and related
+pronouncements. 
+Convertible
+Note Derivative Interest 
+The
+contingent interest provision of the Convertible Notes is considered an embedded
+equity-related derivative that is not clearly and closely related to the fair
+value of an equity interest and therefore must be separately accounted for
+as a
+derivative instrument. The value of the derivative at issuance of the
+Convertible Notes in March 2002 was $474,000. This amount was recorded as a
+decrease to the Convertible Notes payable in the consolidated balance sheets.
+Interest expense for the years ended December 2005, 2004, and 2003,
+includes $95,000 of annual amortization of the original value of this
+derivative. Derivative gain (loss) in the consolidated statements of operations
+for the years ended December 31, 2005, 2004, and 2003, includes a net
+gain of $352,000, a net loss of $45,000, and a net gain of $40,000,
+respectively, from mark-to-market adjustments for this derivative. The fair
+value of this derivative was a liability of $468,000 and $820,000 at December
+31, 2005 and 2004, respectively. 
+F-28 
+Note
+11 - Repurchase of Common Stock 
+Stock
+Repurchase Program 
+In
+August 2004 the Company’s Board of Directors approved an increase in the
+number of shares that may be repurchased under the original authorization
+approved in August 1998 to 6,000,000 as of the effective date of the
+resolution. The shares may be repurchased from time to time in open market
+transactions or privately negotiated transactions, subject to market conditions
+and other factors, including certain provisions of St. Mary’s existing credit
+facility agreement and compliance with securities laws. Stock repurchases may
+be
+funded with existing cash balances, internal cash flow and borrowings under
+the
+credit facility. As of December 31, 2005, 2,153,882 shares of the Company’s
+common stock had been repurchased under the plan. The Company repurchased
+1,175,282 and 978,600 shares in 2005 and 2004, respectively. 
+Repurchase
+of St. Mary Common Stock from Flying J 
+In
+February 2004 the Company repurchased 6,671,636 restricted shares of its
+common stock from Flying J Oil & Gas Inc. and Big West Oil & Gas
+Inc. (collectively “Flying J”) for a total of $91.0 million.
+St. Mary originally issued these shares to Flying J on
+January 29, 2003, in connection with St. Mary's acquisition of
+certain oil and gas properties. In addition to issuing the shares in the
+acquisition, St. Mary loaned Flying J $71.6 million.
+Flying J used the proceeds of the stock repurchase to repay their
+outstanding loan balance of $71.6 million. Accrued interest, which had not
+been recorded by the Company for financial reporting purposes due to the
+non-recourse nature of the loan, was forgiven. The net $19.4 million cash
+outlay for the repurchase was funded from the Company's existing cash balances
+and borrowings under its bank credit facility. 
+Note
+12 - Disclosures about Oil and Gas Producing Activities 
+Costs
+Incurred in Oil and Gas Producing Activities: 
+Costs
+incurred in oil and gas property acquisition, exploration and development
+activities, whether capitalized or expensed, are summarized as follows. The
+2005, 2004 and 2003 amounts include $22.8
+million, $14.1 million, and $5.5 million, respectively, of capitalized
+costs associated with asset retirement obligations. 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Development
+costs 
+$ 
+249,518 
+$ 
+190,829 
+$ 
+111,908 
+Exploration 
+69,817 
+37,977 
+33,296 
+Acquisitions: 
+Proved 
+84,981 
+69,054 
+73,989 
+Unproved 
+2,853 
+7,646 
+8,942 
+Leasing
+activity 
+14,330 
+7,877 
+7,480 
+Total
+$ 
+421,499 
+$ 
+313,383 
+$ 
+235,615 
+F-29 
+The
+following table reflects the net changes in capitalized exploratory well costs
+during 2005, 2004 and 2003, and does not include amounts that were capitalized
+and either subsequently expensed or reclassified to producing well costs in
+the same period. Capitalized exploratory well costs for fiscal years ending
+December 31, 2004 and December 31, 2003 are presented based on the Company’s
+previous accounting policy. 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Beginning
+balance at January 1, 
+$ 
+189 
+$ 
+544 
+$ 
+3,335 
+Capitalized
+exploratory well costs charged to expense upon the adoption of FSP
+FAS
+19-1 
+- 
+- 
+- 
+Additions
+to capitalized exploratory well costs pending the determination of
+proved
+reserves 
+7,994 
+189 
+544 
+Reclassifications
+to wells, facilities, and equipment based on the determination of
+proved
+reserves 
+(189 
+) 
+- 
+(333 
+) 
+Capitalized
+exploratory well costs charged to expense 
+- 
+(544 
+) 
+(3,002 
+) 
+Ending
+balance as December 31, 
+$ 
+7,994 
+$ 
+189 
+$ 
+544 
+No
+exploratory well costs have been capitalized for a period greater than one
+year
+from the completion of exploratory drilling. 
+Oil
+and Gas Reserve Quantities (Unaudited): 
+For
+all
+years presented, Ryder Scott Company L.P. and/or Netherland, Sewell and
+Associates, Inc. (“NSAI”) prepared the reserve information for greater than 80
+percent of the PV-10 value. The Company engaged NSAI for the first time in
+2004.
+St. Mary prepared the reserve estimates for the remainder of all
+properties. The Company emphasizes that reserve estimates are inherently
+imprecise and that estimates of new discoveries and undeveloped locations are
+more imprecise than estimates of established proved producing oil and gas
+properties. Accordingly, these estimates are expected to change as future
+information becomes available. 
+F-30 
+Proved
+oil and gas reserves are the estimated quantities of crude oil, natural gas
+and
+natural gas liquids that geological and engineering data demonstrate with
+reasonable certainty to be recoverable in future years from known reservoirs
+under existing economic and operating conditions. Proved developed oil and
+gas
+reserves are those expected to be recovered through existing wells with existing
+equipment and operating methods. All of the Company’s proved reserves are
+located in the Continental United States and Gulf of Mexico. 
+Presented
+below is a summary of the changes in estimated reserves of the
+Company: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+Oil
+or 
+Oil
+or 
+Oil
+or 
+Condensate 
+Gas 
+Condensate 
+Gas 
+Condensate 
+Gas 
+(MBbl) 
+(MMcf) 
+(MBbl) 
+(MMcf) 
+(MBbl) 
+(MMcf) 
+Developed
+and undeveloped: 
+Beginning
+of year 
+56,574 
+319,196 
+47,787 
+307,024 
+36,119 
+274,172 
+Revisions
+of previous estimate 
+1,593 
+24,354 
+1,994 
+(21,885 
+) 
+2,856 
+3,904 
+Discoveries
+and extensions 
+5,839 
+105,091 
+6,306 
+63,185 
+3,681 
+69,189 
+Purchases
+of minerals in place 
+4,831 
+20,823 
+5,773 
+17,635 
+11,952 
+41,335 
+Sales
+of reserves 
+(7 
+) 
+(588 
+) 
+(487 
+) 
+(165 
+) 
+(2,280 
+) 
+(31,913 
+) 
+Production 
+(5,927 
+) 
+(51,801 
+) 
+(4,799 
+) 
+(46,598 
+) 
+(4,541 
+) 
+(49,663 
+) 
+End
+of year (a) 
+62,903 
+417,075 
+56,574 
+319,196 
+47,787 
+307,024 
+Proved
+developed reserves: 
+Beginning
+of year 
+47,992 
+272,295 
+43,693 
+264,140 
+33,580 
+228,973 
+End
+of year 
+55,971 
+313,125 
+47,992 
+272,295 
+43,693 
+264,140 
+(a) 
+At
+December 31, 2005, 2004, and 2003 amounts include approximately 435,480,
+and 1,119 MMcf, respectively, representing the Company's net underproduced
+gas balancing position. 
+Standardized
+Measure of Discounted Future Net Cash Flows (Unaudited): 
+SFAS
+No.
+69, “Disclosures about Oil and Gas Producing Activities,” prescribes guidelines
+for computing a standardized measure of future net cash flows and changes
+therein relating to estimated proved reserves. The Company has followed these
+guidelines, which are briefly discussed below. 
+Future
+cash inflows and future production and development costs are determined by
+applying benchmark prices and costs, including transportation, quality and
+basis
+differentials, in effect at year-end to the year-end estimated quantities of
+oil
+and gas to be produced in the future. Each property the Company operates is
+also
+charged with field-level overhead in the estimated reserve calculation.
+Estimated future income taxes are computed using current statutory income tax
+rates, including consideration for estimated future statutory depletion. The
+resulting future net cash flows are reduced to present value amounts by applying
+a ten percent annual discount factor. 
+Future
+operating costs are determined based on estimates of expenditures to be incurred
+in developing and producing the proved oil and gas reserves in place at the
+end
+of the period, using year-end costs and assuming continuation of existing
+economic conditions, plus Company overhead incurred by the central
+administrative office attributable to operating activities. 
+F-31 
+The
+assumptions used to compute the standardized measure are those prescribed by
+the
+FASB and the Securities and Exchange Commission. These assumptions do not
+necessarily reflect the Company's expectations of actual revenues to be derived
+from those reserves, nor their present value. The limitations inherent in the
+reserve quantity estimation process, as discussed previously, are equally
+applicable to the standardized measure computations since these estimates are
+the basis for the valuation process. The following prices as adjusted for
+transportation, quality and basis differentials, were used in the calculation
+of
+the standardized measure: 
+2005 
+2004 
+2003 
+Gas
+(per Mcf) 
+$ 
+8.34 
+$ 
+5.80 
+$ 
+5.70 
+Oil
+(per Bbl) 
+$ 
+55.63 
+$ 
+40.06 
+$ 
+31.01 
+The
+following summary sets forth the Company's future net cash flows relating to
+proved oil and gas reserves based on the standardized measure prescribed in
+SFAS
+No. 69: 
+As
+of December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Future
+cash inflows 
+$ 
+6,979,279 
+$ 
+4,118,188 
+$ 
+3,232,605 
+Future
+production costs 
+(2,146,590 
+) 
+(1,349,380 
+) 
+(963,226 
+) 
+Future
+development costs 
+(385,379 
+) 
+(164,797 
+) 
+(101,935 
+) 
+Future
+income taxes 
+(1,448,444 
+) 
+(827,368 
+) 
+(735,947 
+) 
+Future
+net cash flows 
+2,998,866 
+1,776,643 
+1,431,497 
+10
+percent annual discount 
+(1,286,568 
+) 
+(742,705 
+) 
+(571,541 
+) 
+Standardized
+measure of discounted 
+future
+net cash flows 
+$ 
+1,712,298 
+$ 
+1,033,938 
+$ 
+859,956 
+The
+principle sources of change in the standardized measure of discounted future
+net
+cash flows are: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Standard
+measure, beginning of year 
+$ 
+1,033,938 
+$ 
+859,956 
+$ 
+581,862 
+Sales
+of oil and gas produced, net of 
+production
+costs 
+(590,671 
+) 
+(368,099 
+) 
+(299,044 
+) 
+Net
+changes in prices and production costs 
+725,154 
+166,826 
+168,661 
+Extensions,
+discoveries and other, net of 
+production
+costs 
+422,481 
+279,763 
+226,181 
+Purchase
+of minerals in place 
+132,185 
+73,875 
+178,264 
+Development
+costs incurred during the year 
+55,324 
+46,156 
+22,763 
+Changes
+in estimated future development costs 
+(42,710 
+) 
+(17,489 
+) 
+11,175 
+Revisions
+of previous quantity estimates 
+117,763 
+(24,271 
+) 
+45,551 
+Accretion
+of discount 
+150,112 
+125,175 
+78,869 
+Sales
+of reserves in place 
+(1,000 
+) 
+(3,906 
+) 
+(47,270 
+) 
+Net
+change in income taxes 
+(314,685 
+) 
+(75,389 
+) 
+(211,381 
+) 
+Changes
+in timing and other 
+24,407 
+(28,659 
+) 
+104,325 
+Standardized
+measure, end of year 
+$ 
+1,712,298 
+$ 
+1,033,938 
+$ 
+859,956 
+F-32 
+Note
+13 - Quarterly Financial Information (Unaudited) 
+The
+Company’s quarterly financial information for fiscal 2005 and 2004 is as follows
+(in thousands, except per share amounts): 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+Year
+Ended December 31, 2005 
+Total
+revenue 
+$ 
+143,818 
+$ 
+164,574 
+$ 
+203,304 
+$ 
+227,894 
+Less:
+costs and expenses 
+86,161 
+101,820 
+158,721 
+146,894 
+Income
+from operations 
+$ 
+57,657 
+$ 
+62,754 
+$ 
+44,583 
+$ 
+81,000 
+Income
+before income taxes and cumulative effect of change in accounting
+principle 
+$ 
+55,795 
+$ 
+60,578 
+$ 
+42,322 
+$ 
+79,542 
+Net
+income 
+$ 
+35,103 
+$ 
+38,261 
+$ 
+27,334 
+$ 
+51,238 
+Basic
+net income per common share 
+$ 
+0.61 
+$ 
+0.67 
+$ 
+0.48 
+$ 
+0.91 
+Diluted
+net income per common share 
+$ 
+0.54 
+$ 
+0.59 
+$ 
+0.42 
+$ 
+0.78 
+Dividends
+declared per common share 
+$ 
+0.05 
+$ 
+- 
+$ 
+0.05 
+$ 
+- 
+Year
+Ended December 31, 2004 
+Total
+revenue 
+$ 
+96,482 
+$ 
+102,151 
+$ 
+108,078 
+$ 
+126,388 
+Less:
+costs and expenses 
+60,603 
+65,566 
+71,575 
+83,440 
+Income
+from operations 
+$ 
+35,879 
+$ 
+36,585 
+$ 
+36,503 
+$ 
+42,948 
+Income
+before income taxes and cumulative effect of change in accounting
+principle 
+$ 
+34,535 
+$ 
+35,262 
+$ 
+35,125 
+$ 
+41,306 
+Net
+income 
+$ 
+21,449 
+$ 
+21,836 
+$ 
+22,565 
+$ 
+26,629 
+Basic
+net income per common share 
+$ 
+0.36 
+$ 
+0.38 
+$ 
+0.40 
+$ 
+0.46 
+Diluted
+net income per common share 
+$ 
+0.33 
+$ 
+0.34 
+$ 
+0.36 
+$ 
+0.41 
+Dividends
+declared per common share 
+$ 
+- 
+$ 
+0.025 
+$ 
+0.025 
+$ 
+- 
+F-33 
+SIGNATURES 
+Pursuant
+to the requirements of Section 13 or 15(d) of the Securities Exchange Act
+of
+1934, the registrant has duly caused this report to be signed on its behalf
+by
+the undersigned, thereunto duly authorized. 
+/ 
+ST. MARY LAND & EXPLORATION
+COMPANY 
+(Registrant) 
+Date:
+February 23, 2006 
+By: 
+/s/ MARK
+A.
+HELLERSTEIN 
+Mark
+A. Hellerstein 
+Chairman
+of the
+Board of Directors, President 
+and
+Chief Executive Officer 
+GENERAL
+POWER OF ATTORNEY 
+KNOW
+ALL
+PERSONS BY THESE PRESENTS, that each person whose signature appears below
+constitutes and appoints each of Mark A. Hellerstein and David W. Honeyfield
+his
+or her true and lawful attorney-in-fact and agent with full power of
+substitution and resubstitution, and each with full power to act alone, for
+the
+undersigned and in his or her name, place and stead, in any and all capacities,
+to sign any amendments to this Annual Report on Form 10-K for the fiscal
+year
+ended December 31, 2005, and to file the same, with exhibits thereto and
+other
+documents in connection therewith, with the Securities and Exchange Commission,
+hereby ratifying and confirming all that each of said attorney-in-fact, or
+his
+substitute or substitutes, may do or cause to be done by virtue
+hereof. 
+Pursuant
+to the requirements of the Securities Exchange Act of 1934, this report has
+been
+signed below by the following persons on behalf of the registrant and in
+the
+capacities and on the dates indicated. 
+Signature 
+Title 
+Date 
+/S/
+MARK A. HELLERSTEIN 
+Chairman
+of the Board of Directors, 
+February
+23, 2006 
+Mark
+A. Hellerstein 
+President
+and Chief Executive Officer 
+S/
+DAVID W. HONEYFIELD 
+Vice
+President-Chief Financial Officer, 
+February
+23, 2006 
+David
+W. Honeyfield 
+Secretary
+and Treasurer 
+/S/
+GARRY A. WILKENING 
+Vice
+President-Administration 
+February
+23, 2006 
+Garry
+A. Wilkening 
+and
+Controller 
+Signature 
+Title 
+Date 
+/S/
+BARBARA M. BAUMANN 
+Director 
+February
+23, 2006 
+Barbara
+M. Baumann 
+/S/
+LARRY W. BICKLE 
+Director 
+February
+23, 2006 
+Larry
+W. Bickle 
+/S/
+THOMAS E. CONGDON 
+Director 
+February
+23, 2006 
+Thomas
+E. Congdon 
+/S/
+WILLIAM J. GARDINER 
+Director 
+February
+23, 2006 
+William
+J. Gardiner 
+/S/
+WILLIAM D. SULLIVAN 
+Director 
+February
+23, 2006 
+William
+D. Sullivan 
+/S/
+JOHN M. SEIDL 
+Director 
+February
+23, 2006 
+John
+M. Seidl
\ No newline at end of file
diff --git a/raw/filings/0000893538/2005/0001144204-06-007665/filing_metadata.csv b/raw/filings/0000893538/2005/0001144204-06-007665/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..52f91c049841e9dd6ab986a2af047824c3842fa9
--- /dev/null
+++ b/raw/filings/0000893538/2005/0001144204-06-007665/filing_metadata.csv
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+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000893538,SM,SM Energy Co,10-K,2006-02-27,2005-12-31,2006-02-24T23:34:39.000Z,0001144204-06-007665,v036350_10k.htm,,4059847,0,0,https://www.sec.gov/Archives/edgar/data/893538/000114420406007665/v036350_10k.htm,https://www.sec.gov/Archives/edgar/data/893538/000114420406007665/,2005,2005,1
diff --git a/raw/filings/0000893538/2005/0001144204-06-007665/item1.txt b/raw/filings/0000893538/2005/0001144204-06-007665/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e1c7f715ce73db3b3b62cd6750a84866bdde69f0
--- /dev/null
+++ b/raw/filings/0000893538/2005/0001144204-06-007665/item1.txt
@@ -0,0 +1,6229 @@
+Item 1 of Part I of this report. 
+Successful
+efforts method of accounting. Generally
+accepted accounting principles provide for two alternative methods for the
+oil
+and gas industry to use in accounting for oil and gas producing activities.
+These two methods are generally known in our industry as the full cost method
+and the successful efforts method. Both methods are widely used. The methods
+are
+different enough that in many circumstances the same set of facts will provide
+materially different financial statement results within a given year. We have
+chosen the successful efforts method of accounting for our oil and gas producing
+activities, and a detailed description is included in Note 1 of Part IV, Item
+15
+of this report. 
+Revenue
+recognition .
+Our
+revenue recognition policy is significant because revenue is a key component
+of
+our results of operations and our forward-looking statements contained in our
+analyses of liquidity and capital resources. We derive our revenue primarily
+from the sale of produced natural gas and crude oil. We report revenue as the
+gross amounts we receive before taking into account production taxes and
+transportation costs, which are reported as separate expenses. Revenue is
+recorded in the month our production is delivered to the purchaser, but payment
+is generally received between 30 and 90 days after the date of production.
+No
+revenue is recognized unless it is determined that title to the product has
+transferred to a purchaser. At the end of each month we make estimates of the
+amount of production delivered to the purchaser and the price we will receive.
+We use our knowledge of our properties, their historical performance, the
+anticipated effect of weather conditions during the month of production, NYMEX
+and local spot market prices and other factors as the basis for these estimates.
+Variances between our estimates and the actual amounts received are recorded
+in
+the month payment is received. A ten percent change in our year-end revenue
+accrual would have impacted net income before tax by $13.9 million in
+2005. 
+53 
+Crude
+oil and natural gas hedging .
+Our
+crude oil and natural gas hedging contracts usually qualify for cash flow
+deferral hedge accounting under SFAS No. 133. Under this accounting
+pronouncement a majority of the gain or loss from a contract qualifying as
+a
+cash flow hedge is deferred as to statement of operations recognition. The
+position reflected in the statement of operations is based on the actual
+settlements with the counterparty. If our natural gas and crude oil hedge
+contracts did not qualify for hedge accounting treatment or we chose not to
+use
+this hedge accounting methodology, our periodic statements of operations could
+include significant changes in the estimate of non-cash derivative gain or
+loss
+due to swings in the value of these contracts. Consequently, we would report
+a
+different amount for oil and gas hedge loss in our statements of operations.
+These fluctuations could be especially significant in a volatile pricing
+environment such as what we have encountered over the last three years. Net
+income after tax would have increased or (decreased) for 2005, 2004 and 2003
+by
+the following amounts: ($57.2 million), $2.6 million, and ($14.3 million),
+respectively, if our hedges did not qualify as cash flow deferral hedges under
+SFAS 133. 
+Change
+in Net Profits Plan Liability .
+We
+record the estimated liability of future payments for our Net Profit Plan.
+The
+estimated liability is calculated based on a number of assumptions, including
+estimates of oil and gas reserves, recurring and workover lease operating
+expense, product and ad valorem tax rates, present value discount factors and
+pricing assumptions. Additional discussion is included in the analysis in the
+above section titled Overview of the Company, under the heading Net
+Profits Plan .
+Asset
+retirement obligations. We
+are required
+to recognize an estimated liability for future costs associated with the
+abandonment of our oil and gas properties. We base our estimate of the liability
+on our historical experience in abandoning oil and gas wells projected into
+the
+future based on our current understanding of federal and state regulatory
+requirements. Our present value calculations require us to estimate the economic
+lives of our properties, assume what future inflation rates apply to external
+estimates as well as determine what credit adjusted risk-free rate to use.
+The
+statement of operations impact of these estimates is reflected in our
+depreciation, depletion and amortization calculations and occurs over the
+remaining life of our oil and gas properties. 
+Valuation
+of long-lived and intangible assets. Our
+property and equipment is recorded at cost. An impairment allowance is provided
+on unproved property when we determine that the property will not be developed
+or the carrying value will not be realized. We evaluate the realizability of
+our
+proved properties and other long-lived assets whenever events or changes in
+circumstances indicate that impairment may be appropriate. Our impairment test
+compares the expected undiscounted future net revenues from a property, using
+escalated pricing, with the related net capitalized costs of the property at
+the
+end of each period. When the net capitalized costs exceed the undiscounted
+future net revenue of a property, the cost of the property is written down
+to
+our estimate of fair value, which is determined by applying a discount rate
+that
+we believe is indicative of the current market. Our criteria for an acceptable
+internal rate of return are subject to change over time. Different pricing
+assumptions or discount rates could result in a different calculated
+impairment. 
+Income
+taxes .
+We
+provide for deferred income taxes on the difference between the tax basis of
+an
+asset or liability and its carrying amount in our financial statements in
+accordance with SFAS No. 109, Accounting for Income Taxes. This
+difference will result in taxable income or deductions in future years when
+the
+reported amount of the asset or liability is recovered or settled, respectively.
+Considerable judgment is required in determining when these events may occur
+and
+whether recovery of an asset is more likely than not. Additionally, our federal
+and state income tax returns are generally not filed before the consolidated
+financial statements are prepared, therefore we estimate the tax basis of our
+assets and liabilities at the end of each period as well as the effects of
+tax
+rate changes, tax credits and net operating and capital loss carryforwards
+and
+carrybacks. Adjustments related to differences between the estimates we used
+and
+actual amounts we reported are recorded in the period in which we file our
+income tax returns. These adjustments and changes in our estimates of asset
+recovery could have an impact on our results of operations. A one percent change
+in our effective tax rate would have affected our calculated income tax expense
+by $2.4 million for the year ended December 31, 2005. 
+54 
+Stock-based
+compensation. 
+We have
+historically accounted for stock-based compensation using the intrinsic value
+recognition and measurement principles detailed in Accounting Principles Board
+Opinion No. 25, Accounting for Stock Issued to Employees. No stock-based
+employee compensation expense relating to stock options has been reflected
+in
+our expense as all options granted under our plans had an exercise price equal
+to the market value of the underlying common stock on the date of grant. We
+currently use the Black-Scholes option valuation model to calculate required
+disclosures under SFAS No. 123, Accounting for Stock Based Compensation. As
+of
+January 1, 2006, we have adopted the provision of SFAS No. 123(R), “Share-Based
+Payment.” This statement requires us to record expense associated with the fair
+value of stock-based compensation. As a result of adoption of this statement,
+we
+expect to record compensation expense associated with unvested stock options
+totaling $2.2 million recorded in future periods under the modified-prospective
+adoption method. We have recorded expense associated with the issuance of
+restricted stock units since the plan was adopted in 2004 and units were first
+issued. Going forward this expense will decrease on a relative per share basis
+for all units that have already been issued because the accounting standard
+requires cost recognition using fair value estimates of the restricted stock
+units, rather than intrinsic value. 
+Additional
+Comparative Data in Tabular Format: 
+Change
+Between Years 
+Oil
+and Gas Production Revenues : 
+2005
+and 2004 
+2004
+and 2003 
+Increase
+in oil and gas production 
+revenues
+(in thousands) 
+$ 
+297,687 
+$ 
+48,204 
+Components
+of Revenue Increases (Decreases): 
+Oil 
+Realized
+price change per Bbl 
+$ 
+18.40 
+$ 
+5.57 
+Realized
+price percentage change 
+57% 
+21% 
+Production
+change (MBbl) 
+1,128 
+258 
+Production
+percentage change 
+23% 
+6% 
+Natural
+Gas 
+Realized
+price change per Mcf 
+$ 
+2.38 
+$ 
+0.63 
+Realized
+price percentage change 
+43% 
+13% 
+Production
+change (MMcf) 
+5,204 
+(3,065) 
+Production
+percentage change 
+11% 
+(6)% 
+Our
+product mix as a percentage of total oil and gas revenue and
+production: 
+Years
+Ended December 31, 
+Revenue 
+2005 
+2004 
+2003 
+Oil 
+42% 
+38% 
+34% 
+Natural
+Gas 
+58% 
+62% 
+66% 
+Production 
+Oil 
+41% 
+38% 
+35% 
+Natural
+Gas 
+59% 
+62% 
+65% 
+55 
+Information
+regarding the effects of oil and gas hedging activity: 
+Years
+Ended December 31, 
+2005 
+2004 
+2003 
+Oil
+Hedging 
+Percentage
+of oil production hedged 
+24 % 
+45% 
+54% 
+Oil
+volumes hedged (MBbl) 
+1,419 
+2,156 
+2,474 
+Decrease
+in oil revenue 
+$ 
+(13.3
+million 
+) 
+$ 
+(34.8
+million 
+) 
+$ 
+(11.1
+million 
+) 
+Average
+realized oil price per Bbl before hedging 
+$ 
+53.18 
+$ 
+39.77 
+$ 
+29.40 
+Average
+realized oil price per Bbl after hedging 
+$ 
+50.93 
+$ 
+32.53 
+$ 
+26.96 
+Natural
+Gas Hedging 
+Percentage
+of gas production hedged 
+25% 
+25% 
+40% 
+Natural
+gas volumes hedged (MMBtu) 
+14.0
+million 
+12.9
+million 
+21.7
+million 
+Decrease
+in gas revenue 
+$ 
+(9.2
+million 
+) 
+$ 
+(15.5
+million 
+) 
+$ 
+(11.4
+million 
+) 
+Average
+Average realized gas price per Mcf before hedging 
+$ 
+8.08 
+$ 
+5.85 
+$ 
+5.12 
+Average
+Average realized gas price per Mcf after hedging 
+$ 
+7.90 
+$ 
+5.52 
+$ 
+4.89 
+Information
+regarding the components of exploration expense: 
+Years
+Ended December 31, 
+Summary
+of Exploration Expense (in millions) 
+2005 
+2004 
+2003 
+Geological
+and geophysical expenses 
+$ 
+7.9 
+$ 
+7.3 
+$ 
+5.1 
+Exploratory
+dry holes 
+8.1 
+4.2 
+8.5 
+Overhead
+and other expenses 
+28.9 
+17.1 
+11.7 
+Total 
+$ 
+44.9 
+$ 
+28.6 
+$ 
+25.3 
+Comparison
+of Financial Results and Trends between 2005 and 2004 
+Oil
+and gas production revenues .
+Average
+net daily production increased 16 percent to 239.4 MMCFE for 2005 compared
+with
+206.0 MMCFE in 2004. The following table presents specific components that
+contributed to the increase in revenue between the two periods: 
+Average
+Net Daily Production 
+Added
+Oil
+and Gas 
+Revenue
+Added 
+Production 
+Costs
+Added 
+(MMCFE) 
+(In
+millions) 
+(In
+millions) 
+Williston
+Basin Middle Bakken Play 
+19.9 
+37.5 
+1.3 
+Paggi-Broussard
+1 
+16.3 
+37.5 
+0.9 
+Border
+acquisition 
+8.3 
+18.2 
+2.1 
+Agate
+acquisition 
+7.0 
+15.2 
+5.0 
+Goldmark
+acquisition 
+3.9 
+7.0 
+3.9 
+Wold
+acquisition 
+3.2 
+8.5 
+3.1 
+Other
+wells completed in 2004 and 2005 
+27.6 
+105.3 
+15.2 
+Other
+acquisitions 
+0.8 
+2.3 
+0.8 
+Total 
+87.0 
+231.5 
+32.3 
+The
+revenue increases in this table also reflect the difference in oil and gas
+prices received between the comparable periods. The production increases are
+offset by natural declines in production from older properties to result in
+the
+net increase in production between the years presented. Additional production
+costs reflect increases resulting from inflation and competition for
+resources. 
+56 
+Oil
+and gas hedge loss. 
+The 55
+percent decrease in total oil and gas hedge loss to $22.5 million was
+caused by a change in the composition of our hedge position and changes in
+oil
+and gas commodity prices. During 2004 we had significant hedge positions related
+to contracts entered into for acquisitions that closed in 2002 and 2003. These
+hedges were at lower fixed contract prices that resulted in a larger realized
+hedge loss during 2004. These hedges expired in late 2004. 
+Oil
+and gas production expenses. Total
+production costs increased $47.4 million or 50 percent to
+$142.9 million for 2005, from $95.5 million in 2004. Our current year
+acquisition of properties added $8.1 million of incremental production
+costs, prior year acquisitions of properties added $6.8 million of incremental
+production costs, and other wells completed in 2004 and 2005 added
+$15.2 million of incremental production costs in 2005 that were not
+reflected in 2004. We experienced an increase in production taxes consistent
+with the increase in revenue from higher realized prices. 
+Total
+oil
+and gas production costs per MCFE increased $0.37 to $1.64 for 2005, compared
+with $1.27 for 2004. This increase is comprised of the
+following: 
+· 
+An
+$0.08 increase in production taxes in our Mid-Continent
+region resulting
+from higher natural gas revenues and the suspension of
+Oklahoma severance
+tax incentives in 2005 due to average natural gas prices
+in excess of
+price caps; 
+· 
+An
+$0.11 increase in production taxes due to higher revenue
+from crude oil in
+our Rocky Mountain and Permian regions; 
+· 
+A
+$0.01 increase in production taxes in our ArkLaTex and Gulf
+coast regions
+reflecting higher natural gas prices offset by additional benefits
+from
+severance tax incentive credits received from Louisiana and
+Texas; 
+· 
+A
+$0.12 increase in recurring LOE reflecting a $0.03 increase
+due to the
+start-up activity in our Hanging Woman Basin coalbed methane
+project, a
+general seven percent increase that we had forecast and cost
+increases we
+had not forecast in our budget process; 
+· 
+A
+$0.05 increase in workover LOE reflecting a $0.04 increase
+in our Rocky
+Mountain region. 
+Exploration
+expense .
+Exploration expense increased 57 percent in 2005. The most significant component
+of our increase to exploration expense was $12.0 million for exploration
+overhead incurred as we increased the size of our geologic and exploration
+staff
+and incentive compensation related to those individuals. 
+General
+and administrative. 
+General
+and administrative expenses increased $10.8 million or 49 percent to
+$32.8 million for 2005, compared with $22.0 million for 2004. G&A
+increased $0.08 to $0.37 per MCFE for 2005 compared to $0.29 per MCFE for the
+period in 2004. The primary driver for the increase in G&A expense per MCFE
+is the increase in payments under the Net Profits Plan. 
+A
+20
+percent increase in employee count has resulted in an increase in base employee
+compensation of $2.9 million between the year ended December 31, 2005, and
+the
+same period of 2004. Oil and gas price increases have triggered additional
+Net
+Profits Plan payouts and have increased the amounts payable to plan
+participants. Consequently, the current period realized expense associated
+with
+the Net Profits Plan has increased by $12.8 million in 2005. The increase
+in Net Profits Plan payments is the result of the significantly higher oil
+and
+gas prices received, which has the effect of increasing the absolute amount
+of
+payments as well as accelerating the time it takes for pools to reach payout.
+Thirteen of our 19 pools are in payout status as of the end of 2005. The cash
+bonus and RSU bonus are $8.3 million higher than last year as a result of our
+overall performance, which includes an evaluation of reserve replacement,
+production increases and net asset value per share enhancement. 
+The
+incentive plan compensation increases combined with a net $1.8 million increase
+in other compensation expense were partially offset by increases in COPAS
+overhead reimbursements and allocation of G&A to exploration expense. COPAS
+overhead reimbursement from operations increased $3.1 million due to an increase
+in operated well count resulting from our drilling and acquisition programs.
+The
+amount of G&A we allocated to exploration expense increased
+$11.9 million due to incentive plan payment increases and increases in our
+technical exploration staff. 
+57 
+Change
+in Future Net Profits Plan Liability .
+For the
+year ended December 31, 2005, this expense increased $81.9 million to
+$106.3 million from $24.4 million for 2004. This increase reflects our
+estimation of the effect of a sustained higher price environment and the impact
+of hedge contracts entered into in 2005 on the performance of individual pools
+as previously described. This liability is a significant management estimate.
+Adjustments to the liability are subject to estimation and may change
+dramatically from period-to-period based on assumptions used for production
+rates, reserve quantities, commodity pricing, discount rates, tax rates and
+production costs. 
+Interest
+expense. 
+Interest
+expense increased by $2.0 million to $8.2 million for 2005 compared to $6.2
+million for 2004. The increase reflects an increase in our average outstanding
+borrowings and higher interest rates on the floating rate portion of our
+long-term debt. Additionally, we received benefits from fixed-to-floating
+interest rate swaps in effect during 2004 that were effectively offset by
+floating-rate-to-fixed-rate interest rate swaps we entered into in
+April 2005. 
+Income
+tax expense .
+Income
+tax expense totaled $86.3 million for 2005 and $53.7 million in 2004, resulting
+in effective tax rates of 36.3 percent and 36.8 percent, respectively. The
+effective rate change from 2004 reflects changes in the mix of the highest
+marginal state tax rates as a result of acquisition and drilling activity and
+also reflects other permanent differences including the estimated effect of
+the
+domestic production activities deduction from the American Jobs Creation Act
+of 2004. 
+The
+current portion of income tax expense in 2005 is $80.8 million compared to
+$22.5 million in 2004. These amounts are 94 percent and 42 percent of
+total income tax expense for the respective periods. The difference results
+from
+increased estimated taxable income caused by the higher price environment,
+a
+decreased estimated percentage of deductible intangible drilling costs relative
+to gross revenue, and the effect of the change in Net Profit Plan liability,
+which is not currently deductible. We project that the current portion of
+taxable income will be lower in 2006 as a result of our increased drilling
+budget. 
+Comparison
+of Financial Results and Trends between 2004 and 2003 
+Oil
+and gas production revenues .
+Average
+net daily production decreased two percent to 206.0 MMCFE for 2004 compared
+with
+210.7 MMCFE in 2003. Wells completed and properties acquired in 2003 and during
+2004 added revenue of $102.8 million and average net daily production of 38.2
+MMCFE in 2004 compared to 2003. These increases are offset by natural declines
+in production from older properties and 3.9 MMCFE per day of 2003 production
+from properties that were sold in 2003. 
+Oil
+and gas hedge loss. 
+As noted
+in the table above, the 124 percent increase in total oil and gas hedge loss
+to
+$50.3 million for 2004 was caused by a 35 percent increase in the average
+pre-hedge oil price and a 14 percent increase in the pre-hedge gas
+price. 
+Oil
+and gas production expenses. Total
+production costs increased $7.0 million or eight percent to $95.5 million
+for 2004, from $88.5 million in 2003. Our acquisition of properties added
+$2.8 million of incremental production costs, and wells completed in 2003
+and 2004 added $7.7 million of incremental production costs in 2004 that
+were not reflected in 2003. We experienced an increase in production taxes
+consistent with the increase in revenue from higher realized
+prices. 
+Total
+oil
+and gas production costs per MCFE increased $0.12 to $1.27 for 2004, compared
+with $1.15 for 2003. This increase is comprised of the
+following: 
+· 
+A
+$0.07 increase in production taxes due to higher realized
+per MCFE
+prices; 
+· 
+A
+$0.01 increase in transportation costs; 
+· 
+A
+$0.01 decrease in LOE relating to workover
+charges; 
+58 
+· 
+A
+$0.04 increase in LOE that reflects increasing costs
+in our Rocky Mountain
+region; and 
+· 
+A
+$0.01 increase reflecting a general increases in LOE
+per MCFE in our other
+core areas. 
+Exploration
+expense .
+Exploration expense increased 13 percent in 2004. The most significant
+component
+of our increase to exploration expense was $5.5 million for exploration
+overhead
+we incurred as we increased the size of our geologic and exploration
+staff. 
+General
+and administrative expense .
+General
+and administrative expenses increased $807,000 or four percent to $22.0 million
+for 2004, compared with $21.2 million in 2003. The increase in cost on a per
+MCFE basis of $0.01 reflects the effect of the four percent increase in G&A
+and a two percent decrease in production between the respective
+periods. 
+An
+increase in our employee count from 226 to 249 resulted in a general increase
+in
+G&A of $4.2 million between 2004 and 2003. That increase plus a $913,000
+increase in fees that are directly related to Sarbanes-Oxley compliance, and
+a
+$959,000 increase in other professional fees were offset by an increase of
+$5.5 million of general and administrative expense we allocated to
+exploration expense. 
+Change
+in Net Profits Plan liability. For
+the year ended December 31, 2004, the expense related to the change in the
+estimated liability for this plan increased to $24.4 million from
+$5.3 million for 2003. This increase is due to the performance of
+individual pools, the effect of a higher price environment, and the application
+of lower discount rates to reflect the current economics of the market.
+Interest
+expense. 
+Interest
+expense decreased by $1.7 million to $6.2 million for 2004 compared to $8.0
+million for 2003. The decrease reflects the benefit of interest rate swaps
+we
+entered into on October 3, 2003, and decreased average borrowings under our
+credit facility in 2004 relative to the prior year. 
+Income
+tax expense .
+Income
+tax expense totaled $53.7 million for 2004 and $55.9 million in 2003, resulting
+in effective tax rates of 36.8 percent and 38.3 percent, respectively. The
+effective rate change from 2003 reflects percentage depletion and other
+permanent differences as well as changes in the composition of the highest
+marginal state tax rates as a result of acquisition and drilling activity.
+The
+cumulative effect of the change in marginal state tax rates that we recorded
+in
+2004 was a result of filing our 2003 income tax returns and completing the
+evaluation of the impact on future temporary difference reversals. 
+The
+current portion of the income tax expense in 2004 was $22.5 million compared
+to
+$32.2 million in 2003. These amounts are 42 percent and 58 percent of the
+total tax for the respective periods. The difference results from decreased
+estimated taxable income caused by an increase in the estimated percentage
+of
+deductible intangible drilling costs relative to total income and the effect
+of
+an increase in stock option exercises. 
+Cumulative
+effect of change in accounting principal, net of income tax 
+On
+January 1, 2003 we adopted SFAS No. 143. The impact of adoption
+resulted in income to us of $8.8 million offset by the deferred income tax
+effect of $3.4 million. See Note 9 in Part IV, Item 15 of this
+report. 
+59 
+Other
+Liquidity and Capital Resource Information 
+Pension
+Benefits 
+Substantially
+all of our employees who meet age and service requirements participate in a
+non-contributory defined benefit pension plan. At December 31, 2005, we recorded
+a $290,000 pre-tax loss in accumulated other comprehensive income related to
+this plan. We believe this obligation will be funded from future cash flows
+from
+operating activities. For purposes of calculating our obligation under the
+plan,
+we have used an expected return on plan assets of 7.5 percent. We think
+this rate of return is appropriate over the long-term given the 60 percent
+equity and 40 percent debt securities mix of investment of plan assets and
+the
+historical rate of return provided by equity and debt securities since the
+1920s. Our estimated actual rate of return was 7.8 percent for 2005 and was
+10.4
+percent for 2004. The difference in investment income using our projected rate
+of return compared to our actual rates of return for the past two years was
+not
+material and will not have a material effect on the results of operation or
+cash
+flows from operating activities in future years. 
+For
+the
+2005 plan year, a 0.25 percentage point decrease in the discount rate combined
+with a 1.9 percentage point increase in the estimated rate of future
+compensation increases caused a $401,000 increase in the projected benefit
+obligation of the plan. We do not believe this change was material and project
+that it will not have a material effect on the results of operations or on
+cash
+flows from operating activities in future periods. 
+We
+also
+have a supplemental non-contributory defined benefit pension plan that covers
+certain management employees. There are no plan assets for this plan. For the
+2005 plan year, a 0.25 percentage point decrease in the discount rate
+combined with a 1.9 percentage point increase in the estimated rate of future
+compensation increases and the payment of $298,000 in prior year benefits caused
+a $464,000 decrease in the projected benefit obligation for this plan. This
+plan’s accumulated benefit obligation was $1.1 million at December 31, 2005, and
+$1.2 million at December 31, 2004. We believe this obligation will be funded
+from future cash flows from operating activities. 
+Accounting
+Matters 
+We
+recognized a $5.4 million gain net of income tax in 2003 from the adoption
+of
+SFAS No. 143 effective January 1, 2003. 
+Environmental 
+St. Mary’s
+compliance with applicable environmental regulations has not resulted in any
+significant capital expenditures or materially adverse effects to our liquidity
+or results of operations. We believe we are in substantial compliance with
+environmental regulations and foresee that no material expenditures will be
+incurred in the future. However, we are unable to predict the impact that future
+compliance with regulations may have on future capital expenditures, liquidity
+and results of operations. 
+ITEM
+7A. QUANTITATIVE
+AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+The
+information required by this item is provided under the captions “Commodity
+Price Risk and Interest Rate Risk,” “Summary of Oil and Gas Production Hedges in
+Place,” and “Summary of Interest Rate Hedges in Place” in Item 7 above and
+is incorporated herein by reference. 
+ITEM
+8. FINANCIAL
+STATEMENTS AND SUPPLEMENTARY DATA 
+The
+Consolidated Financial Statements that constitute Item 8 follow the text of
+this
+report. An index to the Consolidated Financial Statements and Schedules appears
+in Item 15(a) of this report. 
+60 
+ITEM
+9. CHANGES
+IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
+DISCLOSURE 
+None. 
+ITEM
+9A. CONTROLS
+AND PROCEDURES 
+We
+maintain a system of disclosure controls and procedures that are designed to
+ensure that information required to be disclosed in our SEC reports is recorded,
+processed, summarized and reported within the time periods specified in the
+SEC’s rules and forms, and to ensure that such information is accumulated and
+communicated to our management, including the Chief Executive Officer and the
+Chief Financial Officer, as appropriate to allow timely decisions regarding
+required disclosure. 
+We
+carried out an evaluation, under the supervision and with the participation
+of
+our management, including the Chief Executive Officer and the Chief Financial
+Officer, of the effectiveness of the design and operation of our disclosure
+controls and procedures as of the end of the period covered by this Annual
+Report on Form 10-K. Based upon that evaluation, the Chief Executive Officer
+and
+the Chief Financial Officer concluded that our disclosure controls and
+procedures are effective for the purposes discussed above as of the end of
+the
+period covered by this Annual Report on Form 10-K. There was no change in our
+internal control over financial reporting that occurred during our most recent
+fiscal quarter that has materially affected, or is reasonably likely to
+materially affect, our internal control over financial reporting. 
+MANAGEMENT’S
+REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 
+To
+the
+Stockholders’ of St. Mary Land & Exploration Company 
+Management
+of the Company is responsible for establishing and maintaining adequate internal
+control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f)
+under the Securities Exchange Act of 1934, as amended. The Company’s internal
+control over financial reporting is designed to provide reasonable assurance
+regarding the reliability of financial reporting and the preparation of
+financial statements for external purposes in accordance with generally accepted
+accounting principles. The Company’s internal control over financial reporting
+includes those policies and procedures that: 
+(i) 
+pertain
+to the maintenance of records that, in reasonable detail, accurately
+and
+fairly reflect the transactions and dispositions of the assets of
+the
+Company; 
+(ii) 
+provide
+reasonable assurance that transactions are recorded as necessary
+to permit
+preparation of financial statements in accordance with generally
+accepted
+accounting principles, and that receipts and expenditures of the
+Company
+are being made only in accordance with authorizations of management
+and
+directors of the Company; and 
+(iii) 
+provide
+reasonable assurance regarding prevention or timely detection of
+unauthorized acquisition, use or disposition of the Company’s assets that
+could have a material effect on the financial
+statements. 
+Because
+of the inherent limitations, internal control over financial reporting may
+not
+prevent or detect misstatements. Also, projections of any evaluation of
+effectiveness to future periods are subject to the risk that controls may become
+inadequate because of changes in conditions, or that the degree of compliance
+with the policies or procedures may deteriorate. 
+Management
+assessed the effectiveness of the Company’s internal control over financial
+reporting as of December 31, 2005. In making this assessment, management used
+the criteria set forth by the Committee of Sponsoring Organizations of the
+Treadway Commission in Internal
+Control-Integrated Framework . 
+61 
+Based
+on
+our assessment and those criteria, management believes that the Company
+maintained effective internal control over financial reporting as of December
+31, 2005. 
+The
+Company’s independent registered public accounting firm has issued an
+attestation report on management’s assessment of the Company’s internal controls
+over financial reporting. That report immediately follows this
+report. 
+/S/
+MARK A. HELLERSTEIN 
+/S/
+DAVID W. HONEYFIELD 
+Mark A. Hellerstein 
+David W. Honeyfield 
+Chairman, CEO and President 
+Vice President - CFO, Secretary &
+Treasurer 
+February 23, 2006 
+February 23,
+2006 
+REPORT
+OF
+INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To
+the
+Board of Directors and Stockholders of 
+St.
+Mary
+Land & Exploration Company and Subsidiaries 
+We
+have
+audited management’s assessment, included in the accompanying Management’s
+Report on Internal Control over Financial Reporting, that St. Mary Land &
+Exploration Company and subsidiaries (the “Company”) maintained effective
+internal control over financial reporting as of December 31, 2005, based on
+criteria established in Internal
+Control—Integrated Framework 
+issued
+by the Committee of Sponsoring Organizations of the Treadway Commission. The
+Company’s management is responsible for maintaining effective internal control
+over financial reporting and for its assessment of the effectiveness of internal
+control over financial reporting. Our responsibility is to express an opinion
+on
+management’s assessment and an opinion on the effectiveness of the Company’s
+internal control over financial reporting based on our audit. 
+We
+conducted our audit in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). Those standards require that we
+plan
+and perform the audit to obtain reasonable assurance about whether effective
+internal control over financial reporting was maintained in all material
+respects. Our audit included obtaining an understanding of internal control
+over
+financial reporting, evaluating management’s assessment, testing and evaluating
+the design and operating effectiveness of internal control, and performing
+such
+other procedures as we considered necessary in the circumstances. We believe
+that our audit provides a reasonable basis for our opinions. 
+A
+company’s internal control over financial reporting is a process designed by, or
+under the supervision of, the company’s principal executive and principal
+financial officers, or persons performing similar functions, and effected by
+the
+company’s board of directors, management, and other personnel to provide
+reasonable assurance regarding the reliability of financial reporting and the
+preparation of financial statements for external purposes in accordance with
+generally accepted accounting principles. A company’s internal control over
+financial reporting includes those policies and procedures that (1) pertain
+to
+the maintenance of records that, in reasonable detail, accurately and fairly
+reflect the transactions and dispositions of the assets of the company; (2)
+provide reasonable assurance that transactions are recorded as necessary to
+permit preparation of financial statements in accordance with generally accepted
+accounting principles, and that receipts and expenditures of the company are
+being made only in accordance with authorizations of management and directors
+of
+the company; and (3) provide reasonable assurance regarding prevention or timely
+detection of unauthorized acquisition, use, or disposition of the company’s
+assets that could have a material effect on the financial
+statements. 
+Because
+of the inherent limitations of internal control over financial reporting,
+including the possibility of collusion or improper management override of
+controls, material misstatements due to error or fraud may not be prevented
+or
+detected on a timely basis. Also, projections of any evaluation of the
+effectiveness of the internal control over financial reporting to future periods
+are subject to the risk that the controls may become inadequate because of
+changes in conditions, or that the degree of compliance with the policies or
+procedures may deteriorate. 
+62 
+In
+our
+opinion, management’s assessment that the Company maintained effective internal
+control over financial reporting as of December 31, 2005, is fairly stated,
+in
+all material respects, based on the criteria established in Internal
+Control—Integrated Framework 
+issued
+by the Committee of Sponsoring Organizations of the Treadway Commission. Also
+in
+our opinion, the Company maintained, in all material respects, effective
+internal control over financial reporting as of December 31, 2005,
+based on the criteria established in Internal
+Control—Integrated Framework 
+issued
+by the Committee of Sponsoring Organizations of the Treadway
+Commission. 
+We
+have
+also audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), the consolidated financial statements as of
+and
+for the year ended December 31, 2005, of the Company, and our report dated
+February 23, 2006, expressed an unqualified opinion on those financial
+statements. 
+/S/
+DELOITTE & TOUCHE LLP 
+Denver,
+Colorado 
+February
+23, 2006 
+ITEM
+9B. OTHER
+INFORMATION 
+None. 
+PART
+III 
+ITEM
+10. DIRECTORS
+AND EXECUTIVE OFFICERS OF THE REGISTRANT 
+The
+information required by this Item concerning St. Mary’s Directors is
+incorporated by reference to the information provided under the captions
+“Election of Directors” and “Nominees for Election of Directors” in
+St. Mary’s definitive proxy statement for the 2006 annual meeting of
+stockholders to be filed within 120 days from December 31, 2005. The
+information required by this Item concerning St. Mary’s executive officers
+is incorporated by reference to the information provided in Part I—Item
+4A—EXECUTIVE OFFICERS OF THE REGISTRANT, included in this Form
+10-K. 
+The
+information required by this Item concerning compliance with Section 16(a)
+of
+the Securities Exchange Act of 1934 is incorporated by reference to the
+information provided under the caption “Section 16(a) Beneficial Ownership
+Reporting Compliance” in St. Mary’s definitive proxy statement for the 2006
+annual meeting of stockholders to be filed within 120 days from
+December 31, 2005. 
+ITEM
+11. EXECUTIVE
+COMPENSATION 
+The
+information required by this Item is incorporated by reference to the
+information provided under the captions, “Director Compensation,” “Executive
+Compensation,” “Report of the Compensation Committee on Executive Compensation,”
+“Retirement Plans,” “Performance Graph,” and “Employee Agreements and
+Termination of Employment and Change-in-Control Arrangements” in St. Mary’s
+definitive proxy statement for the 2006 annual meeting of stockholders to be
+filed within 120 days from December 31, 2005. 
+63 
+ITEM 12. 
+SECURITY
+OWNERSHIP OF
+CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
+AND RELATED STOCKHOLDER
+MATTERS 
+The
+information required by this Item concerning security ownership of certain
+beneficial owners and management is incorporated by reference to the information
+provided under the caption “Security Ownership of Certain Beneficial Owners and
+Management” in St. Mary’s definitive proxy statement for the 2006 annual
+meeting of stockholders to be filed within 120 days from
+December 31, 2005. 
+The
+information required by this Item concerning securities authorized for issuance
+under equity compensation plans is incorporated by reference to the information
+provided under the caption “Equity Compensation Plans” in Part II, Item 5 -
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
+Purchases of Equity Securities, included in this Form 10-K. 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND
+RELATED
+TRANSACTIONS 
+The
+information required by this Item is incorporated by reference to the
+information provided under the caption “Certain Relationships and Related
+Transactions” in St. Mary’s definitive proxy statement for the 2006 annual
+meeting of stockholders to be filed within 120 days from
+December 31, 2005. 
+ITEM 14. 
+PRINCIPAL ACCOUNTING FEES
+AND
+SERVICES 
+The
+information required by this Item is incorporated by reference to the
+information provided under the caption “Independent Accountants” in
+St. Mary’s definitive proxy statement for the 2006 annual meeting of
+stockholders to be filed within 120 days from
+December 31, 2005. 
+64 
+PART
+IV 
+ITEM
+15. EXHIBITS
+AND FINANCIAL STATEMENT SCHEDULES 
+(a)(1)
+and (a)(2) Financial Statements and Financial Statement
+Schedules: 
+Audit
+Report of Independent Registered Public Accounting Firm 
+F-1 
+Consolidated
+Balance Sheets 
+F-2 
+Consolidated
+Statements of Operations 
+F-3 
+Consolidated
+Statements of Stockholders' Equity and Comprehensive Income
+F-4 
+Consolidated
+Statements of Cash Flows 
+F-5 
+Notes
+to Consolidated Financial Statements 
+F-7 
+All
+other
+schedules are omitted because the required information is not applicable or
+is
+not present in amounts sufficient to require submission of the schedule or
+because the information required is included in the Consolidated Financial
+Statements and Notes thereto. 
+(b)
+Exhibits. 
+The
+following exhibits are filed with or incorporated by reference into this report
+on Form 10-K: 
+Exhibit
+Number 
+Description 
+3.1
+Restated
+Certificate of Incorporation of St. Mary Land & Exploration Company as
+amended on May 25, 2005 (filed as Exhibit 3.1 to the registrant's
+Quarterly Report on Form 10-Q for the quarter ended June 30, 2005
+and
+incorporated herein by reference) 
+3.2
+Restated
+By-Laws of St. Mary Land & Exploration Company as amended on March 27,
+2003 (filed as Exhibit 3.2 to the registrant's Quarterly Report on
+Form
+10-Q for the quarter ended March 31, 2003 and incorporated herein
+by
+reference) 
+4.1
+St.
+Mary Land & Exploration Company Shareholder Rights Plan adopted on
+July 15, 1999 (filed as Exhibit 4.1 to the registrant's Quarterly
+Report
+on Form 10-Q/A for the quarter ended June 30, 1999 and incorporated
+herein
+by reference) 
+4.2
+First
+Amendment to Shareholders Rights Plan dated March 15, 2002 as adopted
+by
+the Board of Directors on July 19, 2001 (filed as Exhibit 4.2 to
+the
+registrant's Annual Report on Form 10-K for the year ended December
+31,
+2001 and incorporated herein by reference) 
+10.1 † 
+St.
+Mary Land & Exploration Company Stock Option Plan, As Amended on May
+22, 2003 (filed as Exhibit 99.1 to the registrant's Registration
+Statement
+on Form S-8 (Registration No. 333-106438) and incorporated herein
+by
+reference) 
+10.2†
+St.
+Mary Land & Exploration Company Incentive Stock Option Plan, As
+Amended on March 25, 1999, January 27, 2000, March 29, 2001, March
+27,
+2003 and May 22, 2003 (filed as Exhibit 99.2 to registrant's Registration
+Statement on Form S-8 (Registration No. 333-106438) and incorporated
+herein by reference) 
+10.3†
+Cash
+Bonus Plan (filed as Exhibit 10.5 to the registrant's Registration
+Statement on Form S-1 (Registration No. 33-53512) and incorporated
+herein
+by reference) 
+10.4†
+Summary
+Plan Description/Pension Plan dated December 30, 1994 (filed as Exhibit
+10.35 to the registrant's Annual Report on Form 10-K for the year
+ended
+December 31, 1994 and incorporated herein by reference) 
+10.5†
+Non-qualified
+Unfunded Supplemental Retirement Plan, as amended (filed as Exhibit
+10.8
+to the registrant's Registration Statement on Form S-1 (Registration
+No.
+33-53512) and incorporated herein by reference) 
+10.6†
+St.
+Mary Land & Exploration Company Employee Stock Purchase Plan (filed as
+Exhibit 10.48 filed to the registrant's Annual Report on Form 10-K
+(for
+the year ended December 31, 1997 and incorporated herein by
+reference) 
+10.7†
+First
+Amendment to St. Mary Land & Exploration Company Employee Stock
+Purchase Plan dated February 27, 2001 (filed as Exhibit 10.1 to the
+registrant's Quarterly Report on Form 10-Q for the quarter ended
+June 30,
+2001 and incorporated herein by
+reference) 
+65 
+Exhibit
+Number 
+Description 
+10.8†
+Form
+of Change of Control Severance Agreements (filed as Exhibit 10.1
+to the
+registrant's Quarterly Report on Form 10-Q for the quarter ended
+September
+30, 2001 and incorporated herein by reference) 
+10.9†
+Employment
+Agreement between Registrant and Mark A. Hellerstein (filed as Exhibit
+10.15 to the registrant's Registration Statement on Form S-1 (Registration
+No. 33-53512) and incorporated herein by reference) 
+10.10
+St.
+Mary Land & Exploration Company 5.75% Senior Convertible Notes Due
+2002 Indenture dated March 13, 2002 (filed as Exhibit 10.26 to the
+registrant's Annual Report on Form 10-K for the year ended December
+31,
+2001 and incorporated herein by reference) 
+10.11
+Amendment
+to and Extension of Office Lease dated as of December 14, 2001 (filed
+as
+Exhibit 10.45 to the registrant's Annual Report on Form 10-K for
+the year
+ended December 31, 2003 and incorporated herein by
+reference) 
+10.12†
+St.
+Mary Land & Exploration Company Non-Employee Director Stock
+Compensation Plan as adopted on March 27, 2003 (filed as Exhibit
+10.1 to
+the registrant's Quarterly Report on Form 10-Q for the quarter ended
+June
+30, 2003 and incorporated herein by reference) 
+10.13
+First
+Amendment to Credit Agreement dated January 27, 2003 among St. Mary
+Land
+& Exploration Company, Wachovia Bank, National Association as Issuing
+Bank and Administrative Agent, and the Lenders party thereto (filed
+as
+Exhibit 10.41 to the registrant's Annual Report on Form 10-K for
+the year
+ended December 31, 2003 and incorporated herein by
+reference) 
+10.14†
+Net
+Profits Interest Bonus Plan, As Amended on February 3, 2004 (filed
+as
+Exhibit 10.42 to the registrant's Annual Report on Form 10-K for
+the year
+ended December 31, 2003 and incorporated herein by
+reference) 
+10.15†
+St.
+Mary Land & Exploration Company Restricted Stock Plan as adopted on
+April 18, 2004 (filed as Exhibit 10.1 to the registrant's Quarterly
+Report
+on Form 10-Q for the quarter ended June 30, 2004 and incorporated
+herein
+by reference) 
+10.16
+Second
+Amendment to Credit Agreement dated September 20, 2004 among St.
+Mary Land
+& Exploration Company, Wachovia Bank, National Association as Issuing
+Bank and Administrative Agent, and the Lenders party thereto (filed
+as
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q for
+the
+quarter ended September 30, 2004 and incorporated herein by
+reference) 
+10.17
+Third
+Amendment to Credit Agreement dated October 20, 2004 among St. Mary
+Land
+& Exploration Company, Wachovia Bank, National Association as Issuing
+Bank and Administrative Agent, and the Lenders party thereto (filed
+as
+Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q for
+the
+quarter ended September 30, 2004 and incorporated herein by
+reference) 
+10.18†
+Form
+of Restricted Stock Unit Award Memorandum under the St. Mary Land
+&
+Exploration Company Restricted Stock Plan (filed as Exhibit 10.3
+to the
+registrant's Quarterly Report on Form 10-Q for the quarter ended
+September
+30, 2004 and incorporated herein by reference) 
+10.19†
+Attachment
+A to Form of Change of Control Severance Agreement (filed as Exhibit
+10.47
+to the registrants Annual Report on Form 10-K for the year ended
+December
+31, 2004 and incorporated herein by reference) 
+10.20†
+Second
+Amendment to the St. Mary Land & Exploration Employee Stock Purchase
+Plan dated February 18, 2005 (filed as Exhibit 10.48 to the registrants
+Annual Report on Form 10-K for the year ended December 31, 2004 and
+incorporated herein by reference) 
+10.21
+Amended
+and Restated Credit Agreement dated as of April 7, 2005 among St.
+Mary
+Land & Exploration Company, Wachovia Bank, National Association, as
+Administrative Agent, and the Lenders party thereto (filed as Exhibit
+10.1
+to the registrant's Quarterly Report on Form 10-Q for the quarter
+ended
+March 31, 2005 and incorporated herein by reference) 
+10.22
+Guaranty
+Agreement by St. Mary Energy Company in favor of Wachovia Bank, National
+Association, as Administrative Agent, dated April 7, 2005 (filed
+as
+Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q for
+the
+quarter ended March 31, 2005 and incorporated herein by
+reference) 
+66 
+Exhibit
+Number 
+Description 
+10.23
+Guaranty
+Agreement by Nance Petroleum Corporation in favor of Wachovia Bank,
+National Association, as Administrative Agent, dated April 7, 2005
+(filed
+as Exhibit 10.3 to the registrant's Quarterly Report on Form 10-Q
+for the
+quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.24
+Guaranty
+Agreement by NPC Inc. in favor of Wachovia Bank, National Association,
+as
+Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.4
+to the
+registrant's Quarterly Report on Form 10-Q for the quarter ended
+March 31,
+2005 and incorporated herein by reference) 
+10.25
+Pledge
+and Security Agreement between St. Mary Land & Exploration Company and
+Wachovia Bank, National Association, as Administrative Agent, dated
+April
+7, 2005 (filed as Exhibit 10.5 to the registrant's Quarterly Report
+on
+Form 10-Q for the quarter ended March 31, 2005 and incorporated herein
+by
+reference) 
+10.26
+Pledge
+and Security Agreement between Nance Petroleum Corporation and Wachovia
+Bank, National Association, as Administrative Agent, dated April
+7, 2005
+(filed as Exhibit 10.6 to the registrant's Quarterly Report on Form
+10-Q
+for the quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.27
+First
+Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit
+Mortgage, Assignment, Security Agreement, Fixture Filing and Financing
+Statement for the benefit of Wachovia Bank, National Association,
+as
+Administrative Agent, dated effective as of April 7, 2005 (filed
+as
+Exhibit 10.7 to the registrant's Quarterly Report on Form 10-Q for
+the
+quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.28
+Deed
+of Trust - St. Mary Land & Exploration to Wachovia Bank, National
+Association, as Administrative Agent, dated effective as of April
+7, 2005
+(filed as Exhibit 10.8 to the registrant's Quarterly Report on Form
+10-Q
+for the quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.29† 
+Amendment
+to Form of Change of Control Severance Agreement (filed as Exhibit
+10.9 to
+the registrant's Quarterly Report on Form 10-Q for the quarter ended
+March
+31, 2005 and incorporated herein by reference) 
+10.30†
+Net
+Profits Interest Bonus Plan, As Amended on December 15, 2005 (filed
+as
+Exhibit 10.1 to the registrant's Current Report on Form 8-K filed
+on
+December 19, 2005 and incorporated herein by reference) 
+10.31†
+Amendment
+to Restricted Stock Plan, dated December 15, 2005 (filed as Exhibit
+10.2
+to the registrant's Current Report on Form 8-K filed on December
+19, 2005
+and incorporated herein by reference) 
+10.32†
+Amendment
+to Employment Agreement of Mark A. Hellerstein, dated December 16,
+2005
+(filed as Exhibit 10.3 to the registrant's Current Report on Form
+8-K
+filed on December 19, 2005 and incorporated herein by
+reference) 
+10.33
+Summary
+of Charitable Contributions in Honor of Thomas E. Congdon (filed
+as
+Exhibit 10.4 to the registrant's Current Report on Form 8-K filed
+on
+December 19, 2005 and incorporated herein by reference) 
+10.34†
+Summary
+of 2006 Base Salaries for Named Executive Officers (filed as Exhibit
+10.5
+to the registrant's Current Report on Form 8-K filed on December
+19, 2005
+and incorporated herein by reference) 
+10.35*† 
+Summary
+of Compensation Arrangements for Non-Employee Directors 
+12.1*
+Computation
+of Ratio of Earnings to Fixed Charges 
+14.1
+Code
+of Business Conduct and Ethics (filed as Exhibit 14.1 to the registrant's
+Annual Report on Form 10-k for the year ended December 31, 2003 and
+incorporated herein by reference) 
+21.1*
+Subsidiaries
+of Registrant 
+23.1*
+Consent
+of Deloitte & Touche LLP 
+23.2*
+Consent
+of Ryder Scott Company, L.P. 
+23.3*
+Consent
+of Netherland, Sewell & Associates, Inc. 
+24.1*
+Power
+of Attorney (included in signature page
+hereof) 
+67 
+Exhibit
+Number 
+Description 
+31.1*
+Certification
+of Chief Executive Officer pursuant to Section 302 of the Sarbanes
+- Oxley
+Act of 2002 
+31.2*
+Certification
+of Chief Financial Officer pursuant to Section 302 of the Sarbanes
+- Oxley
+Act of 2002 
+32.1*
+Certification
+pursuant to U.S.C. Section 1350 as adopted pursuant to Section 906
+of the
+Sarbanes - Oxley Act of 2002 
+* 
+Filed with
+this Form
+10-K. 
+† 
+Exhibit
+constitutes a management contract or compensatory plan or arrangement
+(c)
+Financial Statement Schedules. 
+See Item
+15(a) above. 
+68 
+REPORT
+OF
+INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To
+the
+Board of Directors and Stockholders of 
+St.
+Mary
+Land & Exploration Company and Subsidiaries 
+We
+have
+audited the accompanying consolidated balance sheets of St. Mary Land &
+Exploration Company and subsidiaries (the “Company”) as of December 31, 2005 and
+2004, and the related consolidated statements of operations, stockholders’
+equity and comprehensive income, and cash flows for each of the three years
+in
+the period ended December 31, 2005. These financial statements are the
+responsibility of the Company’s management. Our responsibility is to express an
+opinion on these financial statements based on our audits. 
+We
+conducted our audits in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). Those standards require that we
+plan
+and perform the audit to obtain reasonable assurance about whether the financial
+statements are free of material misstatement. An audit includes examining,
+on a
+test basis, evidence supporting the amounts and disclosures in the financial
+statements. An audit also includes assessing the accounting principles used
+and
+significant estimates made by management, as well as evaluating the overall
+financial statement presentation. We believe that our audits provide a
+reasonable basis for our opinion. 
+In
+our
+opinion, such consolidated financial statements present fairly, in all material
+respects, the financial position of St. Mary Land & Exploration Company and
+subsidiaries as of December 31, 2005 and 2004, and the results of
+their operations and their cash flows for each of the three years in the period
+ended December 31, 2005, in conformity with accounting principles generally
+accepted in the United States of America. 
+As
+discussed in Note 9 to the consolidated financial statements, the Company
+changed its method of accounting for asset retirement obligations in 2003 with
+the implementation of Statement of Financial Accounting Standards No. 143
+“Accounting for Asset Retirement Obligations”. 
+We
+have
+also audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), the effectiveness of the Company’s internal
+control over financial reporting as of December 31, 2005, based on the criteria
+established in Internal Control—Integrated Framework issued by the
+Committee of Sponsoring Organizations of the Treadway Commission, and our report
+dated February 23, 2006, expressed an unqualified opinion on management’s
+assessment of the effectiveness of the Company’s internal control over financial
+reporting and an unqualified opinion on the effectiveness of the Company’s
+internal control over financial reporting. 
+/S/
+DELOITTE & TOUCHE LLP 
+Denver,
+Colorado 
+February
+23, 2006 
+F-1 
+PART
+I. FINANCIAL INFORMATION 
+ITEM
+1. FINANCIAL STATEMENTS 
+ST.
+MARY LAND & EXPLORATION COMPANY AND
+SUBSIDIARIES 
+CONSOLIDATED
+BALANCE SHEETS 
+(In
+thousands, except share amounts) 
+December
+31, 
+December
+31, 
+ASSETS 
+2005 
+2004 
+Current
+assets: 
+Cash
+and cash equivalents 
+$ 
+14,925 
+$ 
+6,418 
+Short-term
+investments 
+1,475
+1,412
+Accounts
+receivable 
+165,197
+104,964
+Prepaid
+expenses and other 
+7,283
+5,863
+Deferred
+income taxes 
+8,252
+-
+Accrued
+derivative asset 
+6,799
+8,270
+Total
+current assets 
+203,931
+126,927
+Property
+and equipment (successful efforts method), at cost: 
+Proved
+oil and gas properties 
+1,441,959
+1,124,810
+Less
+- accumulated depletion, depreciation and amortization 
+(497,621 
+) 
+(399,013 
+) 
+Unproved
+oil and gas properties, net of impairment allowance 
+of
+$9,862 in 2005 and $9,867 in 2004 
+44,383
+41,969
+Wells
+in progress 
+55,505
+35,515
+Other
+property and equipment, net of accumulated depreciation 
+of
+$8,046 in 2005 and $6,459 in 2004 
+5,340
+5,244
+1,049,566
+808,525
+Noncurrent
+assets: 
+Goodwill
+9,452
+-
+Accrued
+derivative asset 
+575
+115
+Other
+noncurrent assets 
+5,223
+9,893
+Total
+noncurrent assets 
+15,250
+10,008
+Total
+Assets 
+$ 
+1,268,747 
+$ 
+945,460 
+LIABILITIES
+AND STOCKHOLDERS' EQUITY 
+Current
+liabilities: 
+Accounts
+payable and accrued expenses 
+$ 
+164,957 
+$ 
+110,117 
+Accrued
+derivative liability 
+34,037
+2,502
+Deferred
+income taxes 
+-
+2,273
+Total
+current liabilities 
+198,994
+114,892
+Noncurrent
+liabilities: 
+Long-term
+credit facility 
+-
+37,000
+Convertible
+notes 
+99,885
+99,791
+Asset
+retirement obligation 
+66,078
+40,911
+Net
+Profits Plan liability 
+136,824
+30,561
+Deferred
+income taxes 
+128,296
+129,830
+Accrued
+derivative liability 
+64,137
+2,970
+Other
+noncurrent liabilities 
+5,213
+5,050
+Total
+noncurrent liabilities 
+500,433
+346,113
+Commitments
+and Contingencies (Note 6) 
+Stockholders'
+equity: 
+Common
+stock, $0.01 par value: authorized - 200,000,000 shares; 
+issued:
+57,011,740 shares in 2005 and 57,458,246 shares in 2004; 
+outstanding,
+net of treasury shares: 56,761,740 shares in 2005 
+and
+56,958,246 shares in 2004 
+570
+574
+Additional
+paid-in capital 
+123,278
+127,374
+Treasury
+stock, at cost: 250,000 shares in 2005 and 500,000 shares in
+2004 
+(5,148 
+) 
+(5,295 
+) 
+Deferred
+stock-based compensation 
+(5,593 
+) 
+(5,039 
+) 
+Retained
+earnings 
+510,812
+364,567
+Accumulated
+other comprehensive income (loss) 
+(54,599 
+) 
+2,274
+Total
+stockholders' equity 
+569,320
+484,455
+Total
+Liabilities and Stockholders' Equity 
+$ 
+1,268,747 
+$ 
+945,460 
+The
+accompanying notes are an integral part of these consolidated financial
+statements. 
+F-2 
+ST.
+MARY LAND & EXPLORATION COMPANY AND
+SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF OPERATIONS 
+(In
+thousands, except per share amounts) 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+Operating
+revenues: 
+Oil
+and gas production revenue 
+$ 
+733,544 
+$ 
+463,617 
+$ 
+387,553 
+Oil
+and gas hedge loss 
+(22,539 
+) 
+(50,299 
+) 
+(22,439 
+) 
+Marketed
+gas revenue 
+25,269
+15,551
+13,438
+Gain
+on sale of proved properties 
+222
+1,803
+7,278
+Other
+revenue 
+3,094
+2,427
+7,878
+Total
+operating revenues 
+739,590
+433,099
+393,708
+Operating
+expenses: 
+Oil
+and gas production expense 
+142,873
+95,518
+88,509
+Depletion,
+depreciation, amortization 
+and
+abandonment liability accretion 
+132,758
+92,223
+81,960
+Exploration
+44,931
+28,560
+25,318
+Impairment
+of proved properties 
+-
+494
+185
+Abandonment
+and impairment of unproved properties 
+5,780
+1,420
+3,796
+General
+and administrative 
+32,756
+22,004
+21,197
+Change
+in Net Profits Plan liability 
+106,263
+24,398
+5,317
+Marketed
+gas system operating expense 
+24,164
+14,230
+12,229
+Unrealized
+derivative loss 
+1,615
+260
+310
+Other
+expense 
+2,456
+2,077
+1,576
+Total
+operating expenses 
+493,596
+281,184
+240,397
+Income
+from operations 
+245,994
+151,915
+153,311
+Nonoperating
+income (expense): 
+Interest
+income 
+456
+557
+717
+Interest
+expense 
+(8,213 
+) 
+(6,244 
+) 
+(7,958 
+) 
+Income
+before income taxes and cumulative effect 
+of
+change in accounting principle 
+238,237
+146,228
+146,070
+Income
+tax expense 
+(86,301 
+) 
+(53,749 
+) 
+(55,930 
+) 
+Income
+before cumulative effect of change in accounting principle 
+151,936
+92,479
+90,140
+Cumulative
+effect of change in accounting principle, net of income
+tax 
+-
+-
+5,435
+Net
+income 
+$ 
+151,936 
+$ 
+92,479 
+$ 
+95,575 
+Basic
+weighted-average common shares outstanding 
+56,907
+57,702
+62,467
+Diluted
+weighted-average common shares outstanding 
+66,894
+66,894
+71,069
+Basic
+earnings per common share: 
+Income
+before cumulative effect of change in accounting principle 
+$ 
+2.67 
+$ 
+1.60 
+$ 
+1.44 
+Cumulative
+effect of change in accounting 
+principle,
+net of income tax 
+-
+-
+0.09
+Basic
+net income per common share 
+$ 
+2.67 
+$ 
+1.60 
+$ 
+1.53 
+Diluted
+earnings per common share: 
+Income
+before cumulative effect of change in accounting principle 
+$ 
+2.33 
+$ 
+1.44 
+$ 
+1.32 
+Cumulative
+effect of change in accounting 
+principle,
+net of income tax 
+-
+-
+.08
+Diluted
+net income per common share 
+$ 
+2.33 
+$ 
+1.44 
+$ 
+1.40 
+The
+accompanying notes are an integral part of these
+consolidated financial statements. 
+F-3 
+ST.
+MARY LAND & EXPLORATION COMPANY AND
+SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE
+INCOME 
+(In
+thousands, except share
+amounts) 
+Accumulated 
+Common
+Stock 
+Additional 
+Paid-in 
+Treasury
+Stock 
+Deferred
+Stock-Based 
+Retained 
+Other 
+Comprehensive 
+Total
+Stockholders' 
+Shares 
+Amount 
+Capital 
+Shares 
+Amount 
+Compensation 
+Earnings 
+Income
+(Loss) 
+Equity
+Balances,
+December 31, 2002 
+57,966,220
+$ 
+580 
+$ 
+140,398 
+(2,019,800 
+) 
+$ 
+(16,210 
+) 
+$ 
+- 
+$ 
+182,512 
+$ 
+(7,767 
+) 
+$ 
+299,513 
+Comprehensive
+income, net of tax: 
+Net
+income 
+-
+-
+-
+-
+-
+-
+95,575
+-
+95,575
+Unrealized
+net gain on marketable equity securities available for
+sale 
+-
+-
+-
+-
+-
+-
+-
+716
+716
+Change
+in derivative instrument fair value 
+-
+-
+-
+-
+-
+-
+-
+(21,873 
+) 
+(21,873 
+) 
+Reclassification
+to earnings 
+-
+-
+-
+-
+-
+-
+-
+13,846
+13,846
+Minimum
+pension liability adjustment 
+-
+-
+-
+-
+-
+-
+-
+197
+197
+Total
+comprehensive income 
+88,461
+Cash
+dividends declared, $ 0.05 per share 
+-
+-
+-
+-
+-
+-
+(3,150 
+) 
+-
+(3,150 
+) 
+Issuance
+of common stock under Employee Stock Purchase Plan 
+33,988
+-
+375
+-
+-
+-
+-
+-
+375
+Value
+of option right granted to Flying J 
+-
+-
+995
+-
+-
+-
+-
+-
+995
+Sale
+of common stock, including income tax
+benefit of stock option exercises 
+490,038
+4
+4,302
+-
+-
+-
+-
+-
+4,306
+Directors'
+stock compensation 
+-
+-
+-
+14,400
+153
+-
+-
+-
+153
+Balances,
+December 31, 2003 
+58,490,246
+$ 
+584 
+$ 
+146,070 
+(2,005,400 
+) 
+$ 
+(16,057 
+) 
+$ 
+- 
+$ 
+274,937 
+$ 
+(14,881 
+) 
+$ 
+390,653 
+Comprehensive
+income, net of tax: 
+Net
+income 
+-
+-
+-
+-
+-
+-
+92,479
+-
+92,479
+Change
+in derivative instrument fair value 
+-
+-
+-
+-
+-
+-
+-
+(14,795 
+) 
+(14,795 
+) 
+Reclassification
+to earnings 
+-
+-
+-
+-
+-
+-
+-
+31,849
+31,849
+Minimum
+pension liability adjustment 
+-
+-
+-
+-
+-
+-
+-
+101
+101
+Total
+comprehensive income 
+109,634
+Cash
+dividends declared, $ 0.05 per share 
+-
+-
+-
+-
+-
+-
+(2,849 
+) 
+-
+(2,849 
+) 
+Repurchase
+of common stock from Flying J 
+-
+-
+(19,406 
+) 
+-
+-
+-
+-
+-
+(19,406 
+) 
+Treasury
+stock purchases 
+-
+-
+-
+(978,600 
+) 
+(16,336 
+) 
+-
+-
+-
+(16,336 
+) 
+Retirement
+of treasury stock 
+(2,458,800 
+) 
+(24 
+) 
+(26,725 
+) 
+2,458,800
+26,749
+-
+-
+-
+-
+Issuance
+of common stock under Employee Stock Purchase Plan 
+27,748
+-
+375
+-
+-
+-
+-
+-
+375
+Sale
+of common stock, including income tax benefit of stock option
+exercises 
+1,399,052
+14
+17,832
+-
+-
+-
+-
+-
+17,846
+Deferred
+compensation related to issued restricted stock
+unit awards, net of forfeitures 
+-
+-
+8,122
+-
+-
+(8,122 
+) 
+-
+-
+-
+Accrued
+stock-based compensation 
+-
+-
+1,106
+-
+-
+-
+-
+-
+1,106
+Directors'
+stock compensation 
+-
+-
+-
+25,200
+349
+-
+-
+-
+349
+Amortization
+of deferred stock-based compensation 
+-
+-
+-
+-
+-
+3,083
+-
+-
+3,083
+Balances,
+December 31, 2004 
+57,458,246
+$ 
+574 
+$ 
+127,374 
+(500,000 
+) 
+$ 
+(5,295 
+) 
+$ 
+(5,039 
+) 
+$ 
+364,567 
+$ 
+2,274 
+$ 
+484,455 
+Comprehensive
+income, net of tax: 
+Net
+income 
+-
+-
+-
+-
+-
+-
+151,936
+-
+151,936
+Change
+in derivative instrument fair value 
+-
+-
+-
+-
+-
+-
+-
+(71,522 
+) 
+(71,522 
+) 
+Reclassification
+to earnings 
+-
+-
+-
+-
+-
+-
+-
+14,366
+14,366
+Minimum
+pension liability adjustment 
+-
+-
+-
+-
+-
+-
+-
+283
+283
+Total
+comprehensive income 
+95,063
+Cash
+dividends declared, $ 0.10 per share 
+-
+-
+-
+-
+-
+-
+(5,691 
+) 
+-
+(5,691 
+) 
+Treasury
+stock purchases 
+-
+-
+-
+(1,175,282 
+) 
+(28,902 
+) 
+-
+-
+-
+(28,902 
+) 
+Retirement
+of treasury stock 
+(1,411,356 
+) 
+(14 
+) 
+(28,729 
+) 
+1,411,356
+28,743
+-
+-
+-
+-
+Issuance
+of common stock under Employee Stock
+Purchase Plan 
+28,447
+-
+601
+-
+-
+-
+-
+-
+601
+Sale
+of common stock, including income tax
+benefit of stock option exercises 
+936,403
+10
+16,619
+-
+-
+-
+-
+-
+16,629
+Deferred
+compensation related to issued restricted stock
+unit awards, net of forfeitures 
+-
+-
+3,404
+-
+-
+(3,404 
+) 
+-
+-
+-
+Accrued
+stock-based compensation 
+-
+-
+4,009
+-
+-
+-
+-
+-
+4,009
+Directors'
+stock compensation 
+-
+-
+-
+13,926
+306
+(306 
+) 
+-
+-
+-
+Amortization
+of deferred stock-based compensation 
+-
+-
+-
+-
+-
+3,156
+-
+-
+3,156
+Balances,
+December 31, 2005 
+57,011,740
+$ 
+570 
+$ 
+123,278 
+(250,000 
+) 
+$ 
+(5,148 
+) 
+$ 
+(5,593 
+) 
+$ 
+510,812 
+$ 
+(54,599 
+) 
+$ 
+569,320 
+The
+accompanying notes are an integral part of these
+consolidated financial statements. 
+F-4 
+ST.
+MARY LAND & EXPLORATION COMPANY AND
+SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF CASH FLOWS 
+(In
+thousands) 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+Reconciliation
+of net income to net cash provided 
+by
+operating activities: 
+Net
+income 
+$ 
+151,936 
+$ 
+92,479 
+$ 
+95,575 
+Adjustments
+to reconcile net income to net cash 
+provided
+by operating activities: 
+Gain
+on sale of proved properties 
+(222 
+) 
+(1,803 
+) 
+(7,278 
+) 
+Depletion,
+depreciation, amortization 
+and
+abandonment liability accretion 
+132,758
+92,223
+81,960
+Exploratory
+dry hole expense 
+8,104
+4,162
+8,482
+Impairment
+of proved properties 
+-
+494
+185
+Abandonment
+and impairment of unproved properties 
+5,780
+1,420
+3,796
+Unrealized
+derivative loss 
+1,615
+260
+310
+Change
+in Net Profits Plan liability 
+106,263
+24,398
+5,317
+Deferred
+and accrued stock-based compensation 
+7,165
+4,189
+-
+Income
+tax benefit from the exercise of stock options 
+6,037
+3,816
+1,151
+Deferred
+income taxes 
+5,547
+31,217
+23,692
+Other
+281
+(1,948 
+) 
+2,088
+Cumulative
+effect of change in accounting principle, net of tax 
+-
+-
+(5,435 
+) 
+Changes
+in current assets and liabilities, net of acquisitions: 
+Accounts
+receivable 
+(57,113 
+) 
+(39,880 
+) 
+(29,685 
+) 
+Prepaid
+expenses and other 
+(1,210 
+) 
+157
+490
+Accounts
+payable and accrued expenses 
+42,438
+25,978
+23,671
+Net
+cash provided by operating activities 
+409,379
+237,162
+204,319
+Cash
+flows from investing activities: 
+Proceeds
+from sale of oil and gas properties 
+1,213
+2,829
+23,497
+Capital
+expenditures 
+(270,881 
+) 
+(199,385 
+) 
+(123,823 
+) 
+Acquisition
+of oil and gas properties, including related 
+$71,594
+loan to Flying J in 2003 
+(73,905 
+) 
+(68,805 
+) 
+(76,413 
+) 
+Deposits
+to short-term investments available-for-sale 
+(1,502 
+) 
+(1,470 
+) 
+(12,529 
+) 
+Receipts
+from short-term investments available-for-sale 
+1,427
+12,500
+2,450
+Receipts
+from restricted cash 
+-
+10,353
+11,500
+Deposits
+to restricted cash 
+-
+-
+(21,853 
+) 
+Other
+3,869
+(3,028 
+) 
+232
+Net
+cash used in investing activities 
+(339,779 
+) 
+(247,006 
+) 
+(196,939 
+) 
+Cash
+flows from financing activities: 
+Proceeds
+from credit facility 
+284,090
+181,500
+142,020
+Repayment
+of credit facility 
+(321,090 
+) 
+(155,500 
+) 
+(145,020 
+) 
+Proceeds
+from sale of common stock 
+11,193
+14,030
+3,530
+Repurchase
+of common stock 
+(28,902 
+) 
+(35,743 
+) 
+-
+Dividends
+paid 
+(5,691 
+) 
+(2,849 
+) 
+(3,150 
+) 
+Other
+(693 
+) 
+(3 
+) 
+(1,087 
+) 
+Net
+cash provided by (used in) financing activities 
+(61,093 
+) 
+1,435
+(3,707 
+) 
+Net
+change in cash and cash equivalents 
+8,507
+(8,409 
+) 
+3,673
+Cash
+and cash equivalents at beginning of period 
+6,418
+14,827
+11,154
+Cash
+and cash equivalents at end of period 
+$ 
+14,925 
+$ 
+6,418 
+$ 
+14,827 
+The
+accompanying notes are an integral part of these
+consolidated financial statements. 
+F-5 
+ST.
+MARY LAND & EXPLORATION COMPANY AND
+SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF CASH FLOWS (Continued) 
+Supplemental
+schedule of additional cash flow information and noncash investing
+and
+financing activities: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(in
+thousands) 
+Cash
+paid for interest, net of capitalized interest 
+$ 
+8,458 
+$ 
+6,887 
+$ 
+7,555 
+Cash
+paid for income taxes 
+$ 
+65,752 
+$ 
+14,787 
+$ 
+28,858 
+Included
+in the accounts payable and accrued expenses account balances as
+of
+December 31, 2005 and
+2004 are $51.0 million and $39.2 million, respectively, of additions
+to
+oil and gas properties. These
+oil and gas property additions are reflected in cash used in investing
+activities in the periods
+that the payables are settled. 
+In
+March 2005 and June 2004 the Company issued 194,508 and 465,722
+restricted
+stock units, respectively, pursuant
+to the Company's restricted stock plan. The total value of the
+ssuances
+were $4.9 million and $8.3
+million, respectively. 
+In
+May 2005, May 2004, January 2004, and January 2003 the Company
+issued
+13,926, 16,800, 8,400 and 14,400 shares,
+respectively, of common stock from treasury to its non-employee
+directors.
+The Company recorded compensation
+expense related to the issuances of $179,000 and $349,000 and $153,000
+for
+the years ended December
+31, 2005, 2004 and 2003
+respectively. 
+In
+August 2004 the Company closed a transaction whereby it exchanged
+oil and
+gas properties valued at $1.4 million
+together with $769,000 of cash for oil and gas properties valued
+at $2.2
+million. 
+In
+January 2003 the Company issued 6,761,636 restricted shares of
+common
+stock to Flying J Oil & Gas Inc. and Big
+West Oil & Gas Inc. (collectively, "Flying J") and entered into a put
+and call option agreement, valued at $995,000
+for financial reporting purposes, with Flying J with respect to
+those
+shares in connection with the acquisition
+of oil and gas properties and related assets and liabilities.
+The
+accompanying notes are an integral part of these
+consolidated financial statements. 
+F-6 
+ST. MARY
+LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER
+31, 2005 
+Note
+1 - Summary of Significant Accounting Policies 
+Description
+of Operations 
+St. Mary
+Land & Exploration Company (“St. Mary” or the "Company") is an
+independent energy company engaged in the exploration, exploitation,
+development, acquisition and production of natural gas and crude oil.
+The
+Company’s operations are conducted entirely in the Continental United States and
+the Gulf of Mexico. 
+Basis
+of Presentation 
+The
+consolidated financial statements include the accounts of the Company and its
+wholly owned subsidiaries. Subsidiaries that are not wholly owned are accounted
+for using full consolidation with minority interest or by the equity or cost
+method as appropriate. Equity method investments are included in other
+noncurrent assets, and minority interest is included in other noncurrent
+liabilities in the accompanying consolidated balance sheets. All significant
+intercompany accounts and transactions have been eliminated. 
+Common
+stock and additional paid-in capital amounts have been reclassified for all
+periods presented to reflect a stock dividend distributed in March
+2005. 
+Use
+of Estimates in the Preparation of Financial Statements 
+The
+preparation of financial statements in conformity with accounting principles
+generally accepted in the United States requires management to make estimates
+and assumptions that affect the reported amounts of oil and gas reserves, assets
+and liabilities and disclosure of contingent assets and liabilities at the
+date
+of the financial statements and the reported amounts of revenues and expenses
+during the reporting period. Actual results could differ from those estimates.
+Estimates of oil and gas reserve quantities provide the basis for calculations
+of depletion, depreciation, and amortization (“DD&A”), impairment, goodwill,
+and the Net Profits Plan liability, each of which represents a significant
+component of the consolidated financial statements. 
+Cash
+and Cash Equivalents 
+The
+Company considers all liquid investments purchased with an initial maturity
+of
+three months or less to be cash equivalents. The
+carrying value of cash and cash equivalents approximates fair value due to
+the
+short-term nature of these instruments. 
+Short-term
+Investments 
+The
+Company’s short-term investments consists of investment-grade marketable debt,
+which is classified as held-to-maturity or available-for-sale. Securities
+categorized as held-to-maturity are stated at amortized cost whereas
+available-for-sale securities are marked-to-market. As of December 31, 2005
+and
+2004, the Company held $1.5 million and $1.4 million, respectively, of
+short-term investments. 
+Concentration
+of Credit Risk 
+Substantially
+all of the Company's receivables are within the oil and gas industry, primarily
+from purchasers of oil and gas and from joint interest owners. Although
+diversified among many companies, collectability is dependent upon the financial
+wherewithal of each individual company as well as the general economic
+conditions of the industry. The receivables are not collateralized. To date
+the
+Company has had minimal bad debts. 
+F-7 
+The
+Company has accounts with separate banks in Denver, Colorado; Shreveport,
+Louisiana; Tulsa, Oklahoma; Houston, Texas; and Billings, Montana. At December
+31, 2005, 2004 and 2003, the Company had $36.8 million, $22.2 million,
+and $23.5 million respectively, invested in money market funds, corporate
+commercial paper, repurchase agreements and U.S. Treasury obligations. The
+difference between the investment amount and the cash and cash equivalents
+amount on the consolidated balance sheets, represents uncleared disbursements.
+The Company’s policy is to invest in highly rated instruments and to limit the
+amount of credit exposure at each individual institution. 
+The
+Company currently uses ten separate counterparties for its oil and gas commodity
+and interest rate derivatives. The counterparties to the Company’s derivative
+instruments are all highly rated entities. 
+Oil
+and Gas Producing Activities 
+The
+Company follows the successful efforts method of accounting for its oil and
+gas
+properties. Under this method of accounting, all property acquisition costs
+and
+costs of exploratory and development wells are capitalized when incurred,
+pending determination of whether the well has found proved reserves. If an
+exploratory well does not find proved reserves, the costs of drilling the well
+are charged to expense. Exploratory dry hole costs are included in cash flows
+from investing activities as part of capital expenditures within the
+consolidated statements of cash flows. The costs of development wells are
+capitalized whether productive or nonproductive. 
+Geological
+and geophysical costs and the costs of carrying and retaining unproved
+properties are expensed as incurred. DD&A of capitalized costs of proved oil
+and gas properties is provided on a field-by-field basis using the units of
+production method based upon proved reserves. The computation of DD&A takes
+into consideration restoration, dismantlement and abandonment costs and the
+anticipated proceeds from equipment salvage. As
+of
+December 31, 2005, the Company’s capitalized proved oil and gas properties
+included $76.1 million of estimated salvage value, which is excluded from
+the depletable property costs when calculating DD&A. 
+The
+Company reviews its long-lived assets for impairments when events or changes
+in
+circumstances indicate that an impairment may have occurred. The impairment
+test
+for proved properties compares the expected undiscounted future net revenues
+on
+a field-by-field
+basis
+with the related net capitalized costs, including costs associated with asset
+retirement obligations, at the end of each period. Expected future cash flows
+are calculated on all proved reserves using a discount rate and price forecasts
+selected by the Company’s management. The discount rate is a rate that
+management believes is representative of current market conditions. The price
+forecast is based on NYMEX strip pricing for the first three years and is then
+escalated to and capped at specified maximum prices. Operating costs are also
+adjusted as deemed appropriate for these estimates. When the net capitalized
+costs exceed the undiscounted future net revenues of a field, the cost of the
+field is reduced to fair value, which is determined using discounted future
+net
+revenues. An impairment allowance is provided on unproved property when the
+Company determines the property will not be developed or the carrying value
+is
+not realizable. 
+Sales
+of Proved and Unproved Properties 
+The
+sale
+of a partial interest in a proved property is accounted for as normal
+retirement, and no gain or loss is recognized as long as this treatment does
+not
+significantly affect the units-of-production depletion rate. A gain or loss
+is
+recognized for all other sales of producing properties and is included in the
+results of operations. 
+The
+sale
+of a partial interest in an unproved property is accounted for as a recovery
+of
+cost when substantial uncertainty exists as to recovery of the cost applicable
+to the interest retained. A gain on the sale is recognized to the extent the
+sales price exceeds the carrying amount of the unproved property. A gain or
+loss
+is recognized for all other sales of nonproducing properties and is included
+in
+the results of operations. 
+Other
+Property and Equipment 
+Other
+property and equipment such as office furniture and equipment, automobiles
+and
+computer hardware and software are recorded at cost. Costs of renewals and
+improvements that substantially extend the useful lives of the assets are
+capitalized. Maintenance and repair costs are expensed when incurred.
+Depreciation is provided using the straight-line method over the estimated
+useful lives of the assets from three to 15 years. When other property and
+equipment is sold or retired, the capitalized costs and related accumulated
+depreciation are removed from the accounts. 
+F-8 
+Gas
+Balancing 
+The
+Company uses the sales method of accounting for our gas revenue whereby we
+recognize sales revenue on all gas sold to our purchasers, regardless of whether
+the sales are proportionate to our ownership in the property. An asset or a
+liability is recognized to the extent that we have an imbalance in excess of
+the
+remaining gas reserves on the underlying properties. The Company’s gas imbalance
+position at December 31, 2005 and 2004 resulted in the recording of $1.6 million
+and $1.5 million, respectively, to receivables, and $869,000 and $726,000,
+respectively, to payables. 
+Derivative Financial
+Instruments 
+The
+Company seeks to protect its rate of return on acquisitions of producing
+properties and other production by hedging cash flows. The Company intends
+for
+derivative instruments used for this purpose to be designated as, and to qualify
+as cash flow hedging instruments under SFAS No. 133, “Accounting for Derivative
+Instruments and Hedging Activities,” and related pronouncements. The Company
+seeks to minimize basis risk and indexes the majority of its oil hedges to
+NYMEX
+prices and the majority of its gas hedges to various regional index prices
+associated with pipelines in proximity to the Company's areas of gas production.
+For additional discussion of derivatives, please see Note
+10 -
+Derivative Financial Instruments. 
+Fair
+Value of Financial Instruments 
+The
+Company’s financial instruments including cash and cash equivalents, accounts
+receivable and accounts payable are carried at cost, which approximates fair
+value due to the short-term maturity of these instruments. The recorded value
+of
+the Company’s credit facility approximates its fair value as it bears interest
+at a floating rate; however, no amounts are outstanding as of December 31,
+2005.
+The Company’s interest rate swaps are recorded at fair value as discussed in
+Note 10 - Derivative Financial Instruments. The Company’s 5.75% Senior
+Convertible Notes due 2022 (the “Convertible Notes”) are recorded at cost, and
+the fair value is disclosed in Note 5 - Long-Term Debt. The Company has other
+financial instruments and investments in available-for-sale securities that
+are
+marked-to-market with changes in fair value being recorded in accumulated other
+comprehensive income. Since considerable judgment is required to develop
+estimates of fair value, the estimates provided are not necessarily indicative
+of the amounts the Company could realize upon the sale or refinancing of such
+instruments. 
+Net
+Profits Plan 
+The
+Company records the estimated liability of future payments for its Net Profits
+Plan. The estimated liability is calculated based on a
+number
+of assumptions, including estimates of oil and gas reserves, recurring and
+workover lease operating expense, production and ad valorem tax rates, present
+value discount factors and pricing assumptions. The estimates the Company uses
+in calculating the liability are modified from period-to-period based on the
+most current information attributable to the underlying assumptions. Changes
+in
+the estimated liability of future payments associated with the Net Profits
+Plan
+are recorded as increases or decreases to expense in the current period as
+a
+separate line item in the consolidated statements of operations. The estimated
+Net Profits Plan liability is recorded separately as a noncurrent liability
+in
+the accompanying consolidated balance sheets. 
+The
+amounts due and payable in each period under the Net Profits Plan as cash
+compensation related to periodic operations are recognized as compensation
+expense and are included within general and administrative expense and
+exploration expense. The corresponding current liability is included in accounts
+payable and accrued expenses in the accompanying consolidated balance sheets.
+This treatment provides for a consistent matching of cash expense with net
+cash
+flows from the oil and gas properties in each respective pool of the Net Profits
+Plan. For additional discussion, please see Note 7 - Compensation Plans under
+the heading Net
+Profits Plan. 
+F-9 
+Income
+Taxes 
+Deferred
+income taxes are provided on the difference between the tax basis of an asset
+or
+liability and its carrying amount in the financial statements. This difference
+will result in taxable income or deductions in future years when the reported
+amount of the asset or liability is recovered or settled,
+respectively. 
+Earnings
+per Share 
+Basic
+net
+income per common share of stock is calculated by dividing net income available
+to common stockholders by the weighted-average of common shares outstanding
+during each period. 
+Diluted
+net income per common share of stock is calculated by dividing adjusted net
+income by the weighted-average of common shares outstanding, including the
+effect of other dilutive securities. Adjusted net income is used for the
+if-converted method and is derived by adding interest expense paid on the
+Convertible Notes back to net income and then adjusting for nondiscretionary
+items that are based on income and that would have changed had the Convertible
+Notes been converted at the beginning of the period. The Company’s potentially
+dilutive securities consist of in-the-money outstanding options to purchase
+the
+Company’s common stock, shares into which the Convertible Notes may be converted
+and unvested restricted stock units. 
+The
+shares underlying the grants of restricted stock units are included
+in the diluted earnings per share calculation beginning with the grant date
+of
+units under the Restricted Stock Plan regardless of whether the shares are
+vested or unvested. Following the lapse of the restriction period, the shares
+underlying the units will be issued and therefore included in the issued and
+outstanding share count. 
+The
+treasury stock method 
+is used
+to measure the dilutive impact of stock options. The following table details
+the
+weighted-average dilutive and anti-dilutive securities related to stock options
+and RSUs for the periods presented: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+Dilutive
+2,293,768 
+1,499,288 
+910,110 
+Anti-dilutive 
+- 
+186 
+1,426,764 
+The
+dilutive effect of stock options and restricted stock units is considered in
+the
+detailed calculations below. There were no anti-dilutive securities related
+to
+restricted stock units for any periods presented. 
+Shares
+associated with the conversion feature of the Convertible Notes are accounted
+for using the if-converted method as described above. A total of 7,692,307
+potentially dilutive shares related to the Convertible Notes were included
+in
+the calculation of diluted net income per common share for the years ended
+December 31, 2005, 2004 and 2003. The Convertible Notes were issued in
+March 2002. 
+During
+the first quarter of 2003, the Company issued 6,761,636
+shares of common stock as part of an acquisition. In February 2004 the Company
+repurchased and retired these shares (see Note 11-Repurchase of Common Stock).
+These shares were considered outstanding from January 29, 2003, to February
+9,
+2004, for purposes of calculating basic and diluted net income per common share
+and were weighted accordingly in the calculation of common shares outstanding.
+F-10 
+The
+following table sets forth the calculation of basic and diluted earnings per
+share: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands, except per share amounts) 
+Income
+before cumulative effect of change in accounting principle 
+$ 
+151,936 
+$ 
+92,479 
+$ 
+90,140 
+Cumulative
+effect of change in accounting principle, net of
+income tax 
+- 
+- 
+5,435 
+Net
+income 
+151,936 
+92,479 
+95,575 
+Adjustments
+to net income for dilution: 
+Add:
+interest expense avoided if Convertible Notes are
+converted to equity 
+6,337 
+6,354 
+6,337 
+Less:
+other adjustments 
+(64 
+) 
+(64 
+) 
+(63 
+) 
+Less:
+income tax effect of dilutive items 
+(2,275 
+) 
+(2,312 
+) 
+(2,403 
+) 
+Net
+income adjusted for the effect of dilution 
+$ 
+155,934 
+$ 
+96,457 
+$ 
+99,446 
+Basic
+weighted-average common shares outstanding 
+56,907 
+57,702 
+62,467 
+Add:
+dilutive effect of stock options and RSUs 
+2,295 
+1,500 
+910 
+Add:
+dilutive effect of Convertible Notes using the if-converted
+method 
+7,692 
+7,692 
+7,692 
+Diluted
+weighted-average common shares outstanding 
+66,894 
+66,894 
+71,069 
+Basic
+earnings per common share: 
+Income
+before cumulative effect of change in accounting
+principle 
+$ 
+2.67 
+$ 
+1.60 
+$ 
+1.44 
+Cumulative
+effect of change in accounting principle, net of income
+tax 
+- 
+- 
+0.09 
+Total 
+$ 
+2.67 
+$ 
+1.60 
+$ 
+1.53 
+Diluted
+earnings per common share: 
+Income
+before cumulative effect of change in accounting
+principle 
+$ 
+2.33 
+$ 
+1.44 
+$ 
+1.32 
+Cumulative
+effect of change in accounting principle, net of income
+tax 
+- 
+- 
+0.08 
+Total 
+$ 
+2.33 
+$ 
+1.44 
+$ 
+1.40 
+Stock-Based
+Compensation 
+At
+December 31, 2005, the Company had stock-based employee compensation plans
+that
+included restricted stock units (“RSU s”)
+and
+stock options issued to employees and non-employee directors as more fully
+described in Note 7 - Compensation Plans. The Company has historically accounted
+for stock-based compensation using the intrinsic value recognition and
+measurement principles detailed in Accounting Principles Board Opinion No.
+25,
+“Accounting for Stock Issued to Employees” and related interpretations. No
+stock-based employee compensation expense relating to stock options has been
+reflected in the Company’s consolidated statements of operations for any period
+presented as all options granted under the plans had an exercise price equal
+to
+the market value of the underlying common stock on the date of grant. The
+Company currently uses the Black-Scholes option valuation model to calculate
+required disclosures under SFAS No. 123, “Accounting for Stock-Based
+Compensation.” As of January 1, 2006, the Company has adopted the provisions of
+SFAS No. 123(R), “Share-Based Payment.” This statement requires the Company to
+record expense associated with the fair value of stock-based compensation.
+As a
+result of the adoption of this statement, the Company expects to record
+compensation expense associated with unvested stock options totaling $2.2
+million in future periods under the modified-prospective adoption method. The
+Company has recorded expense of costs associated with the issuance of restricted
+stock units since the plan was adopted in 2004 and units were first granted.
+Going forward, this expense will decrease on a relative per share basis for
+all
+units that have already been issued, because the accounting standard requires
+cost recognition using fair value estimates of the restricted stock units,
+rather than intrinsic value used under APB 25. 
+F-11 
+The
+following table illustrates the pro forma effect on net income and earnings
+per
+share if the Company had applied the fair value recognition provisions of SFAS
+No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee
+compensation: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands, except per share amounts) 
+Net
+income 
+As
+reported: 
+$ 
+151,936 
+$ 
+92,479 
+$ 
+95,575 
+Add:
+stock-based employee compensation 
+expense
+included in reported net income, 
+net
+of related tax effects 
+4,453 
+2,650 
+- 
+Less:
+stock-based employee compensation 
+expense
+determined under fair value 
+method
+for all awards, net of 
+related
+income tax effects 
+(6,282 
+) 
+(5,839 
+) 
+(5,859 
+) 
+Pro
+forma 
+$ 
+150,107 
+$ 
+89,290 
+$ 
+89,716 
+Pro
+forma basic earnings per share 
+Income
+before cumulative effect of change in accounting principle
+$ 
+2.64 
+$ 
+1.54 
+$ 
+1.34 
+Cumulative
+effect of change in accounting principle, net of income
+tax 
+- 
+- 
+0.09 
+Total 
+$ 
+2.64 
+$ 
+1.54 
+$ 
+1.43 
+Pro
+forma diluted earnings per share 
+Income
+before cumulative effect of change in accounting principle
+$ 
+2.30 
+$ 
+1.39 
+$ 
+1.24 
+Cumulative
+effect of change in accounting principle, net of income
+tax 
+- 
+- 
+0.08 
+Total 
+$ 
+2.30 
+$ 
+1.39 
+$ 
+1.32 
+For
+purposes of pro forma disclosures, the estimated fair values of the options
+are
+amortized to expense over the options’ vesting periods. The effects of applying
+SFAS No. 123 in the pro forma disclosure are not necessarily indicative of
+actual future amounts. 
+Comprehensive
+Income 
+Comprehensive
+income consists of net income, unrealized gains and losses on marketable equity
+securities the effective portion of derivative instruments classified as cash
+flow hedges, and accrued pension benefit obligation in excess of plan assets.
+Comprehensive income is presented net of income taxes in the consolidated
+statements of stockholders’ equity and comprehensive income. 
+F-12 
+The
+balances of components comprising accumulated other comprehensive income and
+loss are presented in the following table: 
+Minimum 
+Other 
+Derivative 
+Pension 
+Comprehensive 
+Instruments 
+Liability 
+Income
+(Loss) 
+For
+the period ending December 31, 2004 
+Before
+tax amount 
+$ 
+27,401 
+$ 
+168 
+$ 
+27,569 
+Tax
+(expense) benefit 
+(10,347 
+) 
+(67 
+) 
+(10,414 
+) 
+After
+tax amount 
+$ 
+17,054 
+$ 
+101 
+$ 
+17,155 
+For
+the period ending December 31, 2005 
+Before
+tax amount 
+$ 
+(92,097 
+) 
+$ 
+455 
+$ 
+(91,642 
+) 
+Tax
+(expense) benefit 
+34,941 
+(172 
+) 
+34,769 
+After
+tax amount 
+$ 
+(57,156 
+) 
+$ 
+283 
+$ 
+(56,873 
+) 
+Major
+Customers 
+During
+2005 one customer individually accounted for 13 percent of the Company’s total
+oil and gas production revenue. During 2004 one customer individually accounted
+for 20 percent of the Company’s total oil and gas production revenue.
+During
+2003 three
+customers individually accounted for 14 percent, 13 percent and 11 percent
+of the Company’s total oil and gas production revenue. 
+Industry
+Segment and Geographic Information 
+The
+Company operates in one industry segment, which is the exploration, development,
+production and sale of natural gas and crude oil, and all of the Company’s
+operations are conducted in the Continental United States and the Gulf of
+Mexico. Consequently, the Company currently reports as a single industry
+segment. The activities of our gas marketing personnel directly support the
+underlying sale of oil and gas production and are not viewed by management
+as a
+discrete reporting segment. 
+Stock
+Dividend 
+In
+March
+2005 the Company’s Board of Directors approved a two-for-one stock split in the
+form of a stock dividend whereby one additional share of common stock was
+distributed for each common share outstanding. The stock dividend was
+distributed on March 31, 2005, to shareholders of record as of the close of
+business on March 21, 2005. All share and per share amounts for all
+prior periods presented herein have been reclassified to reflect this stock
+split. 
+Goodwill 
+Goodwill
+is measured as the excess of the acquisition costs over the sum of the amounts
+assigned to the identifiable assets acquired less liabilities assumed. Goodwill
+was recorded as a result of the acquisition of Agate Petroleum, Inc. in
+January 2005. Goodwill is reviewed for impairment annually or more
+frequently if impairment indicators arise. The goodwill review is conducted
+at
+the reporting unit level. Each reporting unit is defined as the oil and gas
+properties in a region. 
+Suspended
+Well Costs 
+In
+2005,
+the Company adopted FASB Staff Position No. FAS 19-1, “Accounting for Suspended
+Well Costs,” (“FSP FAS 19-1”). Upon adoption of the FSP FAS 19-1 the Company
+evaluated all existing capitalized exploratory well costs under the provisions
+of the FSP FAS 19-1. As a result, the Company determined that no suspended
+well
+costs should be impaired. 
+F-13 
+Off 
+-
+Balance Sheet 
+Arrangements 
+As
+part
+of its ongoing business, the Company has not participated in transactions that
+generate relationships with unconsolidated entities or financial partnerships,
+such as entities often referred to as structured finance or special purpose
+entities ("SPEs"), or SPEs which would have been established for the purpose
+of
+facilitating off-balance sheet arrangements or other contractually narrow or
+limited purposes. As of December 31, 2005, the Company has not
+been involved in any unconsolidated SPE transactions. 
+Note
+2 - Accounts Receivable and Accounts Payable and Accrued
+Expenses 
+Accounts
+receivable are comprised of the following: 
+As
+of December 31, 
+2005 
+2004 
+(In
+thousands) 
+Accrued
+oil and gas sales 
+$ 
+138,521 
+$ 
+79,107 
+Due
+from joint interest owners 
+21,696 
+20,587 
+Other 
+4,980 
+5,270 
+Total
+accounts receivable 
+$ 
+165,197 
+$ 
+104,964 
+Accounts
+payable and accrued expenses are comprised of the following: 
+As
+of December 31, 
+2005 
+2004 
+(In
+thousands) 
+Accrued
+drilling costs 
+$ 
+40,071 
+$ 
+33,998 
+Revenue
+payable 
+61,924 
+41,875 
+Accrued
+lease operating expense 
+9,738 
+13,066 
+Accrued
+taxes 
+6,202 
+800 
+Accrued
+interest 
+1,861 
+1,779 
+Joint
+owner advances 
+2,955 
+448 
+Accrued
+compensation 
+16,618 
+5,555 
+Trade
+payables 
+14,265 
+7,506 
+Oil
+hedge accrual 
+1,000 
+3,027 
+Other 
+10,323 
+2,063 
+Total
+account payable and accrued expenses 
+$ 
+164,957 
+$ 
+110,117 
+Note
+3 - Acquisitions and Divestitures 
+Agate
+Acquisition 
+On
+January 5, 2005, the Company acquired Agate Petroleum, Inc. (“Agate”)
+in exchange for $40.0 million in cash. The Company allocated the purchase
+price based on the estimated fair values of the acquired assets and liabilities.
+The Company finalized the purchase price allocation in 2005 as all amounts
+related to receivables and payables were determined with certainty. The final
+allocation did not result in any material adjustments to the preliminary
+purchase price. The Company acquired $4.6 million in cash from Agate, and
+the allocation of the purchase price resulted in recording $41.9 million to
+proved and unproved oil and gas properties, $1.1 million to net current
+liabilities, $9.5 million to goodwill, a deferred income tax liability of
+$13.5 million and a $1.4 million asset retirement obligation. The
+acquisition was accounted for using the purchase method of accounting and was
+funded with cash on hand and borrowings under the Company’s credit facility.
+Operating results from the acquired properties have been included in the
+consolidated statements of operations from the date of closing. 
+F-14 
+The
+goodwill and deferred income tax liability result from the use of present value
+considerations in the economic decision process that cannot be applied to the
+amounts recorded for deferred income taxes from acquiring oil and gas assets
+in
+a transaction in which the tax basis of the assets acquired is lower than the
+book basis fair value. The strategic benefits to the Company that support the
+recognition of goodwill in this acquisition include the mix of complementary
+high-quality assets in two of our existing core areas, lower-risk exploitation
+opportunities, and increased cash flow from operations available for investing
+activities. 
+Wold
+Acquisition 
+On
+August 1, 2005, the Company acquired oil and gas properties primarily
+in the Wind River and Powder River Basins of Wyoming from Wold Oil Properties,
+Inc. (“Wold”) for $37.1 million in cash. The Company allocated the purchase
+price based on the fair values of the acquired assets and liabilities. The
+allocation of the purchase price resulted in recording $43.9 million to
+proved and unproved oil and gas properties, a $7.0 million asset retirement
+obligation, and a net $232,000 to other assets. The $7.0 million asset
+retirement obligation includes approximately $4.7 million related to shut
+in and temporarily abandoned wells included in the acquisition. The Company
+finalized the allocation of the purchase price as all post-closing adjustments
+were determined with certainty prior to the end of 2005. The acquisition was
+accounted for using the purchase method of accounting and was funded with cash
+on hand and borrowings under the Company’s credit facility. Operating results
+from the acquired properties have been included in the consolidated statement
+of
+operations from the date of closing. 
+Goldmark
+Acquisition 
+On
+November 1, 2004, the Company acquired Goldmark Engineering Inc. along with
+proved and unproved oil and gas properties from various other parties
+(collectively, “Goldmark”) in exchange for $23.5 million of cash. The
+allocation of the purchase price was $29.6 million of proved reserves and
+unproved acreage, $1.2 million of cash, $753,000 of other assets, $446,000
+of payables, a $2.8 million asset retirement liability, and a
+$4.8 million deferred tax liability. 
+Border
+Acquisition 
+On
+December 15, 2004, the Company completed the acquisition of proved and unproved
+oil and gas properties from Border Company and other parties in exchange for
+$34.8 million in cash. The allocation of the purchase price was $35.5
+million of proved reserves and unproved acreage and a $649,000 asset retirement
+obligation. 
+Sales
+of Properties 
+Throughout
+2005, the Company sold interests in certain properties, received cash proceeds
+of $1.2 million and recognized a gain of approximately $222,000 from these
+sales. Throughout 2004 and 2003, the Company sold interests in certain
+properties and received $2.8 million and $23.5 million, respectively, in net
+proceeds and recognized a gain of approximately $1.8 million and $7.3
+million, respectively, from these sales. 
+F-15 
+Note
+4 - Income Taxes 
+The
+provision for income taxes consists of the following: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Current
+taxes: 
+Federal 
+$ 
+75,848 
+$ 
+21,143 
+$ 
+29,582 
+State 
+4,906 
+1,389 
+2,656
+Deferred
+taxes 
+5,547 
+31,217 
+23,692
+Total
+income tax expense 
+$ 
+86,301 
+$ 
+53,749 
+$ 
+55,930 
+As
+a
+result of the exercise of stock options, the Company was able to reduce its
+income tax payable in each year presented. The tax benefit to the Company of
+stock option exercises was $6.0 million in 2005, $3.8 million in 2004, and
+$1.2
+million in 2003.The components of the net deferred tax liability are as
+follows: 
+December
+31, 
+2005 
+2004 
+(In
+thousands) 
+Deferred
+tax liabilities: 
+Oil
+and gas properties 
+$ 
+204,745 
+$ 
+146,427 
+Interest
+on Convertible Notes 
+5,600 
+4,192 
+Unrealized
+derivative gain included in accumulated other comprehensive
+income 
+- 
+2,246 
+Other 
+2,750 
+435 
+Total
+deferred tax liabilities 
+213,095 
+153,300 
+Deferred
+tax assets: 
+Net
+Profits Plan liability 
+51,712 
+11,598 
+Unrealized
+derivative loss included in accumulated other comprehensive
+income 
+33,441 
+1,033 
+Stock
+compensation 
+4,585 
+1,590 
+State
+tax net operating loss carryforward or carryback 
+2,928 
+2,981 
+State
+and federal income tax benefit 
+1,587 
+1,100 
+Deferred
+capital loss 
+761 
+758 
+Employee
+benefits and other 
+609 
+969 
+Federal
+net operating loss carryforward 
+- 
+2,882 
+Total
+deferred tax assets 
+95,623 
+22,911 
+Valuation
+allowance 
+(2,572 
+) 
+(1,714 
+) 
+Net
+deferred tax assets 
+93,051 
+21,197 
+Total
+net deferred tax liabilities 
+120,044 
+132,103 
+Less:
+current deferred income tax liabilities 
+(1,328 
+) 
+(2,357 
+) 
+Add:
+current deferred income tax assets 
+9,580 
+84 
+Non-current
+net deferred tax liabilities 
+$ 
+128,296 
+$ 
+129,830 
+Current
+federal income tax payable 
+$ 
+3,346 
+$ 
+939 
+Current
+state refundable income tax 
+$ 
+- 
+$ 
+139 
+Current
+state income tax payable 
+$ 
+2,856 
+$ 
+- 
+At
+December 31, 2005, the Company had state net operating loss carryforwards of
+approximately $40.1 million and state tax credits of $125,000, which expire
+between 2006 and 2024. A portion of the Company’s valuation allowance relates to
+state net operating loss carryforwards, state tax credits, and state and federal
+income tax benefit amounts that the Company anticipates will expire before
+they
+can be utilized. The Company has concluded that permanent items included in
+the
+calculation of income tax for certain states may impact its ability to deduct
+net operating losses and realize federal income tax deduction benefits of those
+states and has adjusted its valuation allowances accordingly. The remaining
+portion of the valuation allowance relates to the Net Profits Plan liability
+and
+reflects an estimate of future executive compensation that may not be deductible
+for income tax as a result of payments under the plan. 
+F-16 
+Federal
+income tax expense and benefit differs from the amount that would be provided
+by
+applying the statutory U.S. federal income tax rate to income before income
+taxes for the following reasons: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Federal
+statutory taxes 
+$ 
+83,307 
+$ 
+51,180 
+$ 
+49,668 
+Increase
+(reduction) in taxes resulting from: 
+State
+taxes (net of federal benefit) 
+4,185 
+2,586 
+5,812 
+Domestic
+production activities deduction 
+(1,717 
+) 
+- 
+- 
+Statutory
+depletion 
+(224 
+) 
+(224 
+) 
+(224 
+) 
+Other 
+(108 
+) 
+(665 
+) 
+559 
+Change
+in valuation allowance 
+858 
+872 
+115 
+Income
+tax expense from operations 
+$ 
+86,301 
+$ 
+53,749 
+$ 
+55,930 
+Acquisitions,
+drilling and basis differentials impacting the prices received for crude oil
+and
+natural gas affect the apportionment of taxable income to the states where
+the
+Company owns properties. As these factors change, the Company’s state income tax
+rate changes. This change applied to the Company’s total temporary differences
+will impact the total income tax reported in the current year and is reflected
+in state taxes in the table above. Items affecting state appointment factors
+are
+evaluated upon completion of the prior year income tax return after significant
+acquisitions are closed and at the end of the year. 
+Note
+5 - Long-term Debt 
+Revolving
+Credit Facility 
+The
+Company executed an Amended and Restated Credit Agreement on
+April 7, 2005, to replace its previous credit facility. The new credit
+facility specifies a maximum loan amount of $500 million and has a maturity
+date of April 7, 2010. Borrowings under the facility are secured by a
+pledge in favor of the lenders of collateral that includes certain oil and
+gas
+properties and the common stock of the material subsidiaries of the Company.
+The
+borrowing base under the credit facility as authorized by the bank group is
+currently $500 million, and is subject to regular semi-annual
+redeterminations. The borrowing base redetermination process considers the
+value
+of St. Mary’s oil and gas properties and other assets, as determined by the bank
+syndicate. The Company has elected an aggregate commitment amount of
+$200 million under the credit facility. The Company must comply with
+certain financial and non-financial covenants. Interest and commitment fees
+are
+accrued based on the borrowing base utilization percentage table below.
+Euro-dollar loans accrue interest at LIBOR plus the applicable margin from
+the
+utilization table, and Alternative Base Rate (ABR) loans accrue interest at
+prime plus the applicable margin from the utilization table. Commitment fees
+are
+accrued on the unused portion of the aggregate commitment amount and are
+included in interest expense in the consolidated statements of
+operations. 
+Borrowing
+base 
+utilization
+percentage 
+< 50%
+> 50% < 75%
+> 75% < 90%
+> 90%
+Euro-dollar
+loans 
+1.000% 
+1.250% 
+1.500% 
+1.750% 
+ABR
+loans 
+0.000% 
+0.250% 
+0.250% 
+0.500% 
+Commitment
+fee rate 
+0.250% 
+0.300% 
+0.375% 
+0.375% 
+F-17 
+The
+Company had no outstanding loans under its revolving credit agreement on either
+December 31, 2005 or February 15, 2006. 
+5.75%
+Senior Convertible Notes Due 2022 
+As
+of
+December 31, 2005, the Company also had $100.0 million in outstanding
+borrowings in the form of convertible notes. The Convertible Notes provide
+for
+the payment of contingent interest of up to an additional one-half of one
+percent during six-month interest periods based on the Convertible Notes market
+price before the beginning of the particular six-month period. Under that
+provision, interest was accrued at a total rate of 6.25 percent for 2005.
+Based on the trading price of the Convertible Notes over the determination
+period, the Company will be subject to the contingent interest payments for
+the
+period from September 16, 2005, to March 15, 2006. 
+The
+Convertible Notes are general unsecured obligations and rank on parity in right
+of payment with all existing and future unsecured senior indebtedness and other
+general unsecured obligations. They are senior in right of payment to all future
+subordinated indebtedness. The Convertible Notes are convertible at any time
+into the Company’s common stock at a conversion price of $13.00 per share,
+subject to adjustment. The Company can redeem the Convertible Notes with cash
+in
+whole or in part at a repurchase price of 100 percent of the principal amount
+plus accrued and unpaid interest
+(including contingent interest) beginning on March 20, 2007. The note holders
+have the option of requiring the Company to repurchase the Convertible Notes
+for
+cash at 100 percent of the principal amount plus accrued and unpaid interest
+(including contingent interest) upon (1) a change in control of St. Mary or
+(2) on March 20, 2007, March 15, 2012, and March 15, 2017. If the note
+holders require repurchase on March 20, 2007, the Company may elect to pay
+the
+repurchase price with cash, shares of its common stock valued at a discount
+at
+the time of repurchase, or any combination of cash and its discounted common
+stock. The shares of common stock used in any repurchase will be discounted
+at
+95 percent of market price if 33 percent or less of the repurchase price is
+in
+shares of our common stock; otherwise, the stock will be discounted at 93
+percent of market value. St. Mary is not restricted from paying dividends,
+incurring debt, or issuing or repurchasing its securities under the indenture
+for the Convertible Notes. There are no financial covenants in the indenture.
+Based on the market price of the Convertible Notes, the estimated fair value
+of
+the Convertible Notes was approximately $ 286
+million
+as of December 31, 2005, and approximately $172 million as of December 31,
+2004. 
+Weighted-Average
+Interest Rate Paid and Capitalized Interest 
+The
+weighted-average interest rate paid in 2005 and 2004 was 7.1 percent, including
+commitment fees paid on the unused portion of the credit facility aggregate
+commitment, amortization of deferred financing costs, amortization of the
+contingent interest embedded derivative and the effect of interest rate swaps.
+The impact of these items over a lower average outstanding loan balance results
+in a higher weighted-average interest rate. The Company capitalized interest
+costs of $1.9 million, $1.4 million, and $780,000 for the years ended December
+31, 2005, 2004, and 2003, respectively. 
+Note
+6 - Commitments and Contingencies 
+The
+Company leases office space under various operating leases with terms extending
+as far as May 31, 2012. Rent expense, net of sublease income, was $1.3
+million, $1.5 million, and $1.3 million in 2005, 2004 and 2003,
+respectively. The Company also leases office equipment under various operating
+leases. The Company has a non-cancelable sublease of approximately
+$1.2 million through 2012. The annual minimum lease payments for the next
+five years and thereafter are presented below: 
+F-18 
+Years
+Ending December 31, 
+(In
+thousands) 
+2006 
+2,447 
+2007 
+1,570 
+2008 
+1,370 
+2009 
+1,238 
+2010 
+1,192 
+Thereafter 
+1,507 
+Total 
+$ 
+9,324 
+The
+Company is subject to litigation and claims that have arisen in the ordinary
+course of business. The Company accrues for such items when a liability is
+both
+probable and the amount can be reasonably estimated. In the opinion of
+management, the results of such litigation and claims will not have a material
+effect on the results of operations or the financial position of the Company.
+Management believes it has sufficiently provided for such items to the extent
+necessary in the consolidated balance sheets. 
+Note
+7 - Compensation Plans 
+Cash
+Bonus Plan 
+The
+Company has a cash bonus plan that allows participants to receive up to 50
+percent of their aggregate base salary. Any awards under the cash bonus plans
+are based on a combination of Company and individual performance. The Company
+accrued $7.4 million for cash bonuses in 2005 that will be paid in 2006, and
+$2.0 million for cash bonuses in 2004 that were paid in 2005. 
+Net
+Profits Plan 
+Under
+the
+Company’s Net Profits Plan, oil and gas wells that are completed or acquired
+during a year are designated within a specific pool. Key employees designated
+as
+participants by the Company’s Compensation Committee of the Board of Directors,
+upon recommendation by senior management, and employed by the Company on the
+last day of that year become entitled to bonus payments after the Company has
+received net cash flows returning 100 percent of all costs associated with
+that pool. Thereafter, ten percent of future net cash flows generated by
+the pool are allocated among the participants and distributed at least annually.
+The portion of net cash flows from the pool to be allocated among the
+participants increases to 20 percent after the Company has recovered
+200 percent of the total costs for the pool, including payments made under
+the Net Profits Plan at the ten percent level. The Net Profits Plan has
+been in place since 1991. Pool years prior to and including 2005 are fully
+vested. Pool years beginning in 2006 will carry a vesting period of three years
+and a maximum benefit to full participants from a particular year’s pool of
+300 percent of each participating individual’s salary paid to such
+individual during the year to which the pool relates. A partial interest
+participant’s benefit is prorated proportionally from the 300
+percent. 
+Expense
+for distributions made or accrued under the Net Profits Plan related to current
+period operations for the years ended 2005, 2004, and 2003 were $20.8 million,
+$8.0 million, and $8.9 million, respectively. These amounts relate to the
+current period realized results from oil and gas operations for the properties
+associated with the respective pools that have achieved payout
+status. 
+In
+a
+separate calculation, the Company records the estimated liability for future
+payments under the Net Profits Plan based on the discounted value of estimated
+future payments associated with each individual pool. The calculation of this
+liability is a significant management estimate utilizing a discount rate of
+predominately 15 percent, and is intended to represent the best estimate of
+the present value of expected future payments under the Net Profits Plan. The
+Company’s estimate of its liability is highly dependent on the price assumptions
+and discount rates used in the calculations. The price assumptions are currently
+formulated by applying a price that is derived from a rolling average of actual
+prices realized from the prior 24 months together with adjusted NYMEX strip
+prices for the ensuing 12 months. This calculation is supplemented with
+hedge prices for the percentage of forecast production hedged. The forecast
+expense associated with this significant management estimate increased
+substantially in 2005 as a result of the significant increase of oil and gas
+prices during the year, together with the impact of pricing that is assured
+to
+the Company as a result of executing its expanded hedging strategy. In addition,
+these higher prices have moved more pools to payout status. The Company
+continually evaluates the assumptions used in this calculation in order to
+include the current market environment for oil and gas prices, discount rates
+and overall market conditions. The calculation of the estimated liability for
+the Net Profits Plan is highly sensitive to our price estimates and discount
+rate assumptions. For example, if we changed the prices in our calculation
+by
+ten percent, the liability recorded at December 31, 2005, would differ by
+approximately $26 million, and a one percent change in the discount rate would
+result in a change of approximately $5 million. Actual cash payments to be
+made
+in future periods are dependent on realized actual production, prices, and
+costs
+associated with the individual pools of the Net Profits Plan. Consequently,
+actual cash payments will be inherently different from the amounts
+estimated. 
+F-19 
+The
+following table presents the changes in the estimated liability attributable
+to
+the Net Profits Plan: 
+As
+of December 31, 
+2005 
+2004 
+(In
+thousands) 
+Beginning
+liability for Net Profits Plan 
+$ 
+30,561 
+$ 
+6,163 
+Increase
+in liability 
+127,064 
+32,410 
+Reduction
+in liability for cash payments made or accrued and recognized as
+compensation expense under the Net Profits Plan 
+(20,801 
+) 
+(8,012 
+) 
+Ending
+liability for Net Profits Plan 
+$ 
+136,824 
+$ 
+30,561 
+The
+Company records changes in the present value of estimated future payments under
+the Net Profits Plan as a separate item in the consolidated statements of
+operations. The change in the estimated liability is recorded as an increase
+or
+decrease to expense in the current period. The amount recorded as an increase
+or
+decrease to expense associated with the change in the estimated liability is
+not
+allocated to general and administrative costs or exploration costs because
+it is
+an estimate at the current time of the adjustment to the liability that is
+associated with the future net cash flows from oil and gas properties in the
+respective pools rather than current period realized performance. The table
+below presents the estimated allocation of the change in the liability if the
+Company did allocate the adjustment to these specific line items: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+General
+and administrative expense 
+$ 
+51,419 
+$ 
+14,609 
+$ 
+3,982 
+Exploration
+expense 
+54,844 
+9,789 
+1,335 
+Total 
+$ 
+106,263 
+$ 
+24,398 
+$ 
+5,317 
+401(k)
+Plan 
+The
+Company has a defined contribution pension plan (the "401(k) Plan") that is
+subject to the Employee Retirement Income Security Act of 1974. The 401(k)
+Plan
+allows eligible employees to contribute up to 60 percent of their base salaries.
+The Company matches each employee's contributions up to six percent of the
+employee's base salary and may make additional contributions at its discretion.
+The Company’s contributions to the 401(k) Plan were $966,000, $834,000, and
+$746,000 for the years ended December 31, 2005, 2004, and 2003, respectively.
+No
+discretionary contributions were made by the Company to the 401(k) Plan in
+any
+of these three years. 
+Employee
+Stock Purchase Plan 
+Under 
+the
+St. Mary Land & Exploration Company Employee Stock Purchase Plan (“the
+ESPP”), eligible employees may purchase shares of the Company’s common stock
+through payroll deductions of up to 15 percent of eligible compensation. The
+purchase price of the stock is 85 percent of the lower of the fair market value
+of the stock on the first or last day of the purchase period, and shares issued
+under the ESPP are restricted for a period of 18 months from the date issued.
+The ESPP is intended to qualify under Section 423 of the Internal Revenue Code.
+The Company has set aside 2,000,000 shares of its common stock to be available
+for issuance under the ESPP. Shares issued under the ESPP totaled 28,447
+in
+2005, 
+27,748
+in 2004, and 33,988 in 2003. Total proceeds to the Company for the issuance
+of
+these shares were $ 601,000
+in 2005, 
+$375,000
+in 2004, and $375,000 in 2003. 
+F-20 
+Stock
+Option Plans 
+The
+Company has a Stock Option Plan and an Incentive Stock Option Plan
+(collectively, the “Option Plans”). The Option Plans grant options to purchase
+shares of the Company’s common stock to eligible employees, contractors, and
+current and former members of the Board of Directors. There are 11.2 million
+shares of the Company’s common stock reserved for issuance under the Option
+Plans. This number is reduced to the extent that restricted stock or restricted
+stock units are granted under the Restricted Stock Plan. All options granted
+to
+date under the Option Plans have been granted at exercise prices equal to the
+respective market prices of the Company’s common stock on the grant dates. There
+were 1,063,617 
+shares
+available for grant under the Option Plans (including the Restricted Stock
+Plan,
+as described later) as of December 31, 2005. 
+A
+summary
+of activity associated with the Company’s Stock Option Plans during the last
+three years follows: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+Weighted- 
+Weighted- 
+Weighted- 
+Average 
+Average 
+Average 
+Exercise 
+Exercise 
+Exercise 
+Shares 
+Price 
+Shares 
+Price 
+Shares 
+Price 
+Outstanding,
+start of year 
+5,651,350 
+$ 
+12.06 
+7,050,256 
+$ 
+11.55 
+6,123,132 
+$ 
+10.67 
+Granted
+- 
+- 
+117,356 
+18.90 
+1,716,862 
+13.35 
+Exercised
+(936,403 
+) 
+11.31 
+(1,399,052 
+) 
+10.03 
+(490,038 
+) 
+6.44 
+Forfeited 
+(16,704 
+) 
+13.24 
+(117,210 
+) 
+12.50 
+(299,700 
+) 
+12.00 
+Outstanding,
+end of year 
+4,698,243 
+12.21 
+5,651,350 
+12.06 
+7,050,256 
+11.55 
+Exercisable,
+end of year 
+4,121,424 
+12.07 
+4,441,362 
+11.76 
+4,882,492 
+11.18 
+Weighted-average
+fair value of options granted during the year 
+$ 
+- 
+$ 
+8.44 
+$ 
+6.14 
+F-21 
+A
+summary
+of additional information related to options outstanding as of
+December 31, 2005, follows: 
+Options
+Outstanding 
+Options
+Exercisable 
+Range
+of 
+Exercise Prices 
+Number 
+Outstanding 
+Weighted-Average
+Remaining 
+Contractual Life 
+Weighted-Average
+Exercise Price 
+Number 
+Exercisable 
+Weighted-Average
+Exercise Price 
+$ 4.62 
+- 
+5.13 
+145,270 
+3.0
+years 
+4.63 
+145,270 
+4.63 
+5.13 
+- 
+8.75 
+666,394 
+4.0
+years 
+6.91 
+666,394 
+6.91 
+8.75 
+- 
+11.95 
+1,175,680 
+6.4
+years 
+11.35 
+925,680 
+11.29 
+11.95 
+- 
+12.90 
+1,075,639 
+7.2
+years 
+12.46 
+971,363 
+12.43 
+12.90 
+- 
+14.25 
+794,806 
+7.8
+years 
+13.88 
+631,579 
+13.87 
+14.25 
+- 
+16.72 
+772,050 
+5.2
+years 
+16.66 
+742,050 
+16.66 
+16.72 
+- 
+20.87 
+68,404 
+9.0
+years 
+20.87 
+39,088 
+20.87 
+Total 
+4,698,243 
+4,121,424 
+SFAS
+No.
+123 establishes a fair value method of accounting for stock-based compensation
+plans through either recognition or disclosure. The Company accounts for
+stock-based compensation under the intrinsic value method pursuant to APB No.
+25
+and has elected to adopt SFAS No. 123 through compliance with the disclosure
+requirements set forth in the Statement. Because the exercise price of the
+Company’s stock options equals the market price of the underlying stock on the
+date of grant, no compensation expense is recognized under APB No. 25. Pro
+forma
+information regarding net income and earnings per share is required by SFAS
+No.
+123 and has been determined as if the Company had accounted for its employee
+stock options under the fair value method of that Statement. This pro forma
+information is prominently disclosed in Note 1 - Summary of Significant
+Accounting Policies. 
+The
+fair
+value of options was measured at the date of grant using the Black-Scholes
+option-pricing model. The fair values of options granted and employee stock
+purchase plan shares issued were estimated using the following weighted-average
+assumptions: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+Risk
+free interest rate: 
+Stock
+options 
+- 
+4.1% 
+3.6% 
+Employee
+stock purchase plan 
+2.5 % 
+3.1% 
+3.7% 
+Dividend
+yield: 
+Stock
+options 
+- 
+0.3% 
+0.4% 
+Employee
+stock purchase plan 
+0.4% 
+0.3% 
+0.4% 
+Volatility
+factor of the expected market 
+price
+of the Company's common stock: 
+Stock
+options 
+- 
+35.9% 
+39.9% 
+Employee
+stock purchase plan 
+36.3% 
+23.8% 
+20.2% 
+Expected
+life of the options (in years) 
+Stock
+options 
+- 
+9.0 
+7.0 
+Employee
+stock purchase plan 
+0.5 
+0.5 
+0.5 
+The
+Black-Scholes option valuation model was developed for use in estimating the
+fair value of traded options that have no vesting restrictions and are fully
+transferable. In addition, option valuation models require the input of highly
+subjective assumptions including the expected stock price volatility. The
+Company’s stock options have characteristics significantly different from those
+of traded options, and because changes in the subjective input assumptions
+can
+materially affect the fair value estimate, it is management’s opinion that the
+valuations afforded by the existing models are different from the value that
+the
+options would realize if traded in the market. 
+F-22 
+Restricted
+Stock Plan 
+In
+May 2004 the Restricted Stock Plan was approved by the Company’s
+stockholders. This established a long-term incentive program whereby grants
+of
+restricted stock or restricted stock units (“RSUs”) may be awarded to eligible
+employees, consultants, and members of the Board of Directors. Restrictions
+and
+vesting periods for the awards are determined at the discretion of the Board
+of
+Directors and are set forth in the award agreements. Each RSU represents a
+right
+for one share of the Company’s common stock to be delivered upon settlement of
+the award at the end of a specified restriction period. The total number of
+shares of the Company’s common stock reserved for issuance under the Restricted
+Stock Plan is 11,200,000. This number is reduced to the extent that stock
+options are granted under the Company’s Option Plans. 
+St.
+Mary
+issued 194,508 RSUs on March 15, 2005, related to 2004 performance.
+The total expense associated with this issuance was $4.9 million as
+measured on the grant date. The total unvested portion of the measured expense
+was initially recorded as deferred stock-based compensation and is being charged
+to compensation expense based on the vesting schedule. The granted RSUs vest
+25 percent immediately upon grant and 25 percent on each of the next
+three anniversary dates of the grant. The vested shares underlying the RSU
+grants will be issued on the third anniversary of the grant, at which time
+the
+shares carry no further restrictions. As of December 31, 2005, there were a
+total of 632,809 RSUs outstanding, of which 276,746 were vested. Total
+compensation expense related to the RSUs for the year ended December
+31, 2005, was $7.0 million. This amount includes $4.0 million of
+compensation expense related to the 2005 plan year for the estimated value
+of
+grants expected to be issued in 2006. 
+Non
+-Employee Director Stock Compensation Plan 
+In
+May
+2003, stockholders approved a Non-Employee Director Stock Compensation Plan
+to
+authorize the issuance of up to 60,000 shares of St. Mary’s common stock to
+non-employee directors as part of their compensation over an anticipated period
+of up to five years. The purpose of the plan is to attract, retain, and motivate
+non-employee directors. As of December 31, 2005, 39,126 shares have
+been issued under this plan. 
+Note
+8 - Pension Benefits 
+The
+Company has a non-contributory pension plan covering substantially all employees
+who meet age and service requirements (the “Qualified Pension Plan”). The
+Company also has a supplemental non-contributory pension plan covering certain
+management employees (the “Nonqualified Pension Plan”). 
+F-23 
+Obligations
+and Funded Status for Both Plans 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Change
+in benefit obligations: 
+Projected
+benefit obligation at beginning of year 
+$ 
+10,174 
+$ 
+8,048 
+$ 
+6,330 
+Service
+cost 
+1,385 
+1,139 
+963 
+Interest
+cost 
+535 
+489 
+428 
+Actuarial
+loss 
+(4 
+) 
+1,236 
+620 
+Benefits
+paid 
+(190 
+) 
+(738 
+) 
+(293 
+) 
+Projected
+benefit obligation at end of year 
+$ 
+11,900 
+$ 
+10,174 
+$ 
+8,048 
+Change
+in plan assets: 
+Fair
+value of plan assets at beginning of year 
+$ 
+4,675 
+$ 
+3,694 
+$ 
+2,478 
+Actual
+return on plan assets 
+412 
+434 
+608 
+Employer
+contribution 
+1,058 
+1,285 
+901 
+Benefits
+paid 
+(190 
+) 
+(738 
+) 
+(293 
+) 
+Fair
+value of plan assets at end of year 
+$ 
+5,955 
+$ 
+4,675 
+$ 
+3,694 
+Funded
+status: 
+$ 
+(5,945 
+) 
+$ 
+(5,499 
+) 
+$ 
+(4,354 
+) 
+Unrecognized
+net loss 
+3,450 
+3,754 
+2,874 
+Unrecognized
+prior service cost 
+- 
+- 
+(15 
+) 
+Accrued
+benefit cost 
+$ 
+(2,495 
+) 
+$ 
+(1,745 
+) 
+$ 
+(1,495 
+) 
+Amounts
+Recognized in the Consolidated Balance Sheets for Both Plans 
+As
+of December 31, 
+2005 
+2004 
+(In
+thousands) 
+Accrued
+benefit cost 
+$ 
+2,495 
+$ 
+1,745 
+Accumulated
+other comprehensive income 
+290 
+746 
+Net
+amount recognized 
+$ 
+2,785 
+$ 
+2,491 
+Information
+for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan
+Assets for Both Plans 
+As
+of December 31, 
+2005 
+2004 
+(In
+thousands) 
+Projected
+benefit obligation 
+$ 
+11,900 
+$ 
+10,174 
+Accumulated
+benefit obligation 
+$ 
+8,429 
+$ 
+7,143 
+Fair
+value of plan assets 
+$ 
+5,955 
+$ 
+4,675 
+The
+Company’s accumulated benefit obligation for the Qualified Pension Plan was
+$ 7.3
+million at December 31, 2005, and $5.9 million at December 31, 2004.
+The accumulated benefit obligation exceeds plan assets by $1.3 million. The
+tax-adjusted liability of $180,000 was recorded in other comprehensive income
+at
+December 31, 2005. 
+The
+Company’s accumulated benefit obligation for the Nonqualified Pension Plan was
+$ 1.1 
+million
+at December 31, 2005, and $1.2 million at December 31, 2004.
+There are no plan assets in the Nonqualified Pension Plan due to the nature
+of
+the plan. 
+F-24 
+Components
+of Net Periodic Benefit Cost for Both Plans 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Components
+of net periodic benefit cost: 
+Service
+cost 
+$ 
+1,385 
+$ 
+1,139 
+$ 
+963 
+Interest
+cost 
+535 
+489 
+428 
+Expected
+return on plan assets 
+(354 
+) 
+(295 
+) 
+(172 
+) 
+Amortization
+of prior service cost 
+- 
+(16 
+) 
+(25 
+) 
+Amortization
+of net actuarial loss 
+241 
+218 
+329 
+Net
+periodic benefit cost 
+$ 
+1,807 
+$ 
+1,535 
+$ 
+1,523 
+Prior
+service costs are amortized on a straight-line basis over the average remaining
+service period of active participants. Gains and losses in excess of ten percent
+of the greater of the benefit obligation and the market-related value of assets
+are amortized over the average remaining service period of active
+participants. 
+Additional
+Information 
+The
+minimum liability included in other accumulated comprehensive income, net of
+taxes, decreased by $ 283,000, 
+$101,000
+and $197,000 for the years ended December 31, 2005, 2004 and 2003,
+respectively. 
+Assumptions 
+Weighted-average
+assumptions to measure the Company’s projected benefit obligation and net
+periodic benefit cost are as follows: 
+As
+of December 31, 
+2005 
+2004 
+Projected
+benefit obligation 
+Discount
+rate 
+5.50% 
+5.75% 
+Expected
+return on plan assets 
+7.50% 
+8.00% 
+Rate
+of compensation increase 
+5.93% 
+4.00% 
+Net
+periodic benefit cost 
+Discount
+rate 
+5.75% 
+6.25% 
+Expected
+return on plan assets 
+7.50% 
+8.00% 
+Rate
+of compensation increase 
+5.93% 
+3.50% 
+Plan
+Assets 
+The
+Company’s weighted-average asset allocation for the Qualified Plan is as
+follows: 
+Target 
+As
+of December 31, 
+Asset
+Category 
+2006 
+2005 
+2004 
+Equity
+securities 
+60 % 
+61.6% 
+63.0% 
+Debt
+securities 
+40% 
+38.2% 
+34.7% 
+Other 
+- 
+0.2% 
+2.3% 
+Total 
+100.0% 
+100.0% 
+100.0% 
+F-25 
+Equity
+securities do not include any shares of the Company’s common stock for any
+period presented. There is no asset allocation for the Nonqualified Pension
+Plan
+since that plan does not have its own assets. An expected return on plan assets
+of 7.5 percent was used to calculate the Company’s obligation under the
+Qualified Plan. Factors considered in determining the expected return
+include the 60 percent equity and 40 percent debt securities mix of investment
+for plan assets and the long-term historical rate of return provided by the
+equity and debt securities markets. The estimated rate of return on plan
+assets was 7.8 percent for 2005 and 10.4 percent for 2004. The difference
+in investment income using the projected rate of return compared to the actual
+rates of return for the past two years was not material and will not have a
+material effect on the statements of operation or on cash flows from operating
+activities in future years. 
+Contributions 
+The
+Company contributed $1.1 million, $1.3 million, and $901,000, to the pension
+plans in the years ended December 31, 2005, 2004, and 2003,
+respectively. St. Mary expects to contribute approximately $1.4 million to
+the pension plans in 2006. 
+Benefit
+Payments 
+The
+Plans
+made actual benefit payments of $190,000, $738,000, and $293,000 in the years
+ended December 31, 2005, 2004, and 2003, respectively. Expected benefit payments
+over the next ten years follows: 
+Years
+Ended December 31, 
+(in
+thousands) 
+2006 
+$ 
+310 
+2007 
+$ 
+413 
+2008 
+$ 
+534 
+2009 
+$ 
+732 
+2010 
+$ 
+793 
+2011
+through 2015 
+$ 
+10,181 
+Note
+9 - Asset Retirement Obligations 
+The
+Company recognizes an estimated liability for future costs associated with
+the
+abandonment of its oil and gas properties. A liability for the fair value of
+an
+asset retirement obligation and a corresponding increase to the carrying value
+of the related long-lived asset are recorded at the time a well is completed
+or
+acquired. The increase in carrying value is included in proved oil and gas
+properties in the consolidated balance sheets. The Company depletes the amount
+added to proved oil and gas property costs and recognizes accretion expense
+in
+connection with the discounted liability over the remaining estimated economic
+lives of the respective oil and gas properties. 
+The
+Company’s estimated asset retirement obligation liability is based on historical
+experience in abandoning wells, estimated economic lives, estimates as to the
+cost to abandon the wells in the future, and federal and state regulatory
+requirements. The liability is discounted using a credit-adjusted risk-free
+rate
+estimated at the time the liability is incurred or revised. The credit-adjusted
+risk-free rates used to discount the Company’s abandonment liabilities range
+from 6.50 percent to 7.25 percent. Revisions to the liability are due
+to increases in estimated abandonment costs and changes in well economic
+lives. 
+A
+reconciliation of the Company's asset retirement obligation liability is as
+follows: 
+As
+of December 31, 
+2005 
+2004 
+(In
+thousands) 
+Beginning
+asset retirement obligation 
+$ 
+40,911 
+$ 
+25,485 
+Liabilities
+incurred 
+13,188 
+7,187 
+Liabilities
+settled 
+(955 
+) 
+(620 
+) 
+Accretion
+expense 
+3,279 
+1,984 
+Revision
+to estimated cash flows 
+9,655 
+6,875 
+Ending
+asset retirement obligation 
+$ 
+66,078 
+$ 
+40,911 
+F-26 
+Note
+10 - Derivative Financial Instruments 
+To
+mitigate a portion of the potential exposure to adverse market changes, the
+Company has entered into various derivative contracts. The
+Company realized a net loss of $24.4 million, $49.8 million, and $22.7
+million from its derivative contracts for the years ended
+December 31, 2005, 2004, and 2003 respectively. 
+The
+following table summarizes derivative instrument gain (loss)
+activity: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Derivative
+contract settlements included in oil and gas hedge loss 
+$ 
+(22,539 
+) 
+$ 
+(50,299 
+) 
+$ 
+(22,439 
+) 
+Ineffective
+portion of hedges qualifying for hedge accounting included in derivative
+gain (loss) 
+(1,754 
+) 
+113 
+(246 
+) 
+Non-qualified
+derivative contracts included in derivative gain (loss) 
+139 
+(373 
+) 
+(64 
+) 
+Interest
+rate derivative contract settlements 
+(247 
+) 
+795 
+- 
+Total
+loss 
+$ 
+(24,401 
+) 
+$ 
+(49,764 
+) 
+$ 
+(22,749 
+) 
+Oil
+and Gas Commodity Hedges 
+The
+Company has in place derivative contracts, which included swap and collar
+arrangements, for the sale of oil and natural gas. Including oil and natural
+gas
+collar arrangements entered into subsequent to December 31, 2005, the
+Company has hedge contracts in place through 2011 for a total of approximately
+13.0 million Bbls and 73.7 million MMBTU of anticipated production.
+The
+Company anticipates that all forecasted transactions will occur by the end
+of
+their originally specified periods. All contracts are entered into for other
+than trading purposes. 
+The
+Company attempts to qualify its oil and natural gas derivative instruments
+as
+cash flow hedges for accounting purposes. As of December 31, 2005, all oil
+and natural gas derivative instruments qualified as cash flow hedges for
+accounting purposes. T he
+estimated fair value of oil
+and
+natural gas derivative contracts designated
+and qualifying as cash flow hedges under SFAS No. 133 was a net
+liability of $90 million at December
+31, 2005.
+Gains
+or
+losses from the settlement of oil and gas derivative contracts are reported
+in
+the total operating revenues section on the consolidated statements of
+operations. Changes in the fair value of derivative instruments designated
+as
+cash flow hedges, to the extent they are effective in offsetting cash flows
+attributable to the hedged risk, are recorded in other comprehensive income
+until the hedged item is recognized in earnings. Any change in fair value
+resulting from ineffectiveness is recognized currently in derivative gain (loss)
+in the consolidated statement of operations. 
+The
+Company seeks to minimize ineffectiveness by entering into oil derivative
+contracts indexed to NYMEX and gas contracts indexed to regional index prices
+associated with pipelines in proximity to the Company’s areas of production. As
+the Company’s derivative contracts contain the same index as the Company’s sale
+contracts, this results in hedges that are highly correlated with the underlying
+hedged item. 
+F-27 
+Derivative
+gain or loss for the years ended December 31, 2005, 2004, and 2003, includes
+a
+net loss of $1.8 million, a net gain of $113,000, and a net loss of
+$246,000, respectively, from ineffectiveness related to oil and natural gas
+derivative contracts. 
+As
+of
+December
+31, 2005,
+the
+amount of unrealized loss net of deferred income taxes to be reclassified from
+accumulated other comprehensive income to oil and gas production operating
+revenues in the next twelve months was $17.0 million. 
+Interest
+Rate Derivative Contracts 
+In
+October 2003 the Company entered into fixed-to-floating interest rate swaps
+for
+a total notional amount of $50 million through March 20, 2007. Under
+the swaps, St. Mary will be paid a fixed interest rate of 5.75 percent and
+will pay a variable interest rate of 235 basis points above the six-month
+LIBOR rate as determined on the semi-annual settlement date. The payment dates
+of the swaps match exactly with the interest payment dates of the Convertible
+Notes. 
+The
+Company entered into a floating-to-fixed interest rate swap on
+April 13, 2005, for a total notional amount of $50 million
+through March 20, 2007, that effectively offsets the fixed-to-floating
+interest rate swaps described above. Under the swap, St. Mary will be paid
+a
+variable interest rate of 235 basis points above the six-month LIBOR rate
+as determined on the semi-annual settlement date and will pay a fixed interest
+rate of 6.85 percent. The payment dates of the swap match exactly with the
+interest payment dates of the Convertible Notes and the fixed-to-floating
+interest rate swaps. The impact of this instrument, when combined with the
+other
+interest rate swaps, is that the Company has fixed its net liability related
+to
+the interest rate swaps and will pay a 1.1 percent interest factor on
+$50 million of notional debt through March 2007. 
+During
+the year ended December 31, 2005, the Company made payments of $247,000,
+and during the year ended December 31 , 2004,
+the
+Company received payments of $795,000 under the swap arrangements. These
+payments are included in the Company’s interest expense. 
+The
+fair
+value of the interest rate derivatives was a liability of $646,000 as of
+December 31, 2005. The Company recorded a net derivative loss in the
+consolidated statements of operations of $213,000, $328,000, and $104,000 for
+the years ended December 31, 2005, 2004, and 2003, respectively, from
+mark-to-market adjustments for these derivatives. These swaps do not qualify
+for
+fair value hedge treatment under SFAS No. 133 and related
+pronouncements. 
+Convertible
+Note Derivative Interest 
+The
+contingent interest provision of the Convertible Notes is considered an embedded
+equity-related derivative that is not clearly and closely related to the fair
+value of an equity interest and therefore must be separately accounted for
+as a
+derivative instrument. The value of the derivative at issuance of the
+Convertible Notes in March 2002 was $474,000. This amount was recorded as a
+decrease to the Convertible Notes payable in the consolidated balance sheets.
+Interest expense for the years ended December 2005, 2004, and 2003,
+includes $95,000 of annual amortization of the original value of this
+derivative. Derivative gain (loss) in the consolidated statements of operations
+for the years ended December 31, 2005, 2004, and 2003, includes a net
+gain of $352,000, a net loss of $45,000, and a net gain of $40,000,
+respectively, from mark-to-market adjustments for this derivative. The fair
+value of this derivative was a liability of $468,000 and $820,000 at December
+31, 2005 and 2004, respectively. 
+F-28 
+Note
+11 - Repurchase of Common Stock 
+Stock
+Repurchase Program 
+In
+August 2004 the Company’s Board of Directors approved an increase in the
+number of shares that may be repurchased under the original authorization
+approved in August 1998 to 6,000,000 as of the effective date of the
+resolution. The shares may be repurchased from time to time in open market
+transactions or privately negotiated transactions, subject to market conditions
+and other factors, including certain provisions of St. Mary’s existing credit
+facility agreement and compliance with securities laws. Stock repurchases may
+be
+funded with existing cash balances, internal cash flow and borrowings under
+the
+credit facility. As of December 31, 2005, 2,153,882 shares of the Company’s
+common stock had been repurchased under the plan. The Company repurchased
+1,175,282 and 978,600 shares in 2005 and 2004, respectively. 
+Repurchase
+of St. Mary Common Stock from Flying J 
+In
+February 2004 the Company repurchased 6,671,636 restricted shares of its
+common stock from Flying J Oil & Gas Inc. and Big West Oil & Gas
+Inc. (collectively “Flying J”) for a total of $91.0 million.
+St. Mary originally issued these shares to Flying J on
+January 29, 2003, in connection with St. Mary's acquisition of
+certain oil and gas properties. In addition to issuing the shares in the
+acquisition, St. Mary loaned Flying J $71.6 million.
+Flying J used the proceeds of the stock repurchase to repay their
+outstanding loan balance of $71.6 million. Accrued interest, which had not
+been recorded by the Company for financial reporting purposes due to the
+non-recourse nature of the loan, was forgiven. The net $19.4 million cash
+outlay for the repurchase was funded from the Company's existing cash balances
+and borrowings under its bank credit facility. 
+Note
+12 - Disclosures about Oil and Gas Producing Activities 
+Costs
+Incurred in Oil and Gas Producing Activities: 
+Costs
+incurred in oil and gas property acquisition, exploration and development
+activities, whether capitalized or expensed, are summarized as follows. The
+2005, 2004 and 2003 amounts include $22.8
+million, $14.1 million, and $5.5 million, respectively, of capitalized
+costs associated with asset retirement obligations. 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Development
+costs 
+$ 
+249,518 
+$ 
+190,829 
+$ 
+111,908 
+Exploration 
+69,817 
+37,977 
+33,296 
+Acquisitions: 
+Proved 
+84,981 
+69,054 
+73,989 
+Unproved 
+2,853 
+7,646 
+8,942 
+Leasing
+activity 
+14,330 
+7,877 
+7,480 
+Total
+$ 
+421,499 
+$ 
+313,383 
+$ 
+235,615 
+F-29 
+The
+following table reflects the net changes in capitalized exploratory well costs
+during 2005, 2004 and 2003, and does not include amounts that were capitalized
+and either subsequently expensed or reclassified to producing well costs in
+the same period. Capitalized exploratory well costs for fiscal years ending
+December 31, 2004 and December 31, 2003 are presented based on the Company’s
+previous accounting policy. 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Beginning
+balance at January 1, 
+$ 
+189 
+$ 
+544 
+$ 
+3,335 
+Capitalized
+exploratory well costs charged to expense upon the adoption of FSP
+FAS
+19-1 
+- 
+- 
+- 
+Additions
+to capitalized exploratory well costs pending the determination of
+proved
+reserves 
+7,994 
+189 
+544 
+Reclassifications
+to wells, facilities, and equipment based on the determination of
+proved
+reserves 
+(189 
+) 
+- 
+(333 
+) 
+Capitalized
+exploratory well costs charged to expense 
+- 
+(544 
+) 
+(3,002 
+) 
+Ending
+balance as December 31, 
+$ 
+7,994 
+$ 
+189 
+$ 
+544 
+No
+exploratory well costs have been capitalized for a period greater than one
+year
+from the completion of exploratory drilling. 
+Oil
+and Gas Reserve Quantities (Unaudited): 
+For
+all
+years presented, Ryder Scott Company L.P. and/or Netherland, Sewell and
+Associates, Inc. (“NSAI”) prepared the reserve information for greater than 80
+percent of the PV-10 value. The Company engaged NSAI for the first time in
+2004.
+St. Mary prepared the reserve estimates for the remainder of all
+properties. The Company emphasizes that reserve estimates are inherently
+imprecise and that estimates of new discoveries and undeveloped locations are
+more imprecise than estimates of established proved producing oil and gas
+properties. Accordingly, these estimates are expected to change as future
+information becomes available. 
+F-30 
+Proved
+oil and gas reserves are the estimated quantities of crude oil, natural gas
+and
+natural gas liquids that geological and engineering data demonstrate with
+reasonable certainty to be recoverable in future years from known reservoirs
+under existing economic and operating conditions. Proved developed oil and
+gas
+reserves are those expected to be recovered through existing wells with existing
+equipment and operating methods. All of the Company’s proved reserves are
+located in the Continental United States and Gulf of Mexico. 
+Presented
+below is a summary of the changes in estimated reserves of the
+Company: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+Oil
+or 
+Oil
+or 
+Oil
+or 
+Condensate 
+Gas 
+Condensate 
+Gas 
+Condensate 
+Gas 
+(MBbl) 
+(MMcf) 
+(MBbl) 
+(MMcf) 
+(MBbl) 
+(MMcf) 
+Developed
+and undeveloped: 
+Beginning
+of year 
+56,574 
+319,196 
+47,787 
+307,024 
+36,119 
+274,172 
+Revisions
+of previous estimate 
+1,593 
+24,354 
+1,994 
+(21,885 
+) 
+2,856 
+3,904 
+Discoveries
+and extensions 
+5,839 
+105,091 
+6,306 
+63,185 
+3,681 
+69,189 
+Purchases
+of minerals in place 
+4,831 
+20,823 
+5,773 
+17,635 
+11,952 
+41,335 
+Sales
+of reserves 
+(7 
+) 
+(588 
+) 
+(487 
+) 
+(165 
+) 
+(2,280 
+) 
+(31,913 
+) 
+Production 
+(5,927 
+) 
+(51,801 
+) 
+(4,799 
+) 
+(46,598 
+) 
+(4,541 
+) 
+(49,663 
+) 
+End
+of year (a) 
+62,903 
+417,075 
+56,574 
+319,196 
+47,787 
+307,024 
+Proved
+developed reserves: 
+Beginning
+of year 
+47,992 
+272,295 
+43,693 
+264,140 
+33,580 
+228,973 
+End
+of year 
+55,971 
+313,125 
+47,992 
+272,295 
+43,693 
+264,140 
+(a) 
+At
+December 31, 2005, 2004, and 2003 amounts include approximately 435,480,
+and 1,119 MMcf, respectively, representing the Company's net underproduced
+gas balancing position. 
+Standardized
+Measure of Discounted Future Net Cash Flows (Unaudited): 
+SFAS
+No.
+69, “Disclosures about Oil and Gas Producing Activities,” prescribes guidelines
+for computing a standardized measure of future net cash flows and changes
+therein relating to estimated proved reserves. The Company has followed these
+guidelines, which are briefly discussed below. 
+Future
+cash inflows and future production and development costs are determined by
+applying benchmark prices and costs, including transportation, quality and
+basis
+differentials, in effect at year-end to the year-end estimated quantities of
+oil
+and gas to be produced in the future. Each property the Company operates is
+also
+charged with field-level overhead in the estimated reserve calculation.
+Estimated future income taxes are computed using current statutory income tax
+rates, including consideration for estimated future statutory depletion. The
+resulting future net cash flows are reduced to present value amounts by applying
+a ten percent annual discount factor. 
+Future
+operating costs are determined based on estimates of expenditures to be incurred
+in developing and producing the proved oil and gas reserves in place at the
+end
+of the period, using year-end costs and assuming continuation of existing
+economic conditions, plus Company overhead incurred by the central
+administrative office attributable to operating activities. 
+F-31 
+The
+assumptions used to compute the standardized measure are those prescribed by
+the
+FASB and the Securities and Exchange Commission. These assumptions do not
+necessarily reflect the Company's expectations of actual revenues to be derived
+from those reserves, nor their present value. The limitations inherent in the
+reserve quantity estimation process, as discussed previously, are equally
+applicable to the standardized measure computations since these estimates are
+the basis for the valuation process. The following prices as adjusted for
+transportation, quality and basis differentials, were used in the calculation
+of
+the standardized measure: 
+2005 
+2004 
+2003 
+Gas
+(per Mcf) 
+$ 
+8.34 
+$ 
+5.80 
+$ 
+5.70 
+Oil
+(per Bbl) 
+$ 
+55.63 
+$ 
+40.06 
+$ 
+31.01 
+The
+following summary sets forth the Company's future net cash flows relating to
+proved oil and gas reserves based on the standardized measure prescribed in
+SFAS
+No. 69: 
+As
+of December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Future
+cash inflows 
+$ 
+6,979,279 
+$ 
+4,118,188 
+$ 
+3,232,605 
+Future
+production costs 
+(2,146,590 
+) 
+(1,349,380 
+) 
+(963,226 
+) 
+Future
+development costs 
+(385,379 
+) 
+(164,797 
+) 
+(101,935 
+) 
+Future
+income taxes 
+(1,448,444 
+) 
+(827,368 
+) 
+(735,947 
+) 
+Future
+net cash flows 
+2,998,866 
+1,776,643 
+1,431,497 
+10
+percent annual discount 
+(1,286,568 
+) 
+(742,705 
+) 
+(571,541 
+) 
+Standardized
+measure of discounted 
+future
+net cash flows 
+$ 
+1,712,298 
+$ 
+1,033,938 
+$ 
+859,956 
+The
+principle sources of change in the standardized measure of discounted future
+net
+cash flows are: 
+For
+the Years Ended December 31, 
+2005 
+2004 
+2003 
+(In
+thousands) 
+Standard
+measure, beginning of year 
+$ 
+1,033,938 
+$ 
+859,956 
+$ 
+581,862 
+Sales
+of oil and gas produced, net of 
+production
+costs 
+(590,671 
+) 
+(368,099 
+) 
+(299,044 
+) 
+Net
+changes in prices and production costs 
+725,154 
+166,826 
+168,661 
+Extensions,
+discoveries and other, net of 
+production
+costs 
+422,481 
+279,763 
+226,181 
+Purchase
+of minerals in place 
+132,185 
+73,875 
+178,264 
+Development
+costs incurred during the year 
+55,324 
+46,156 
+22,763 
+Changes
+in estimated future development costs 
+(42,710 
+) 
+(17,489 
+) 
+11,175 
+Revisions
+of previous quantity estimates 
+117,763 
+(24,271 
+) 
+45,551 
+Accretion
+of discount 
+150,112 
+125,175 
+78,869 
+Sales
+of reserves in place 
+(1,000 
+) 
+(3,906 
+) 
+(47,270 
+) 
+Net
+change in income taxes 
+(314,685 
+) 
+(75,389 
+) 
+(211,381 
+) 
+Changes
+in timing and other 
+24,407 
+(28,659 
+) 
+104,325 
+Standardized
+measure, end of year 
+$ 
+1,712,298 
+$ 
+1,033,938 
+$ 
+859,956 
+F-32 
+Note
+13 - Quarterly Financial Information (Unaudited) 
+The
+Company’s quarterly financial information for fiscal 2005 and 2004 is as follows
+(in thousands, except per share amounts): 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+Year
+Ended December 31, 2005 
+Total
+revenue 
+$ 
+143,818 
+$ 
+164,574 
+$ 
+203,304 
+$ 
+227,894 
+Less:
+costs and expenses 
+86,161 
+101,820 
+158,721 
+146,894 
+Income
+from operations 
+$ 
+57,657 
+$ 
+62,754 
+$ 
+44,583 
+$ 
+81,000 
+Income
+before income taxes and cumulative effect of change in accounting
+principle 
+$ 
+55,795 
+$ 
+60,578 
+$ 
+42,322 
+$ 
+79,542 
+Net
+income 
+$ 
+35,103 
+$ 
+38,261 
+$ 
+27,334 
+$ 
+51,238 
+Basic
+net income per common share 
+$ 
+0.61 
+$ 
+0.67 
+$ 
+0.48 
+$ 
+0.91 
+Diluted
+net income per common share 
+$ 
+0.54 
+$ 
+0.59 
+$ 
+0.42 
+$ 
+0.78 
+Dividends
+declared per common share 
+$ 
+0.05 
+$ 
+- 
+$ 
+0.05 
+$ 
+- 
+Year
+Ended December 31, 2004 
+Total
+revenue 
+$ 
+96,482 
+$ 
+102,151 
+$ 
+108,078 
+$ 
+126,388 
+Less:
+costs and expenses 
+60,603 
+65,566 
+71,575 
+83,440 
+Income
+from operations 
+$ 
+35,879 
+$ 
+36,585 
+$ 
+36,503 
+$ 
+42,948 
+Income
+before income taxes and cumulative effect of change in accounting
+principle 
+$ 
+34,535 
+$ 
+35,262 
+$ 
+35,125 
+$ 
+41,306 
+Net
+income 
+$ 
+21,449 
+$ 
+21,836 
+$ 
+22,565 
+$ 
+26,629 
+Basic
+net income per common share 
+$ 
+0.36 
+$ 
+0.38 
+$ 
+0.40 
+$ 
+0.46 
+Diluted
+net income per common share 
+$ 
+0.33 
+$ 
+0.34 
+$ 
+0.36 
+$ 
+0.41 
+Dividends
+declared per common share 
+$ 
+- 
+$ 
+0.025 
+$ 
+0.025 
+$ 
+- 
+F-33 
+SIGNATURES 
+Pursuant
+to the requirements of Section 13 or 15(d) of the Securities Exchange Act
+of
+1934, the registrant has duly caused this report to be signed on its behalf
+by
+the undersigned, thereunto duly authorized. 
+/ 
+ST. MARY LAND & EXPLORATION
+COMPANY 
+(Registrant) 
+Date:
+February 23, 2006 
+By: 
+/s/ MARK
+A.
+HELLERSTEIN 
+Mark
+A. Hellerstein 
+Chairman
+of the
+Board of Directors, President 
+and
+Chief Executive Officer 
+GENERAL
+POWER OF ATTORNEY 
+KNOW
+ALL
+PERSONS BY THESE PRESENTS, that each person whose signature appears below
+constitutes and appoints each of Mark A. Hellerstein and David W. Honeyfield
+his
+or her true and lawful attorney-in-fact and agent with full power of
+substitution and resubstitution, and each with full power to act alone, for
+the
+undersigned and in his or her name, place and stead, in any and all capacities,
+to sign any amendments to this Annual Report on Form 10-K for the fiscal
+year
+ended December 31, 2005, and to file the same, with exhibits thereto and
+other
+documents in connection therewith, with the Securities and Exchange Commission,
+hereby ratifying and confirming all that each of said attorney-in-fact, or
+his
+substitute or substitutes, may do or cause to be done by virtue
+hereof. 
+Pursuant
+to the requirements of the Securities Exchange Act of 1934, this report has
+been
+signed below by the following persons on behalf of the registrant and in
+the
+capacities and on the dates indicated. 
+Signature 
+Title 
+Date 
+/S/
+MARK A. HELLERSTEIN 
+Chairman
+of the Board of Directors, 
+February
+23, 2006 
+Mark
+A. Hellerstein 
+President
+and Chief Executive Officer 
+S/
+DAVID W. HONEYFIELD 
+Vice
+President-Chief Financial Officer, 
+February
+23, 2006 
+David
+W. Honeyfield 
+Secretary
+and Treasurer 
+/S/
+GARRY A. WILKENING 
+Vice
+President-Administration 
+February
+23, 2006 
+Garry
+A. Wilkening 
+and
+Controller 
+Signature 
+Title 
+Date 
+/S/
+BARBARA M. BAUMANN 
+Director 
+February
+23, 2006 
+Barbara
+M. Baumann 
+/S/
+LARRY W. BICKLE 
+Director 
+February
+23, 2006 
+Larry
+W. Bickle 
+/S/
+THOMAS E. CONGDON 
+Director 
+February
+23, 2006 
+Thomas
+E. Congdon 
+/S/
+WILLIAM J. GARDINER 
+Director 
+February
+23, 2006 
+William
+J. Gardiner 
+/S/
+WILLIAM D. SULLIVAN 
+Director 
+February
+23, 2006 
+William
+D. Sullivan 
+/S/
+JOHN M. SEIDL 
+Director 
+February
+23, 2006 
+John
+M. Seidl
\ No newline at end of file
diff --git a/raw/filings/0000893538/2005/0001144204-06-007665/item13.txt b/raw/filings/0000893538/2005/0001144204-06-007665/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..fcbd33f8165a276002cda4e4dcec8cbb2c46680a
--- /dev/null
+++ b/raw/filings/0000893538/2005/0001144204-06-007665/item13.txt
@@ -0,0 +1,10 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND
+RELATED
+TRANSACTIONS 
+The
+information required by this Item is incorporated by reference to the
+information provided under the caption “Certain Relationships and Related
+Transactions” in St. Mary’s definitive proxy statement for the 2006 annual
+meeting of stockholders to be filed within 120 days from
+December 31, 2005.
\ No newline at end of file
diff --git a/raw/filings/0000893538/2005/0001144204-06-007665/item9a.txt b/raw/filings/0000893538/2005/0001144204-06-007665/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2005/0001144204-06-007665/rp_note.txt b/raw/filings/0000893538/2005/0001144204-06-007665/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2005/0001144204-06-007665/rpt_disclosure.txt b/raw/filings/0000893538/2005/0001144204-06-007665/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e3fbe44da968650c5f17155bb8958c1a0aef78a1
--- /dev/null
+++ b/raw/filings/0000893538/2005/0001144204-06-007665/rpt_disclosure.txt
@@ -0,0 +1,16 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+Set forth below is a description of a related transaction between St. Mary and one of its officers during the last fiscal year. Some of the aspects of this
+transaction will continue in effect and may result in conflicts of interest between St. Mary and the individual. Although the person owes a fiduciary duty to St. Mary and its stockholders, we cannot
+assure you that conflicts of interest will always be resolved in favor of St. Mary. 
+As
+a result of his employment with another company prior to 1995, with which St. Mary engaged in a number of transactions, Kevin E. Willson, an executive officer of St. Mary during 2005
+and the first quarter of 2006, owns royalty interests in a number of our properties, which were earned as part of the prior employer's employee benefit programs. 
+St.
+Mary's Bylaws provide that no director, officer, or employee may pursue for his or her own account a business or investment opportunity if he or she has obtained knowledge of such
+opportunity through his or her affiliation with the Company. In addition, no officer or employee of St. Mary may pursue for his or her own account an oil and gas opportunity as to which his or her
+knowledge of the opportunity was not obtained through his or her affiliation with the Company unless (a) with respect to an officer of St. Mary, the officer's pursuit of the opportunity has
+been approved by the Board of Directors and (b) with respect to a nonofficer of St. Mary, the employee's pursuit of the opportunity has been approved by a senior officer of St. Mary with full
+knowledge of such opportunity. These 
+26 
+restrictions
+do not apply to the acquisition of less than one percent of the publicly traded stock of another company.
\ No newline at end of file
diff --git a/raw/filings/0000893538/2007/0000893538-08-000013/filing.txt b/raw/filings/0000893538/2007/0000893538-08-000013/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..991304ea7fd94d3e5fd5cfbaca54721ad208b8d0
--- /dev/null
+++ b/raw/filings/0000893538/2007/0000893538-08-000013/filing.txt
@@ -0,0 +1,13600 @@
+10-K
+1
+form10k_123107.htm
+FORM 10K
+form10k_123107.htm 
+UNITED
+STATES 
+SECURITIES
+AND EXCHANGE COMMISSION 
+Washington,
+D.C. 20549 
+FORM
+10-K 
+þ Annual
+Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
+1934 
+For the
+fiscal year ended December 31, 2007 
+or 
+o Transition
+Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
+1934 
+Commission
+file number 001-31539 
+ST. MARY
+LAND & EXPLORATION COMPANY 
+(Exact
+name of registrant as specified in its charter) 
+Delaware 
+(State
+or other jurisdiction 
+of
+incorporation or organization) 
+41-0518430 
+(I.R.S.
+Employer Identification No.) 
+1776
+Lincoln Street, Suite 700, Denver, Colorado 
+(Address
+of principal executive offices) 
+80203 
+(Zip
+Code) 
+(303)
+861-8140 
+(Registrant's
+telephone number, including area code) 
+Securities
+registered pursuant to Section 12(b) of the Act: 
+Title
+of each class 
+Name
+of each exchange on which registered 
+Common
+Stock, $.01 par value 
+New
+York Stock Exchange 
+Securities
+registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the
+registrant is a well-known seasoned issuer, as defined in Rule 405 of the
+Securities Act. Yes þ No
+o 
+Indicate by check mark if the
+registrant is not required to file reports pursuant to Section 13 or Section
+15(d) of the Act. Yes o No
+þ 
+Indicate
+by check mark whether the registrant (1) has filed all reports required to be
+filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
+preceding 12 months (or for such shorter period that the registrant was required
+to file such reports), and (2) has been subject to such filing requirements for
+the past 90 days. Yes
+þ No o 
+Indicate
+by check mark if disclosure of delinquent filers pursuant to Item 405 of
+Regulation S-K is not contained herein, and will not be contained, to the best
+of registrant’s knowledge, in definitive proxy or information statements
+incorporated by reference in Part III of this Form 10-K or any amendment to this
+Form 10-K. o 
+Indicate
+by check mark whether the registrant is a large accelerated filer, an
+accelerated filer, a non-accelerated filer, or a smaller reporting
+company. See the definitions of “large accelerated filer,”
+“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
+Exchange Act. (Check one): 
+Large
+accelerated filer þ 
+Accelerated
+filer o 
+Non-accelerated
+filer o (Do
+not check if a smaller reporting company) 
+Smaller
+reporting company o 
+Indicate
+by check mark whether the registrant is a shell company (as defined by Rule
+12b-2 of the Exchange Act). Yes
+o No þ 
+The
+aggregate market value of 62,317,450 shares of voting stock held by
+non-affiliates of the registrant, based upon the closing sale price of the
+common stock on June 29, 2007, the last business day of the registrant’s most
+recently completed second fiscal quarter, of $36.62 per share as reported on the
+New York Stock Exchange was $2,282,065,019. Shares of common stock
+held by each director and executive officer and by each person who owns 10
+percent or more of the outstanding common stock or who is otherwise believed by
+the Company to be in a control position have been excluded. This determination
+of affiliate status is not necessarily a conclusive determination for other
+purposes. 
+As of
+February 15, 2008, the registrant had 63,020,524 shares of common stock
+outstanding, which is net of 1,009,712 treasury shares held by the
+Company. 
+DOCUMENTS
+INCORPORATED BY REFERENCE 
+Certain
+information required by Items 10, 11, 12, 13 and 14 of Part III is incorporated
+by reference from portions of the registrant's definitive proxy statement
+relating to its 2008 annual meeting of stockholders to be filed within 120 days
+after December 31, 2007. 
+TABLE OF
+CONTENTS 
+ITEM 
+PAGE 
+PART
+I 
+ITEMS
+1 and 2. 
+BUSINESS
+and PROPERTIES 
+1 
+General 
+1 
+Strategy 
+1 
+Significant Developments in
+2007 
+2 
+Assets 
+4 
+Reserves 
+9 
+Production 
+10 
+Productive
+Wells 
+11 
+Drilling
+Activity 
+11 
+Acreage 
+12 
+Major
+Customers 
+12 
+Employees and Office
+Space 
+12 
+Title to
+Properties 
+13 
+Seasonality 
+13 
+Competition 
+13 
+Government
+Regulations 
+13 
+Cautionary Information about
+Forward-Looking Statements 
+15 
+Available
+Information 
+17 
+Glossary of Oil and Natural
+Gas Terms 
+17 
+ITEM
+1A. 
+RISK
+FACTORS 
+20 
+ITEM
+1B. 
+UNRESOLVED
+STAFF COMMENTS 
+29 
+ITEM
+3. 
+LEGAL
+PROCEEDINGS 
+29 
+ITEM
+4. 
+SUBMISSION
+OF MATTERS TO A VOTE OF SECURITY 
+HOLDERS 
+29 
+ITEM
+4A. 
+EXECUTIVE
+OFFICERS OF THE REGISTRANT 
+30 
+PART
+II 
+ITEM
+5. 
+MARKET
+FOR REGISTRANT’S COMMON EQUITY, 
+RELATED
+STOCKHOLDER MATTERS AND ISSUER 
+PURCHASES
+OF EQUITY SECURITIES. 
+32 
+ITEM
+6. 
+SELECTED
+FINANCIAL DATA 
+36 
+ITEM
+7. 
+MANAGEMENT’S
+DISCUSSION AND ANALYSIS OF 
+FINANCIAL
+CONDITION AND RESULTS OF OPERATIONS 
+38 
+Overview of the
+Company 
+38 
+Overview of Liquidity and
+Capital Resources 
+48 
+Critical Accounting Policies
+and Estimates 
+59 
+Additional Comparative Data in
+Tabular Format 
+62 
+Comparison of Financial
+Results and Trends between 
+2007
+and 2006 
+64 
+Comparison of Financial
+Results and Trends between 
+2006
+and 2005 
+66 
+Other Liquidity and Capital
+Resource Information 
+68 
+Accounting
+Matters 
+69 
+Environmental 
+70 
+TABLE OF
+CONTENTS 
+(Continued) 
+ITEM 
+PAGE 
+ITEM
+7A. 
+QUANTITATIVE
+AND QUALITATIVE DISCLOSURES ABOUT 
+MARKET
+RISK (included with the content of ITEM 7) 
+70 
+ITEM
+8. 
+FINANCIAL
+STATEMENTS AND SUPPLEMENTARY DATA 
+70 
+ITEM
+9. 
+CHANGES
+IN AND DISAGREEMENTS WITH ACCOUNTANTS 
+ON
+ACCOUNTING AND FINANCIAL DISCLOSURE 
+70 
+ITEM
+9A. 
+CONTROLS
+AND PROCEDURES 
+70 
+ITEM
+9B. 
+OTHER
+INFORMATION 
+73 
+PART
+III 
+ITEM
+10. 
+DIRECTORS,
+EXECUTIVE OFFICERS AND CORPORATE 
+GOVERNANCE 
+73 
+ITEM
+11. 
+EXECUTIVE
+COMPENSATION 
+73 
+ITEM
+12. 
+SECURITY
+OWNERSHIP OF CERTAIN BENEFICIAL 
+OWNERS
+AND MANAGEMENT AND RELATED 
+STOCKHOLDER
+MATTERS 
+73 
+ITEM
+13. 
+CERTAIN
+RELATIONSHIPS AND RELATED TRANSACTIONS, 
+AND
+DIRECTOR INDEPENDENCE 
+73 
+ITEM
+14. 
+PRINCIPAL
+ACCOUNTING FEES AND SERVICES 
+74 
+PART
+IV 
+ITEM
+15. 
+EXHIBITS
+AND FINANCIAL STATEMENT SCHEDULES 
+74 
+PART
+I 
+When we
+use the terms “St. Mary,” “the Company,” “we,” “us,” or “our,” we are
+referring to St. Mary Land & Exploration Company and its subsidiaries,
+unless the context otherwise requires. We have included technical
+terms important to an understanding of our business under “Glossary of Oil and
+Natural Gas Terms”. Throughout this document we make statements that
+are classified as “forward-looking”. Please refer to the “Cautionary
+Information about Forward-Looking Statements” section of this document for an
+explanation of these types of statements. 
+ITEMS
+1 and 2. BUSINESS and PROPERTIES 
+General 
+We are an
+independent oil and gas company engaged in the exploration, exploitation,
+development, acquisition, and production of natural gas and crude
+oil. We were founded in 1908 and incorporated in Delaware in
+1915. Our initial public offering of common stock took place in
+December of 1992. The common stock of the Company trades on the New
+York Stock Exchange under the ticker “SM”. 
+Our
+principal offices are located at 1776 Lincoln Street, Suite 700, Denver,
+Colorado 80203, and our telephone number is (303) 861-8140. 
+Strategy 
+Our
+objective is to build stockholder value through consistent economic growth in
+reserves and production that increases net asset value per share. We
+seek to invest in oil and gas producing assets that result in a superior return
+on equity while preserving underlying capital, resulting in a return on equity
+to stockholders that reflects capital appreciation as well as the payment of
+cash dividends. 
+The
+majority of our current senior technical managers in each region possess between
+20 and 30 years of industry experience and lead fully-staffed regional technical
+offices that are supported by centralized administration from our corporate
+office in Denver. We use our comprehensive base of geological,
+geophysical, land, engineering, and production experience in each of our core
+operating areas to source prospects for our ongoing low-to-medium-risk
+development and exploitation programs. We conduct detailed geologic
+studies and use an array of technologies and tools including 2-D and 3-D seismic
+imaging, hydraulic fracturing and other reservoir stimulation techniques,
+horizontal drilling, secondary recovery, and specialized logging tools to
+enhance the potential of our existing properties. We believe that
+having fully-staffed technical teams based in each of our operating regions is
+an advantage in that our regional offices are staffed with personnel that have a
+deep knowledge of the basins in which they work, participate in the regional
+deal flow and prefer to live in regional areas, which minimizes personnel
+attrition. 
+Acquisitions
+have been a key element of our business strategy. Historically, we
+have been most successful in acquiring properties on a negotiated basis, as
+opposed to participating in widely marketed auctions for
+properties. In the last two years we have made several
+large acquisitions. In 2007, we paid $178.9 million for two
+acquisitions in South Texas for properties targeting the Olmos shallow gas
+formation. In 2006, we paid $243.1 million to acquire assets that
+target the Wolfberry section in the Permian Basin. 
+We divest
+selected non-core assets when market conditions and prices are
+attractive. We will continue to evaluate such opportunities in the
+future when we believe it to be appropriate. During 2007, we sold
+properties with estimated proved reserves of 1.4 BCFE. We
+actively marketed and contracted to sell a package of non-core assets in
+2007. This sale closed on January 31, 2008, for a total adjusted
+sales price of $131.1 million before commissions; this sale represented
+40.4 BCFE of our year-end 2007 proved reserves. We utilized a
+1031 reverse exchange structure to defer the recognition of income tax on the
+gain from this sale. 
+Conservative
+use of financial leverage has long been a critical element of our
+strategy. We believe that maintaining a strong balance sheet is a
+significant competitive advantage that enables us to pursue acquisitions
+and 
+1 
+other
+opportunities, particularly in weaker price environments. It also
+provides us with the financial resources to weather periods of volatile
+commodity prices or escalating costs. Our debt to book capitalization
+ratio was 40 percent at the end of December 2007. The
+proceeds from the aforementioned property sale in January 2008 were applied to
+reducing bank borrowings. 
+In
+summary, we believe that our dedication to making investment decisions based on
+net asset value per share, our long-standing geologic and engineering experience
+in the regions in which we operate, our appropriate application of technology,
+our established networks of local industry relationships, and our measured
+approach to acquisitions and divestitures all provide us with competitive
+advantages that we can use to continue growing the Company. 
+Significant
+Developments in 2007 
+· 
+Increase in 2007 Year-End
+Reserves. Proved reserves increased 17 percent to
+1,086.5 BCFE at December 31, 2007, from 927.6 BCFE at December 31,
+2006. We added 132.1 BCFE from our drilling program and 94.8
+BCFE from acquisitions. We had a positive revision of 40.9 BCFE
+which consisted of a 6.4 BCFE upward performance revision and an upward
+revision of 34.5 BCFE due primarily to increased oil prices at the end of
+2007. The 2007 acquisition volumes are lower than the initial
+estimates previously disclosed as a result of the final year-end reservoir
+engineering estimation. We sold properties with reserves of 1.4
+BCFE in 2007. 
+· 
+Drilling
+Results. Reserve additions from drilling activities of
+132.1 BCFE were driven by results in the Mid-Continent, Rocky Mountain,
+ArkLaTex, and Permian regions, with those regions contributing 37 percent,
+21 percent, 20 percent, and 18 percent,
+respectively. Additions in the Mid-Continent were driven
+principally by successful drilling by us and others in the horizontal
+Woodford shale formation in the Arkoma Basin, as well as positive results
+in two programs in the Anadarko Basin. In the Rocky Mountain
+region, the largest contribution came from the Hanging Woman Basin where
+we added 9.9 BCFE of proved reserves. The ArkLaTex region added
+26.2 BCFE from successful drilling operations in the James Lime carbonate
+program and Elm Grove Field. Successful results in the
+Wolfberry program in 2007 were the principal driver of drilling additions
+in the Permian Basin. 
+· 
+New Basin Entry in
+2007. In 2007 we spent $182.9 million for acquisitions
+of proved and unproved oil and gas properties. We entered the
+greater Maverick Basin with two acquisitions in South Texas totaling
+$178.9 million that target the Olmos shallow gas formation. The
+first was the $30.0 million Catarina acquisition that closed in June
+2007. The more significant transaction was the $148.9 million
+Rockford acquisition that closed in October 2007. These
+properties added a sizeable inventory of lower risk drilling locations to
+our portfolio. Consistent with prior acquisitions, we hedged
+several years of the risked production related to these acquisitions at
+the time of acquisition. The remaining acquisitions in 2007
+were small niche transactions throughout the year in the Mid-Continent,
+ArkLaTex, and Rocky Mountain
+regions. 
+· 
+Senior and Regional Management
+Changes. During 2007, the Company underwent or announced
+personnel changes in the chief executive position and in several regional
+manager positions. On February 23, 2007, Mark Hellerstein
+retired as Chief Executive Officer after serving in that role since
+1995. Tony Best, President of the Company, was appointed as
+Chief Executive Officer on that date. Mr. Hellerstein
+continues to serve as the Chairman of the Board. In June of
+2007, Jerry Schuyler, the Senior Vice President responsible for the Gulf
+Coast and Permian regions, left St. Mary to pursue another professional
+opportunity. Greg Leyendecker, then Operations Manager for the
+Gulf Coast region, assumed responsibility for the Gulf Coast and is now
+Vice President - Regional Manager of the Gulf Coast region. We
+also made the Midland office a stand-alone regional office headed by
+Lehman Newton III, Vice President - Regional Manager of our Permian
+region. Mr. Leyendecker and Mr. Newton joined St. Mary in
+2006 and each have over 25 years of management and operational experience
+in the oil and gas industry. In July 2007, Stephen Pugh joined
+the Company as Senior Vice President and Regional Manager of the ArkLaTex
+region. Mr. Pugh succeeded David Hart, who retired from St.
+Mary after 15 years in various roles at the Company. Mr. Pugh
+came to St. Mary with over 25 
+2 
+years
+of engineering, operations, and business development experience in the oil
+and gas industry. In August of this year, Robert Nance, Senior
+Vice President - Regional Manager of the Rocky Mountain region, announced
+his decision to retire in the first quarter of 2008 after more than 40
+years in the oil and gas industry. Mark Mueller joined us as
+Senior Vice President in August and now leads our Rocky Mountain
+region. Mr. Mueller has over 20 years of management and
+technical experience in the oil and gas industry. Effective
+January 1, 2008 Mark Mueller was appointed Senior Vice President -
+Regional Manager. Subsequent to year end, David Honeyfield,
+Senior Vice President - Chief Financial Officer, announced that he will
+resign as an officer of St. Mary on March 21, 2008, in order to pursue an
+opportunity in an unrelated industry. An external search for
+his successor is underway at the time of this
+filing. 
+· 
+2007 Capital Markets
+Activity. In March of 2007 we called for redemption of
+the then outstanding $100.0 million 5.75% Senior Convertible Notes. 
+The notes had a conversion price of $13.00 per share. One hundred
+percent of the holders of the notes elected to convert their notes into
+shares of common stock. As a result of the conversion, 7.7 million
+shares of stock were issued to the note holders. This resulted in a
+decrease to long-term debt of $100.0 million, and an increase to common
+stock associated with the conversion together with the recognition of the
+excess tax benefit associated with the contingent interest feature
+associated with the notes. 
+In April
+of 2007, we completed the sale of $287.5 million of 3.50% Senior
+Convertible Notes. The net proceeds from the 3.50% Senior Convertible
+Notes were used to repay outstanding borrowings under our revolving credit
+facility. 
+· 
+Significant Volatility in
+Commodity Prices. During 2007, the exploration and
+production sector was impacted by volatility in the prices for crude oil
+and natural gas. Our operations and financial conditions were
+significantly impacted by these prices. Our crude oil is sold
+on contracts that pay us the average of posted prices for the period in
+which the crude oil is sold. NYMEX crude oil began 2007 with an
+average January price of $54.67 per barrel and increased steadily
+throughout the year, reaching an average monthly high for the year of
+$94.63 per barrel in November. The average NYMEX price for the
+year was $72.34 per barrel. Geopolitical unrest in various
+producing regions overseas and concerns domestically related to refinery
+utilization and petroleum product inventories were the principal drivers
+of the increase in oil prices in
+2007. 
+We sell
+the majority of our natural gas on contracts which are based on first of the
+month (also frequently referred to as bid week) index pricing. The
+Inside FERC bid week price for Henry Hub, a widely used industry measuring
+point, averaged $6.86 per MMBtu in 2007, which was five percent lower than
+the average for 2006. High levels of natural gas in storage had an
+impact on pricing during 2007 as inventory levels exceeded the five year average
+for all of 2007. Concerns about supply overhang peaked for the year
+around September of 2007, leading to the lowest Henry Hub price for the year of
+$5.43 per MMBtu. The impact was more acute in the Rocky Mountain
+region where bid week prices were driven down to $2.13 per MMBtu and $1.11 per
+MMBtu for September and October, respectively, on the Colorado Interstate Gas
+(CIG) index. A significant portion of our production in the Rockies
+is oil and we had limited exposure to the CIG hub. Additionally,
+recent acquisitions have added a richer gas stream to our overall production
+mix. The value received associated with natural gas liquids (NGLs)
+from this rich gas stream align more closely with crude oil
+prices. The increase in crude prices has had a similar impact on
+prices for NGLs, and as a result we have enjoyed higher realized natural gas
+prices. We hedge a portion of our oil and gas production using
+swaps and collars. A gain of $58.7 million was realized on our
+natural gas hedges for the year and a loss of $34.3 million was realized on
+our oil hedges for the year. 
+· 
+Repurchase of Common
+Stock. In 2007, we repurchased a total of 792,216 shares of our
+common stock in the open market for a weighted-average price of $32.76 per
+share, including commissions, under this program. At the time
+we repurchased our shares, we entered into hedges for a commensurate
+amount of our production that was represented by the share repurchase in
+order to lock in the discounted price at which our shares were
+trading. As of the date of this filing, we
+are 
+3 
+authorized
+by the Board to repurchase 5,207,784 additional shares under this
+program. The shares may be repurchased from time to time in
+open market transactions or in privately negotiated transactions, subject
+to market conditions and other factors, including certain provisions of
+our existing credit facility agreement and compliance with securities
+laws. Stock repurchases may be funded with existing cash
+balances, internal cash flow, and borrowings under the credit
+facility. 
+Assets 
+As of
+December 31, 2007, we had estimated proved reserves of 78.8 MMBbl
+of oil and 613.5 Bcf of natural gas. Prices in effect on
+December 31, 2007, used to estimate proved reserves were $6.80 per MMBtu of gas
+and $95.98 per barrel of oil. On an equivalent basis, our proved
+reserves were 1,086.5 BCFE as of December 31, 2007, an increase of 17
+percent from 927.6 BCFE at the end of the prior year. The increase in
+proved reserves in 2007 was the result of development activities and
+acquisitions. On an equivalent basis, 77 percent of our proved
+reserves are classified as proved developed as of year-end. Total
+proved oil and gas reserves have a before income tax PV-10 value of
+$3.9 billion and a standardized measure value, which includes the effect of
+income taxes, of $2.7 billion (a reconciliation between these two amounts
+is shown under Reserves in Part I, Items 1 and 2). During 2007, our
+average daily production was 181.0 MMcf of gas and 18.9 MBbl of oil, for an
+average equivalent production rate of 294.5 MMCFE per day, which is a new annual
+record for us. We sold certain non-core oil and gas properties
+subsequent to year end; all production and reserve information presented is
+before the impact of this sale unless otherwise noted. 
+Our
+reserve replacement percentage – including sales for 2007 was 248 percent, which
+includes 1.4 BCFE of asset sales that occurred during the year. Our
+reserve replacement percentage – excluding sales was
+249 percent. We acquired 94.8 BCFE of proved reserves through
+acquisitions in 2007, the majority of which relate to the two Olmos shallow gas
+acquisitions in South Texas. We believe the use of the phrase
+“reserve replacement percentage” is widely understood by those who make
+investment decisions related to the oil and gas exploration
+business. We believe that this measure is useful in evaluating and
+comparing exploration and production companies and provides a measure of the
+growth of a company. The Glossary includes a definition of “reserve
+replacement percentage” and description of how it is calculated. 
+In 2007,
+we invested a total of $926.1 million on drilling activities and
+acquisitions. This was 15 percent higher than the $805.5 million
+invested in 2006. Drilling investments, including leasing activity,
+in 2007 of $740.9 million comprised 80 percent of our total capital investment
+budget for the year and compares to $522.6 million in 2006. The
+increase in drilling activity was driven primarily by development of the Sweetie
+Peck asset in the Permian Basin that was acquired in late 2006 as well as
+increases in activity in our ArkLaTex region. We invested $185.2
+million on acquisitions in 2007, the majority of which related to the two
+acquisitions in South Texas targeting the Olmos shallow gas play. 
+We have
+$626 million budgeted for development and exploration investments in 2008, which
+is a decrease of 16 percent from the $740.9 million invested in drilling
+activities in 2007. The decrease in investment year over year is a
+reflection of our goal to improve our capital efficiency and to invest within
+our cash flow from operations in order to maintain financial flexibility so that
+we can deploy additional capital where warranted in order to make accretive
+acquisitions, repurchase stock, or repay debt. 
+4 
+Our
+operations are currently concentrated in five core operating areas in the United
+States. The following table summarizes the production and proved
+reserves and PV-10 value of our core operating areas as of
+December 31, 2007. 
+ArkLaTex 
+Mid- 
+Continent 
+Gulf
+Coast 
+Permian 
+Rocky 
+Mountain 
+Total 
+2007
+Proved Reserves: 
+Oil
+(MMBbl) 
+1.0 
+1.5 
+0.9 
+20.0 
+55.4 
+78.8 
+Gas
+(Bcf) 
+163.9 
+192.4 
+111.3 
+34.7 
+111.2 
+613.5 
+Equivalents
+(BCFE) 
+170.1 
+201.3 
+116.8 
+154.7 
+443.6 
+1,086.5 
+Relative
+percentage 
+15% 
+19% 
+11% 
+14% 
+41% 
+100% 
+Proved
+Developed % 
+52% 
+88% 
+48% 
+69% 
+92% 
+77% 
+PV-10
+Value (in millions) 
+$ 
+380.3 
+$ 
+585.5 
+$ 
+361.6 
+$ 
+824.2 
+$ 
+1,709.6 
+$ 
+3,861.2 
+Relative
+percentage 
+10% 
+15% 
+9% 
+21% 
+45% 
+100% 
+2007
+Production: 
+Oil
+(MMBbl) 
+0.1 
+0.5 
+0.2 
+1.4 
+4.7 
+6.9 
+Gas
+(Bcf) 
+13.0 
+30.9 
+9.0 
+2.4 
+10.8 
+66.1 
+Equivalent
+(BCFE) 
+13.8 
+34.0 
+10.3 
+10.7 
+38.7 
+107.5 
+Avg.
+Daily Equivalents (MMCFE/d) 
+37.8 
+93.2 
+28.2 
+29.3 
+106.0 
+294.5 
+Relative
+percentage 
+13% 
+31% 
+10% 
+10% 
+36% 
+100% 
+Note: The
+table above includes production and proved reserves related to non-core assets
+that were divested on January 31, 2008. The properties
+divested were primarily in the Mid-Continent and Rocky Mountain
+regions. These non-core properties contributed 5.0 BCFE of
+production during 2007 and represented 40.4 BCFE of proved reserves at
+December 31, 2007. 
+ArkLaTex
+Region . St. Mary’s operations in the ArkLaTex region are
+managed from our office in Shreveport, Louisiana. The ArkLaTex region
+was the first operating office for the Company, originating from an acquisition
+in 1992. For years the activities of this region focused on the tight
+sandstone Cotton Valley and Travis Peak formations in the region. In
+recent years, we have utilized horizontal wells in the development of limestone
+carbonates found in the region, particularly the James Lime
+formation. 
+The
+ArkLaTex region invested $149.8 million in 2007 on exploration,
+development, and acquisition activities, which is 70 percent higher than
+the $88.0 million spent in 2006. The primary drivers of this
+increase in capital were increased activity levels in our James Lime and Cotton
+Valley programs during the year. In the St. Mary operated
+horizontal James Lime program, we operated one rig continuously throughout
+2007. We continued to see solid results in proven development areas
+and had two successful wells that extended the play westward by approximately 75
+miles. The Cotton Valley programs at Elm Grove and Terryville fields
+were areas of significant investment in 2007, although these are operated by
+other companies. At Elm Grove Field, advancements such as 20-acre
+increased density drilling, commingling of production of the Cotton Valley and
+Hosston formations, and horizontal drilling have benefited us, particularly as
+development has moved into areas where we have larger working
+interests. Even though operations at Terryville Field are more
+difficult due to the formation being deeper and more highly pressured than the
+Cotton Valley formation at Elm Grove Field, operations in the field were highly
+successful in 2007 and allowed for sustained activity during the
+year. The region’s 2007 production increased 31 percent to
+13.8 BCFE. Our proved reserves at year-end 2007 were
+170.1 BCFE, a seven percent increase over 2006 year-end proved
+reserves of 159.5 BCFE. On a forward looking basis, we expect
+that proved reserves in this area will be booked on 20 acre spacing as the
+in-fill program at Elm Grove Field continues and additional locations become
+permitted. We have not however booked these locations as proved
+reserves at year end due to the Securities and Exchange Commission technical
+requirement of needing to have an “alternate unit” permitting process completed
+prior to booking such items as proved reserves. 
+5 
+The Elm Grove Field is the highest
+value field in the ArkLaTex region at year-end 2007, with proved reserves of
+85.3 BCFE and a PV-10 value of $161.3 million. Elm Grove
+comprises roughly 42 percent of the region’s PV-10 value and approximately
+four percent of our entire PV-10 value. We own interests in 382 producing wells
+in the field with many of those wells having uphole recompletion potential in
+the future. Our working interest in the field is as high as 37
+percent; higher working interests are located in the southern portion of the
+acreage where recent activity has been occurring. Reserves in this
+field are primarily natural gas. 
+Our
+capital budget for the ArkLaTex region in 2008 is $161 million, 51 percent
+of which will be operated by us. The largest portion of this year’s
+budget relates to Cotton Valley programs, where 50 percent of the region’s
+capital will be deployed. Of the capital allocated for Cotton Valley
+programs, 60 percent will be invested at Elm Grove Field where development
+continues to be highly successful. Development of the field on
+20-acre spacing continues to drive activity levels, and a successful horizontal
+well completed at the end of 2007 could set the stage for horizontal development
+at Elm Grove Field. The remaining Cotton Valley allocation for 2008
+will be split roughly evenly between the program at Terryville Field and the St.
+Mary operated program at Carthage. Our operated horizontal James Lime
+program will represent 34 percent of the region’s 2008 budget. We
+plan to operate two drilling rigs throughout the year, with plans to drill more
+than 20 horizontal James Lime wells in 2008. 
+Mid-Continent
+Region . St. Mary has
+been active in the Mid-Continent region since 1973. Operations for
+the region are managed by our office in Tulsa, Oklahoma. We have been
+active in the Anadarko Basin of western Oklahoma since our entry into the region
+and our primary focus in the region is currently on the Atoka and Granite Wash
+formations. In recent years we have begun operating in the Arkoma
+Basin in eastern Oklahoma where the current focus is on horizontal development
+of the Woodford shale, although the Wapanucka limestone and Cromwell sandstone
+also appear to have commercial potential. The Mid-Continent region
+oversees our assets in Constitution South Field in Jefferson County,
+Texas. Our long history of operations and proprietary geologic
+knowledge in the region enables us to sustain economic development and
+exploration programs despite periods of adverse industry
+conditions. We apply current technology through the use of hydraulic
+fracturing, innovative well completion techniques, and horizontal drilling to
+accelerate production and associated cash flow from the region’s tight gas
+reservoirs and developing plays. 
+In 2007,
+we invested $185.7 million in the
+Mid-Continent region on exploration, development, and acquisition activity,
+which is 13 percent less than the $214.3 million deployed in
+2006. Throughout 2007, we maintained a consistent level of activity
+in the Arkoma Basin working on the Woodford shale program as we continued to
+refine our understanding of the play. We decreased our activity in
+the Atoka/Granite Wash development program as we developed more cost efficient
+completion designs for these wells. Mid-Continent production in 2007
+was 34.0 BCFE, an increase of 14 percent from the 29.8 BCFE
+produced in 2006. Proved reserves at the end of 2007 were
+201.3 BCFE, an increase of 18 percent from the 170.7 BCFE report for the
+prior year. 
+The
+Constitution South Field is the highest value field in the Mid-Continent region
+with reserves of 15.2 BCFE and a PV-10 value of $115.1
+million. This field also contributed 8.6 BCFE of production in
+2007, which represents approximately eight percent of our total
+production. Three wells, the Paggi Broussard #1, the Paggi Broussard
+# 2, and the Loretta B. Casey #1, comprise the majority of reserves, PV-10
+value, and production in the Constitution South Field. These wells
+historically have performed better than anticipated and we have a history,
+including at year-end 2007, of recognizing upward performance revisions in our
+proved reserves at this field. 
+The 2008
+capital expenditure budget for the Mid-Continent region is $135.0 million,
+69 percent of which we will operate. The largest component of
+the budget is our program targeting the Woodford shale using horizontal wells in
+the Arkoma basin, where roughly 30 percent of the region’s budget will be
+invested. After mixed results in the horizontal Woodford shale
+program in the first half of 2007, we had a series of successful wells in the
+latter part of the year which we believe validates our understanding of the well
+and completion design being used currently in this program. Our
+budget anticipates that we will drill ten horizontal Woodford wells with two
+operated rigs in the first half of 2008, and continue to participate with our
+partners in outside operated wells. With continued success in the
+play, we have the ability to increase activity and our capital investment in the
+program in the latter part of 2008. In 2008, we plan to continue with
+an exploration program in the Anadarko 
+6 
+Basin
+that yielded encouraging results in 2007. This exploration program
+targets deeper formations of the basin. We also plan to deploy
+approximately 27 percent of the region’s 2008 capital budget to drill six
+exploratory test wells in this program. In the Western Oklahoma
+Washes program in the Anadarko Basin, which we have referred to previously as
+the Mayfield development area, we plan to invest roughly 17 percent of the
+year’s budget in this program that targets the Atoka and Granite Wash
+formations. The area is a known hydrocarbon province, and efforts in
+2008 will be directed toward improving the geotechnical effort applied
+to the program and revising drilling and completion techniques. 
+Gulf Coast
+Region . St. Mary’s presence in south Louisiana dates to
+the early 1900s when our founders acquired our namesake property in
+St. Mary Parish, Louisiana abutting the Gulf of Mexico. These
+24,914 acres of fee lands yielded $3.7 million of gross oil and gas royalty
+revenue in 2007. Our Gulf Coast regional presence expanded as a
+result of the acquisition of King Ranch Energy, Inc. in 1999. During
+2007 we reached a significant inflection point in this region as it shifted from
+an office centered on geotechnically driven exploration to one focused on
+repeatable development and exploitation with our acquisition of two Olmos
+shallow gas assets in South Texas. The Gulf Coast region is run from
+our office in Houston, Texas. 
+Our
+capital expenditures for exploration, development, and acquisition activity in
+the Gulf Coast region grew significantly from $65.5 million in 2006 to
+$278.5 million in 2007, primarily driven by two significant
+acquisitions. 
+The
+majority of our 94.8 BCFE of acquisitions, classified as purchases of minerals
+in place, were in the Gulf Coast region. These were the $150.3
+million Rockford acquisition that closed in October 2007 and the $30.4 million
+Catarina acquisition which closed in April 2007, both of which target the Olmos
+shallow gas formation and are located in the greater Maverick Basin in
+Southwestern Texas. Final year-end reserve estimates related to these
+acquisitions are lower than the initial estimates we previously disclosed,
+partly due to the fact that our presentation of reserves at the time of the
+acquisition was on a dry gas basis whereas our annual report on Form 10-K
+disclosures utilize a wet gas presentation. This accounted for
+approximately ten BCFE of the difference in volumes, without any impact to
+value. The remaining difference was based on our final year-end
+assessment of proved non-producing reserves and our proved undeveloped reserves,
+which were each lower than the amounts estimated at the time of
+acquisition. Our emphasis in 2007 was on the successful integration
+of our newly acquired properties. While the core focus of the region
+shifted toward onshore projects, we continued to be active offshore in
+2007. A previously discovered intermediate deepwater project, Zloty,
+began production late in 2007 and we continue to work to advance other
+intermediate deepwater projects in which we are a partner. We were
+also active closer to shore with a mixed program that included the successful
+Reno, Clement, and Amber Jack wells. Gulf Coast production in 2007
+was 10.3 BCFE, an increase of six percent from the 9.7 BCFE
+produced in 2006. Proved reserves at the end of 2007 were
+116.8 BCFE, an increase of 263 percent from the 32.2 BCFE reported for the
+prior year. The disparity between the production growth and reserve
+growth for the Gulf Coast region in 2007 is attributable to the acquisitions
+previously discussed. 
+The most
+significant asset in the Gulf Coast region is the Gold River project area that
+was acquired in October of 2007 as part of the Rockford
+acquisition. The Gold River project area has 104 producing wells as
+of year end. At December 31, 2007, this project area had a
+PV-10 value of $136.9 million with 53.6 BCFE of proved reserves and
+accounts for approximately four percent of our entire PV-10
+value. The acquisition of these assets, together with the Catarina
+assets, represents the most recent resource play entry for the
+Company. 
+Our
+development and exploration budget in the Gulf Coast region for 2008 is
+$80 million and is focused primarily on the development of the Olmos assets
+acquired in 2007. St. Mary will operate 75 percent of the planned
+capital investment next year. Roughly $38 million, or 47 percent, of
+the budget will be dedicated to grass roots Olmos wells and approximately $10
+million, or 12 percent, of the budget will be spent on Olmos
+recompletions. 
+Permian Basin
+Region . The Permian Basin
+area covers a significant portion of western Texas and eastern New Mexico and is
+one of the major producing basins in the United States. Our holdings
+in the Permian Basin began with a series of property acquisitions in
+1996. In December 2006, we made a $240.6 million
+acquisition of predominately oil properties in the Sweetie Peck project
+area. To manage the significant increase in operated properties
+associated with the Sweetie Peck acquisition, we opened a regional office in
+Midland, Texas in early February 2007. 
+7 
+In 2007,
+we spent $135.1 million in the region. The majority of this capital
+was deployed to develop projects that target the Wolfberry tight oil play, which
+targets the stacked carbonate Wolfcamp and Spraberry formations found in the
+basin. We participated in two substantial Wolfberry programs during
+2007 – the operated Sweetie Peck program and the outside operated program at
+Halff East. We operated between two and five drilling rigs at Sweetie
+Peck throughout 2007. At Halff East, our operating partner had two
+drilling rigs running throughout the year. We also invested capital
+in the Parkway and East Shugart Delaware waterflood
+projects. Production in the region increased 234 percent over
+the prior year, from 3.2 BCFE in 2006 to 10.7 BCFE in 2007. Proved
+reserves as of the end of 2007 were 154.7 BCFE, which is an increase of
+nine percent from 2006 year-end reserves of 142.2 BCFE. 
+As of the
+end of December 2007, the Sweetie Peck assets in the Permian Basin
+represented a PV-10 value of $438.0 million with 77.7 BCFE of proved
+reserves. This accounts for approximately 11 percent of our
+entire PV-10 value. The Sweetie Peck assets had 106 producing wells
+and 47 proved undeveloped reserve locations as of the end of 2007. 
+The
+capital budget for 2008 in the region is $120 million, of which 74 percent
+will be operated by us. Of this amount, roughly $103 million, or 86
+percent, will be invested in Wolfberry projects. At Sweetie Peck, we
+plan to spend approximately $77 million operating three drilling rigs
+continuously throughout the year. Included in this amount are
+investment dollars to test several 40-acre pilot areas, which if successful
+could add meaningful proved reserves. At Halff East, we will invest
+approximately $25 million with our operating partner. We will also
+invest a small amount of capital in several smaller programs, including our
+Delaware waterfloods. 
+Rocky Mountain
+Region . St. Mary has
+conducted operations in the Williston Basin in eastern Montana and western North
+Dakota since 1991. The region is managed by our office in Billings,
+Montana. In recent years, we have expanded our operations into the
+Greater Green River, Powder River, Big Horn, and Wind River basins of Wyoming
+through a series of acquisitions. The largest growth in the region
+came in late 2002 and early 2003 with significant property acquisitions from
+Choctaw, Burlington Resources, and Flying J. These transactions
+brought with them a tremendous acreage position that has precipitated additional
+growth in this region. 
+Including
+the Hanging Woman Basin coalbed methane project, we invested $178.3 million
+in 2007 on exploration, development, and acquisitions in the Rocky Mountain
+region, compared to $161.3 million in 2006. The 2007 program was
+focused on a horizontal development in the Mississippian formations of the
+Williston Basin, and the drilling of Bakken formation infill locations in
+Montana and Red River locations. Additionally, 2007 saw an
+acceleration of drilling at Hanging Woman Basin. Proved reserves for
+the Rocky Mountain region were 443.6 BCFE at year-end, up five percent from
+422.9 BCFE as of year end 2006. Production in the Rocky Mountain
+region for 2007 was 38.7 BCFE. Total regional production was down two
+percent from 39.5 BCFE in 2006. 
+Included
+in the Rocky Mountain region is the coalbed methane project at Hanging Woman
+Basin. This program is of particular interest because of the large
+resource potential on our leasehold. In 2007, we invested $35.7
+million at Hanging Woman Basin compared to $30.4 million in 2006. Proved
+reserves in this project grew 20 percent in 2007 to 40.2 BCFE, 75 percent of
+which were proved developed. Hanging Woman Basin had 33.4 BCFE in
+proved reserves at December 31, 2006, 91 percent of which were proved
+developed. Production was 3.0 BCFE for the year ended 2007, up 49
+percent from production in 2006. 
+The Elm
+Coulee Field is the highest value field in the region at year-end 2007, with 92
+producing wells and proved reserves of 42.4 BCFE and a PV-10 value of
+$236.5 million. The reserves in this field are predominately oil
+and the Bakken is the formation of primary interest. This field
+comprises approximately six percent of our entire PV-10 value. 
+Our
+capital budget for the Rocky Mountain region is $130 million for 2008, with
+roughly $24 million budgeted for activities for Hanging Woman Basin coalbed
+methane. We will operate roughly 65 percent of our planned regional
+investment in 2008. In the conventional Rockies program, several
+vertical wells and two recompletions in the Red River are planned for the
+year. We also plan to drill a small number of horizontal Bakken wells
+in and around our historic Bakken development areas in
+Montana. Workover and recompletion 
+8 
+operations
+are planned in our Wind River Basin and Big Horn Basin oil
+properties. At the outside operated Atlantic Rim coalbed methane play
+in the Green River Basin, we expect to see activity ramp up since regulatory and
+environmental delays appear to have been resolved. At Hanging Woman
+Basin, we plan to moderate our drilling activity in 2008 and monitor and
+evaluate the results of the shallow and intermediate pods and deep horizontal
+programs from previous year’s drilling efforts. 
+Reserves 
+The
+following table presents summary information with respect to the estimates of
+our proved oil and gas reserves for each of the years in the three-year period
+ended December 31, 2007. For all years presented
+Netherland, Sewell and Associates, Inc. (“NSAI”) prepared the reserve
+information for the Company’s coalbed natural gas projects at Hanging Woman
+Basin in the northern Powder River Basin and St. Mary’s non-operated coalbed
+methane interest in the Green River Basin. We engaged Ryder Scott
+Company, L.P. to review internal engineering estimates for 80 percent of
+the PV-10 value of our proven conventional oil and gas reserves in 2007 and
+2006. In 2005, Ryder Scott Company, L.P. prepared the reserve
+estimates for at least 80 percent of the PV-10 value of our conventional
+oil and gas assets. St. Mary personnel prepared the reserve
+estimates for the remainder of all properties. The Company emphasizes
+that reserve estimates are inherently imprecise and that estimates of new
+discoveries and undeveloped locations are more imprecise than estimates of
+established producing oil and gas properties. Accordingly, these
+estimates are expected to change as future information becomes
+available. The PV-10 values shown in the following table are not
+intended to represent the current market value of the estimated proved oil and
+gas reserves owned by St. Mary. Neither prices nor costs have
+been escalated. You should read the following table along with the
+section entitled “Risk Factors – Risks Related to Our Business – The actual
+quantities and present values of our proved oil and natural gas reserves may be
+less than we have estimated.” No estimates of our proved reserves
+have been filed with or included in reports to any federal authority or agency,
+other than the Securities and Exchange Commission, since the beginning of the
+last fiscal year. 
+As
+of December 31, 
+Proved
+Reserves Data: 
+2007 
+2006 
+2005 
+Oil
+(MMBbl) 
+78.8 
+74.2 
+62.9 
+Gas
+(Bcf) 
+613.5 
+482.5 
+417.1 
+BCFE 
+1,086.5 
+927.6 
+794.5 
+Standardized
+measure of discounted 
+future
+net cash flows (in thousands) 
+$ 
+2,706,914 
+$ 
+1,576,437 
+$ 
+1,712,298 
+PV-10
+value (in thousands) 
+$ 
+3,861,187 
+$ 
+2,157,449 
+$ 
+2,494,169 
+Proved
+developed reserves 
+77% 
+78% 
+82% 
+Reserve
+replacement – including sales of reserves 
+248% 
+244% 
+256% 
+Reserve
+replacement – excluding sales of reserves 
+249% 
+247% 
+256% 
+Reserve
+life (years) (1) 
+10.1 
+10.0 
+9.1 
+(1) Reserve
+life represents the estimated proved reserves at the dates indicated divided by
+actual production for the preceding 12-month period. 
+9 
+The
+following table reconciles the standardized measure of discounted future net
+cash flows to the PV-10 value. The difference has to do with the
+PV-10 value measure excluding the impact of income taxes. Please see
+the definitions of standardized measure of discounted future net cash flows and
+PV-10 value in the Glossary. 
+As
+of December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Standardized
+measure of discounted 
+future
+net cash flows 
+$ 
+2,706,914 
+$ 
+1,576,437 
+$ 
+1,712,298 
+Add:
+10 percent annual discount, net of income taxes 
+2,321,983 
+1,238,308 
+1,286,568 
+Add:
+Future income taxes 
+2,316,637 
+1,125,955 
+1,448,444 
+Undiscounted
+future net cash flows 
+$ 
+7,345,534 
+$ 
+3,940,700 
+$ 
+4,447,310 
+Less:
+10 percent annual discount without tax effect 
+(3,484,347 
+) 
+(1,783,251 
+) 
+(1,953,141 
+) 
+PV-10
+value 
+$ 
+3,861,187 
+$ 
+2,157,449 
+$ 
+2,494,169 
+Production 
+The
+following table summarizes the average volumes and realized prices, including
+and excluding the effects of hedging, of oil and gas produced from properties in
+which St. Mary held an interest during the periods
+indicated. Also presented is a production cost per MCFE summary for
+the Company. 
+Years
+Ended December 31, 
+2007 
+2006 
+2005 
+Net
+production: 
+Oil
+(MMBbl) 
+6.9 
+6.1 
+5.9 
+Gas
+(Bcf) 
+66.1 
+56.4 
+51.8 
+BCFE 
+107.5 
+92.8 
+87.4 
+Average
+net daily production: 
+Oil
+(MBbl) 
+18.9 
+16.6 
+16.2 
+Gas
+(MMcf) 
+181.0 
+154.7 
+141.9 
+MMCFE 
+294.5 
+254.2 
+239.4 
+Average
+realized sales price, excluding the effects of hedging: 
+Oil
+(per Bbl) 
+$ 
+67.56 
+$ 
+59.33 
+$ 
+53.18 
+Gas
+(per Mcf) 
+$ 
+6.74 
+$ 
+6.58 
+$ 
+8.08 
+Per
+MCFE 
+$ 
+8.48 
+$ 
+7.88 
+$ 
+8.40 
+Average
+realized sales price, including the effects of hedging: 
+Oil
+(per Bbl) 
+$ 
+62.60 
+$ 
+56.60 
+$ 
+50.93 
+Gas
+(per Mcf) 
+$ 
+7.63 
+$ 
+7.37 
+$ 
+7.90 
+Per
+MCFE 
+$ 
+8.71 
+$ 
+8.18 
+$ 
+8.14 
+Production
+costs per MCFE: 
+Lease
+operating expense 
+$ 
+1.31 
+$ 
+1.25 
+$ 
+0.99 
+Transportation
+expense 
+$ 
+0.14 
+$ 
+0.12 
+$ 
+0.09 
+Production
+taxes 
+$ 
+0.58 
+$ 
+0.54 
+$ 
+0.56 
+10 
+Productive
+Wells 
+As of
+December 31, 2007, St. Mary had working interests in 2,365 gross
+(1,125 net) productive oil wells and 4,199 gross (1,405 net)
+productive gas wells. Productive wells are either producing wells or
+wells capable of commercial production although currently
+shut-in. One or more completions in the same wellbore are counted as
+one well. A well is categorized under state reporting regulations as
+an oil well or a gas well based upon the ratio of gas to oil produced when it
+first commenced production, and such designation may not be indicative of
+current production. 
+Drilling
+Activity 
+All of
+our drilling activities are conducted on a contract basis with independent
+drilling contractors. We do not own any drilling
+equipment. The following table sets forth the wells drilled and
+recompleted in which St. Mary participated during each of the three years
+indicated: 
+Years
+Ended December 31, 
+2007 
+2006 
+2005 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development: 
+Oil 
+164 
+77.91 
+81 
+35.32 
+83 
+38.09 
+Gas 
+518 
+204.62 
+446 
+178.97 
+379 
+152.69 
+Non-productive 
+30 
+13.18 
+31 
+10.65 
+29 
+9.12 
+712 
+295.71 
+558 
+224.94 
+491 
+199.90 
+Exploratory: 
+Oil 
+3 
+1.92 
+10 
+5.53 
+8 
+1.91 
+Gas 
+9 
+4.01 
+15 
+3.68 
+5 
+0.86 
+Non-productive 
+5 
+2.58 
+8 
+1.81 
+5 
+2.32 
+17 
+8.51 
+33 
+11.02 
+18 
+5.09 
+Farmout
+or non-consent 
+1 
+- 
+2 
+- 
+18 
+- 
+Total
+(1) 
+730 
+304.22 
+593 
+235.96 
+527 
+204.99 
+(1) Does not
+include three and nine gross wells completed on St. Mary's fee lands during
+2006 and 2005, respectively, in which we have
+only a royalty interest. 
+11 
+Acreage 
+The
+following table sets forth the gross and net acres of developed and undeveloped
+oil and gas leases, fee properties, mineral servitudes, and lease options held
+by St. Mary as of December 31, 2007. Undeveloped
+acreage includes leasehold interests that may already have been classified as
+containing proved undeveloped reserves. 
+Developed
+Acres (1) 
+Undeveloped
+Acres (2) 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Arkansas 
+2,917 
+408 
+207 
+68 
+3,124 
+476 
+Colorado 
+3,098 
+2,496 
+20,269 
+12,530 
+23,367 
+15,026 
+Louisiana 
+136,606 
+45,913 
+52,349 
+15,081 
+188,955 
+60,994 
+Mississippi 
+6,646 
+727 
+59,907 
+21,435 
+66,553 
+22,162 
+Montana 
+70,462 
+45,523 
+426,161 
+286,841 
+496,623 
+332,364 
+New
+Mexico 
+5,440 
+2,608 
+1,480 
+1,187 
+6,920 
+3,795 
+North
+Dakota 
+150,968 
+97,691 
+198,104 
+110,786 
+349,072 
+208,477 
+Oklahoma 
+302,820 
+91,523 
+107,018 
+56,735 
+409,838 
+148,258 
+Texas 
+215,056 
+78,310 
+163,849 
+97,019 
+378,905 
+175,329 
+Utah
+(3) 
+480 
+115 
+3,574 
+831 
+4,054 
+946 
+Wyoming 
+152,209 
+97,129 
+395,083 
+226,410 
+547,292 
+323,539 
+Other
+(4) 
+2,201 
+873 
+3,836 
+1,090 
+6,037 
+1,963 
+1,048,903 
+463,316 
+1,431,837 
+830,013 
+2,480,740 
+1,293,329 
+Louisiana
+Fee Properties 
+10,818 
+10,818 
+14,096 
+14,096 
+24,914 
+24,914 
+Louisiana
+Mineral Servitudes 
+10,173 
+5,740 
+4,411 
+4,048 
+14,584 
+9,788 
+20,991 
+16,558 
+18,507 
+18,144 
+39,498 
+34,702 
+Total
+(5) 
+1,069,894 
+479,874 
+1,450,344 
+848,157 
+2,520,238 
+1,328,031 
+(1) Developed acreage is acreage assigned to producing wells for the
+spacing unit of the producing formation. Developed acreage in certain
+of St. Mary's properties that include multiple formations with different
+well spacing requirements may be considered undeveloped for certain formations,
+but have only been included as developed acreage in the presentation
+above. 
+(2) Undeveloped acreage is lease acreage on which wells have not
+been drilled or completed to a point that would permit the production of
+commercial quantities of oil and gas, regardless of whether such acreage
+contains estimated proved reserves. 
+(3) St. Mary holds an overriding royalty interest in an
+additional 36,021 gross acres in Utah. 
+(4) Includes interests in Alabama, Kansas, Nebraska and South
+Dakota. 
+(5) Subsequent to December 31, 2007, St. Mary divested certain
+non-core properties, which included leases covering approximately 155,400 and
+53,900 developed gross and net acres, respectively, and 67,100 and 38,400
+undeveloped gross and net acres, respectively. Additionally, St. Mary
+also divested its overriding royalty interest in 36,000 gross acres in
+Utah. 
+Major
+Customers 
+During
+2007 and 2006, no customer individually accounted for ten percent or more
+of the Company’s total oil and gas production revenue. During 2005,
+sales to Tesoro Refining and Marketing individually accounted for
+13 percent of the Company’s total oil and gas production
+revenue. 
+Employees
+and Office Space 
+As of
+February 15, 2008, we had 438 full-time employees. None of our
+employees are subject to a collective bargaining agreement, and we consider our
+relations with our employees to be good. We lease approximately
+77,000 square feet of office space in Denver, Colorado for our executive
+and 
+12 
+administrative
+offices, of which approximately 10,000 square feet is
+subleased. We lease approximately 22,000 square feet of office
+space in Tulsa, Oklahoma; approximately 21,000 square feet in Shreveport,
+Louisiana; approximately 20,000 square feet in Houston, Texas;
+approximately 12,000 square feet in Midland, Texas; approximately 36,000
+square feet in Billings, Montana; and approximately 2,000 square feet
+in Casper, Wyoming. 
+Title
+to Properties 
+Substantially
+all of our working interests are held pursuant to leases from third
+parties. A title opinion is usually obtained prior to the
+commencement of drilling operations. We have obtained title opinions
+or have conducted a thorough title review on substantially all of our producing
+properties and believe that we have satisfactory title to such properties in
+accordance with standards generally accepted in the oil and gas
+industry. The majority of the value of our properties is subject to a
+mortgage under our credit facility, customary royalty interests, liens for
+current taxes, and other burdens that we believe do not materially interfere
+with the use of or affect the value of such properties. We perform
+only a minimal title investigation before acquiring undeveloped
+leasehold. 
+Seasonality 
+Generally,
+but not always, the demand and price levels for natural gas increase during the
+colder winter months and decrease during the warmer summer months. To
+lessen seasonal demand fluctuations, pipelines, utilities, local distribution
+companies, and industrial users utilize natural gas storage facilities and
+forward purchase some of their anticipated winter requirements during the
+summer. However, increased summertime demand for electricity is
+beginning to place an increasing demand on storage volumes. Crude oil
+and the demand for heating oil are also impacted by generally higher prices in
+the winter – although oil is much more driven by global supply and
+demand. Seasonal anomalies such as mild winters sometimes lessen
+these fluctuations. The impact of seasonality has somewhat been
+exacerbated by the overall supply and demand economics related to crude oil
+because there is a narrow margin of production capacity in excess of existing
+worldwide demand. 
+Competition 
+The oil
+and gas industry is intensely competitive. This is particularly true
+in the competition for acquisitions of prospective oil and natural gas
+properties and oil and gas reserves. We believe that our leasehold
+position provides a sound foundation for a solid drilling
+program. Our competitive position also depends on our geological,
+geophysical, and engineering expertise, and our financial
+resources. We believe that the location of our leasehold acreage, our
+exploration, drilling, and production expertise, and the experience and
+knowledge of our management and industry partners enable us to compete
+effectively in our core operating areas. Notwithstanding our talents
+and assets, we still face stiff competition from a substantial number of major
+and independent oil and gas companies that have larger technical staffs and
+greater financial and operational resources than we do. Many of these
+companies not only engage in the acquisition, exploration, development, and
+production of oil and natural gas reserves, but also have refining operations,
+market refined products, own drilling rigs, and generate
+electricity. We also compete with other oil and natural gas companies
+in attempting to secure drilling rigs and other equipment necessary for the
+drilling and completion of wells. Consequently, drilling equipment
+may be in short supply from time to time. Currently, access to
+incremental drilling equipment in certain regions is difficult but is not, at
+this time, anticipated to have any material negative impact on our ability to
+deploy our drilling capital budget for 2008. We are seeing signs of
+loosening rig availability, although it is quite specific by
+region. Finally, we also compete for people. Throughout
+the industry, the need for talented people has grown at a time when the number
+of people available is constrained. We are not insulated from this
+resource constraint and we have to be willing to compete in this market in order
+to be successful. 
+Government Regulations 
+Our
+business is subject to various federal, state, and local laws and governmental
+regulations that may be changed from time to time in response to economic or
+political conditions. Matters subject to regulation include the
+issuance of drilling permits, discharge permits for drilling operations,
+drilling bonds, reports concerning operations, the spacing of wells, unitization
+and pooling of properties, taxation, and environmental
+protection. From time to 
+13 
+time,
+regulatory agencies have imposed price controls and limitations on production by
+restricting the rate of flow of oil and gas wells below actual production
+capacity in order to conserve supplies of oil and gas. 
+Energy
+Regulations . Our sale of natural gas is affected by the
+availability, terms, and cost of transportation. The price and terms
+of access to pipeline transportation are subject to extensive federal and state
+regulation. While the rules and regulations of the Federal Energy
+Regulatory Commission (FERC) have in the past greatly affected the production
+and sale of natural gas, the direct impact on the upstream exploration and
+production segment of the energy industry has changed to allow market forces to
+set the price paid for natural gas. FERC regulations continue to
+affect the midstream and transportation segments of the industry and thus can
+have an indirect impact of the sales price we receive for natural gas
+production. There is no assurance that the less stringent regulatory
+approach recently pursued by the FERC and Congress will continue. We
+do not believe that we will be more materially affected by any action taken by
+the FERC or Congress than other natural gas producers and marketers with whom we
+compete. 
+Certain
+operations we conduct involve federal minerals administered by the Minerals
+Management Service (MMS). The MMS issues leases covering such lands
+through competitive bidding. These leases contain relatively
+standardized terms and require compliance with federal laws and detailed MMS
+regulations. For offshore operations, lessees must obtain MMS
+approval for exploration plans and development and production plans prior to the
+commencement of such operations. In addition to permits required from
+other agencies such as the Coast Guard, the Army Corps of Engineers, and the
+Environmental Protection Agency, lessees must obtain a permit from the MMS prior
+to the commencement of drilling. Lessees must also comply with
+detailed MMS regulations governing, among other things: 
+· 
+Engineering
+and construction specifications for offshore production
+facilities 
+· 
+Safety
+procedures 
+· 
+Flaring
+of production 
+· 
+Plugging
+and abandonment of Outer Continental Shelf (OCS)
+wells 
+· 
+Calculation
+of royalty payments and the valuation of production for this
+purpose 
+· 
+Removal
+of facilities. 
+To cover
+the various obligations of lessees on the OCS, the MMS generally requires that
+lessees post substantial bonds or other acceptable assurances that such
+obligations will be met. The cost of such bonds or other surety can
+be substantial, and we may not be able to continue to obtain bonds or other
+surety in all cases. Under certain circumstances the MMS may require
+our operations on federal leases to be suspended or terminated. 
+Many of
+the states in which we conduct our oil and gas drilling and production
+activities regulate such activities by requiring, among other things, drilling
+permits and bonds and reports concerning operations. The laws of
+these states also govern a number of environmental and conservation matters,
+including the handling and disposing of waste material, plugging and abandonment
+of wells, restoration requirements, unitization, pooling of interests in natural
+gas and oil properties, and establishment of maximum rates of production from
+natural gas and oil wells. States generally have the ability to
+prorate production to the market demand for oil and natural gas; however, this
+is not currently occurring. 
+Environmental
+Regulations. Our operations are subject to numerous existing
+federal, state, and local laws and regulations governing environmental quality
+and pollution control. These laws and regulations may require that
+permits be obtained before drilling commences, restrict the types, quantities,
+and concentration of various substances that can be released into the
+environment in connection with drilling and production activities, and limit or
+prohibit drilling activities on certain lands lying within wilderness, wetlands,
+and other protected areas, including areas containing endangered animal
+species. As a result, these laws and regulations may substantially
+increase the costs of 
+14 
+exploring
+for, developing, or producing oil and gas and may prevent or delay the
+commencement or continuation of certain projects. In addition, these
+laws and regulations may impose substantial clean-up, remediation, and other
+obligations in the event of any discharges or emissions in violation of such
+laws and regulations. 
+Our
+coalbed methane gas production is similar to our traditional natural gas
+production as to the physical producing facilities and the product
+produced. However, the subsurface mechanisms that allow the gas to
+move to the wellbore and the producing characteristics of coalbed methane wells
+are very different from traditional natural gas production. Unlike
+conventional gas wells, which require a porous and permeable reservoir,
+hydrocarbon migration, and a natural structural and/or stratigraphic trap,
+coalbed methane gas is trapped in the molecular structure of the coal itself
+until released by pressure changes resulting from the removal of in situ 
+water. Frequently, coalbeds are partly or completely saturated with
+water. As the water is removed, internal pressures on the coal are
+decreased, allowing the gas to desorb from the coal and flow to the
+wellbore. Unlike traditional gas wells, new coalbed methane wells
+often produce water for several months and then, as the water production
+decreases, natural gas production increases. 
+Coalbed
+methane gas production requires state permits for the use of well-site pits and
+evaporation ponds for the disposal of produced water. Groundwater
+produced from the coal seams can generally be discharged into arroyos, surface
+waters, well-site pits, and evaporation ponds without a permit if it does not
+exceed surface discharge permit levels, and meets state and federal primary
+drinking water standards. All of these disposal options require an
+extensive third-party water sampling and laboratory analysis program to ensure
+compliance with state permit standards. Where water of lesser quality
+is involved or the wells produce water in excess of the applicable volumetric
+permit limits, additional disposal wells may have to be drilled to re-inject the
+produced water back into underground rock formations. 
+A portion
+of our acreage at the Hanging Woman Basin coalbed methane project is on federal
+lands in Montana. We are subject to delays in permitting associated
+with the completion of a supplemental Environmental Impact Statement covering
+the contemplation of phased development on federal leases in
+Montana. We are also affected by considerations for sage grouse that
+are native to the area. Each of these issues has the potential to
+impact the timing of our permitting and drilling operations associated with
+development of Hanging Woman Basin. 
+To date
+we have not experienced any material adverse effect on our operations from
+obligations under environmental laws and regulations. We believe that
+we are in substantial compliance with currently applicable environmental laws
+and regulations and that continued compliance with existing requirements would
+not have a material adverse impact on us. 
+Cautionary
+Information about Forward-Looking Statements 
+This Form
+10-K contains “forward-looking statements” within the meaning of Section 27A of
+the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
+1934. All statements, other than statements of historical facts,
+included in this Form 10-K that address activities, events or developments with
+respect to our financial condition, results of operations, or economic
+performance that we expect, believe, or anticipate will or may occur in the
+future, or that address plans and objectives of management for future
+operations, are forward-looking statements. The words “anticipate,”
+“assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,”
+“plan,” “project,” “will,” and similar expressions are intended to identify
+forward-looking statements. Forward-looking statements appear in a
+number of places in this Form 10-K, and include statements about such matters
+as: 
+· 
+The
+amount and nature of future capital expenditures and the availability of
+capital resources to fund capital
+expenditures 
+· 
+The
+drilling of wells and other exploration and development activities, as
+well as possible future
+acquisitions 
+· 
+Reserve
+estimates and the estimates of both future net revenues and the present
+value of future net revenues that are implied by those reserve
+estimates 
+15 
+· 
+Future
+oil and natural gas production
+estimates 
+· 
+Our
+outlook on future oil and natural gas
+prices 
+· 
+Cash
+flows, anticipated liquidity, and the future repayment of
+debt 
+· 
+Business
+strategies and other plans and objectives for future operations, including
+plans for expansion and growth of operations and our outlook on future
+financial condition or results of
+operations 
+· 
+Other
+similar matters such as those discussed in the “Management’s Discussion
+and Analysis of Financial Condition and Results of Operations” in Item 7
+of this Form 10-K. 
+Our
+forward-looking statements are based on assumptions and analyses made by us in
+light of our experience and our perception of historical trends, current
+conditions, expected future developments, and other factors that we believe are
+appropriate under the circumstances. These statements are subject to
+a number of known and unknown risks and uncertainties which may cause our actual
+results and performance to be materially different from any future results or
+performance expressed or implied by the forward-looking
+statements. These risks are described in the “Risk Factors” in Item
+1A of this Form 10-K, and include such factors as: 
+· 
+The
+volatility and level of realized oil and natural gas
+prices 
+· 
+Our
+ability to replace reserves and sustain
+production 
+· 
+Unexpected
+drilling conditions and results 
+· 
+Unsuccessful
+exploration and development
+drilling 
+· 
+The
+availability of economically attractive exploration, development, and
+property acquisition opportunities and any necessary
+financing 
+· 
+The
+risks of hedging strategies 
+· 
+Lower
+prices realized on oil and natural gas sales resulting from our commodity
+price risk management activities 
+· 
+The
+uncertain nature of the expected benefits from acquisitions and
+divestitures of oil and natural gas properties, including uncertainties in
+evaluating oil and natural gas reserves of acquired properties and
+associated potential liabilities 
+· 
+The
+imprecise nature of oil and natural gas reserve
+estimates 
+· 
+Uncertainties
+inherent in projecting future rates of production from drilling activities
+and acquisitions 
+· 
+Drilling
+and operating service availability 
+· 
+Uncertainties
+in cash flow 
+· 
+The
+financial strength of hedge contract
+counterparties 
+· 
+The
+negative impact that lower oil and natural gas prices could have on our
+ability to borrow 
+· 
+The
+potential effects of increased levels of debt
+financing 
+· 
+Our
+ability to compete effectively against other independent and major oil and
+natural gas companies 
+16 
+· 
+Litigation,
+environmental matters, the potential impact of government regulations, and
+the use of management estimates. 
+We
+caution you that forward-looking statements are not guarantees of
+future performance and that actual results or developments may be
+materially different from those expressed or implied in the forward-looking
+statements. Although we may from time to time voluntarily update our
+prior forward-looking statements, we disclaim any commitment to do so except as
+required by securities laws. 
+Available
+Information 
+Our
+Internet website address is www.stmaryland.com. Within our website’s
+financial information section we make available free of charge our annual
+reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
+8-K, and amendments to those reports filed with or furnished to the SEC under
+applicable securities laws. These materials are made available as
+soon as reasonably practical after we electronically file such materials with or
+furnish such materials to the SEC. 
+We also
+make available through our website’s corporate governance section our Corporate
+Governance Guidelines, Code of Business Conduct and Ethics, and the Charters for
+our Board of Directors’ Audit Committee, Compensation Committee, Executive
+Committee, and Nominating and Corporate Governance Committee. These
+documents are also available in print to any stockholder who requests
+them. Requests for these documents may be submitted to: 
+St. Mary
+Land & Exploration Company 
+Investor
+Relations 
+1776
+Lincoln Street, Suite 700 
+Denver,
+Colorado 80203 
+Telephone: (303)
+863-4322 
+http://www.stmaryland.com 
+Information
+on our website is not incorporated by reference into this Form 10-K and should
+not be considered part of this document. 
+Glossary
+of Oil and Natural Gas Terms 
+The oil
+and natural gas terms defined in this section are used throughout this Form
+10-K. 
+2-D seismic or 2-D
+data. Seismic data that is acquired and processed to yield a
+two-dimensional cross-section of the subsurface. 
+3-D seismic or 3-D
+data. Seismic data that is acquired and processed to yield a
+three-dimensional picture of the subsurface. 
+Bbl. One stock
+tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other
+liquid hydrocarbons. 
+Bcf. Billion cubic
+feet, used in reference to natural gas. 
+BCFE. Billion
+cubic feet of natural gas equivalent. Natural gas equivalents are
+determined using the ratio of six Mcf of natural gas (including natural gas
+liquids) to one Bbl of oil. 
+BOE. Barrels of
+oil equivalent. Oil equivalents are determined using the ratio of six
+Mcf of natural gas (including natural gas liquids) to one Bbl of
+oil. 
+Development
+well. A well drilled within the proved area of an oil or
+natural gas reservoir to the depth of a stratigraphic horizon known to be
+productive. 
+Dry hole. A well
+found to be incapable of producing either oil or natural gas in sufficient
+commercial quantities. 
+17 
+Exploratory
+well. A well drilled to find and produce oil or natural gas in
+an unproved area, to find a new reservoir in a field previously found to be
+productive of oil or natural gas in another reservoir, or to extend a known
+reservoir beyond its known horizon. 
+Farmout. An
+assignment of an interest in a drilling location and related acreage conditioned
+upon the drilling of a well on that location. 
+Fee land. The most
+extensive interest that can be owned in land, including surface and mineral
+(including oil and natural gas) rights. 
+Field. An area
+consisting of a single reservoir or multiple reservoirs all grouped on or
+related to the same individual geological structural feature or stratigraphic
+condition. 
+Finding
+cost. Expressed in dollars per BOE or MCFE. Finding
+costs are calculated by dividing the amount of total capital expenditures for
+oil and natural gas activities, including the effect of asset retirement
+obligations, by the amount of estimated net proved reserves added through
+discoveries, extensions, infill drilling, acquisitions, and revisions of
+previous estimates during the same period. The information for this
+calculation is included in Note 13 of Part IV, Item 15 of this Form
+10-K. 
+Formation. A
+succession of sedimentary beds that were deposited under the same general
+geologic conditions. 
+Gross acre. An
+acre in which a working interest is owned. 
+Gross well. A well
+in which a working interest is owned. 
+Horizontal
+wells. Wells which are drilled at angles greater than 70
+degrees from vertical. 
+Hydraulic
+fracturing. A procedure to stimulate production by forcing a
+mixture of fluid and proppant (usually sand) into the formation under high
+pressure. This increases the permeability and porosity of the
+targeted formation. 
+MBbl. One thousand
+barrels of oil or other liquid hydrocarbons. 
+MMBbl. One million
+barrels of oil or other liquid hydrocarbons. 
+MBOE. One thousand
+barrels of oil equivalent. Oil equivalents are determined using the
+ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of
+oil. 
+MMBOE. One million
+barrels of oil equivalent. Oil equivalents are determined using the
+ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of
+oil. 
+Mcf. One thousand
+cubic feet, used in reference to natural gas. 
+MCFE . One thousand
+cubic feet of natural gas equivalent. Natural gas equivalents are
+determined using the ratio of six Mcf of natural gas (including natural gas
+liquids) to one Bbl of oil. 
+MMcf. One million
+cubic feet, used in reference to natural gas. 
+MMCFE . One million
+cubic feet of natural gas equivalent. Natural gas equivalents are
+determined using the ratio of six Mcf of natural gas (including natural gas
+liquids) to one Bbl of oil. 
+MMBtu. One million
+British Thermal Units. A British Thermal Unit is the amount of heat
+required to raise the temperature of a one-pound mass of water by one degree
+Fahrenheit. 
+Net acres or net
+wells. The sum of our fractional working interests owned in
+gross acres or gross wells. 
+18 
+Net asset value per
+share. The result of the fair market value of total assets
+less total liabilities, divided by the total number of outstanding shares of
+common stock. 
+NYMEX . New York
+Mercantile Exchange. 
+OCS. Outer Continental Shelf
+in the Gulf of Mexico. 
+PV-10 value. The
+present value of estimated future gross revenue to be generated from the
+production of estimated net proved reserves, net of estimated production and
+future development costs, using prices and costs in effect as of the date
+indicated (unless such prices or costs are subject to change pursuant to
+contractual provisions), without giving effect to non-property related expenses
+such as general and administrative expenses, debt service and future income tax
+expenses or to depreciation, depletion, and amortization, discounted using an
+annual discount rate of ten percent. While this measure does not
+include the effect of income taxes as it would in the use of the standardized
+measure calculation, it does provide an indicative representation of the
+relative value of the Company on a comparative basis to other companies and from
+period to period. 
+Productive well. A
+well that is producing oil or natural gas or that is capable of commercial
+production. 
+Proved developed
+reserves. Reserves that can be expected to be recovered
+through existing wells with existing equipment and operating
+methods. 
+Proved
+reserves. The estimated quantities of oil, natural gas, and
+natural gas liquids which geological and engineering data demonstrate with
+reasonable certainty to be recoverable in future years from known reservoirs
+under existing economic and operating conditions. 
+Proved undeveloped
+reserves. Reserves that are expected to be recovered from new
+wells on undrilled acreage or from existing wells where a relatively major
+expenditure is required for recompletion. 
+Recompletion. The
+completion in an existing wellbore in a formation other than that in which the
+well has previously been completed. 
+Reserve
+life. Expressed in years, represents the estimated net proved
+reserves at a specified date divided by actual production for the preceding
+12-month period. 
+Reserve replacement percentage –
+excluding sales of reserves . The sum of reserve extensions and
+discoveries, reserve acquisitions, and reserve revisions of previous estimates
+for a specified period of time divided by production for that same period of
+time. This is believed to be a useful non-GAAP measure that is widely
+utilized within the exploration and production industry as well as by
+investors. It is an easily calculable number and is representative of
+the relative success a company is having in replacing its production from its
+declining asset base as well as its ability to grow the overall
+company. 
+Reserve replacement percentage –
+including sales of reserves . The sum of sales of reserves,
+reserve extensions and discoveries, reserve acquisitions, and reserve revisions
+of previous estimates for a specified period of time divided by production for
+that same period of time. This is believed to be a useful non-GAAP
+measure that is widely utilized within the exploration and production industry
+as well as by investors. It is an easily calculable number and is
+representative of the relative success a company is having in replacing its
+production from its declining asset base as well as its ability to grow the
+overall company. 
+Royalty. The
+amount or fee paid to the owner of mineral rights, expressed as a percentage of
+gross income from oil and natural gas produced and sold unencumbered by expenses
+relating to the drilling, completing, and operating of the affected
+well. 
+Royalty
+interest. An interest in an oil and natural gas property
+entitling the owner to shares of oil and natural gas production free of costs of
+exploration, development, and production operations. 
+19 
+Standardized measure of discounted
+future net cash flows. The discounted future net cash flows
+relating to proved reserves based on year-end prices, costs, and statutory tax
+rates, and a ten percent annual discount rate. The information
+for this calculation is included in the note regarding disclosures about oil and
+gas producing activities contained in the Notes to Consolidated Financial
+Statements included in this Form 10-K. 
+Undeveloped
+acreage. Lease acreage on which wells have not been drilled or
+completed to a point that would permit the production of commercial quantities
+of oil and natural gas, regardless of whether such acreage contains estimated
+net proved reserves. 
+Working
+interest. The operating interest that gives the owner the
+right to drill, produce, and conduct operating activities on the property and to
+share in the production, sales, and costs. 
+ITEM
+1A. RISK
+FACTORS 
+In
+addition to the other information included in this Form 10-K, the following risk
+factors should be carefully considered when evaluating
+St. Mary. 
+Risks
+Related to Our Business 
+Oil
+and natural gas prices are volatile and a decline in prices could hurt our
+profitability, financial condition, cash flows, access to capital, and ability
+to grow. 
+Our
+revenues, operating results, profitability, future rate of growth, and the
+carrying value of our oil and natural gas properties depend heavily on the
+prices we receive for oil and natural gas sales. Oil and natural gas
+prices also affect our cash flows and borrowing capacity, as well as the amount
+and value of our oil and natural gas reserves. 
+Historically,
+the markets for oil and natural gas have been volatile and they are likely to
+continue to be volatile. Wide fluctuations in oil and natural gas
+prices may result from relatively minor changes in the supply of and demand for
+oil and natural gas, market uncertainty, and other factors that are beyond our
+control, including: 
+· 
+Worldwide
+and domestic supplies of oil and natural
+gas 
+· 
+The
+ability of the members of the Organization of Petroleum Exporting
+Countries to agree to and maintain oil price and production
+controls 
+· 
+Pipeline,
+transportation, or refining capacity constraints in a regional or
+localized area may impact the realized price for oil or natural
+gas 
+· 
+Political
+instability or armed conflict in oil or natural gas producing
+regions 
+· 
+The
+price and level of foreign imports of crude oil, refined petroleum
+products, and liquefied natural gas 
+· 
+Worldwide
+and domestic economic conditions 
+· 
+The
+level of consumer demand for
+hydrocarbons 
+· 
+Productive
+capacity of the industry as a whole 
+· 
+The
+availability of transportation
+facilities 
+· 
+Weather
+conditions 
+· 
+The
+price and availability of alternative
+fuels 
+20 
+· 
+Governmental
+regulations and taxes. 
+These
+factors and the volatility of oil and natural gas markets make it very difficult
+to predict future oil and natural gas price movements with any
+certainty. Declines in oil or natural gas prices would reduce our
+revenues and could also reduce the amount of oil and natural gas that we can
+produce economically, which could have a material adverse effect on
+us. 
+If
+we are not able to replace reserves, we will not be able to sustain
+production. 
+Our
+future operations depend on our ability to find, develop, and acquire oil and
+natural gas reserves that are economically recoverable. Our
+properties produce oil and natural gas at a declining rate over
+time. In order to maintain current production rates we must locate
+and develop or acquire new oil and natural gas reserves to replace those being
+depleted by production. In addition, competition for the acquisition
+of producing oil and natural gas properties is intense and many of our
+competitors have financial and other resources needed to evaluate and integrate
+acquisitions that are substantially greater than those available to
+us. Therefore, we may not be able to acquire oil and natural gas
+properties that contain economically recoverable reserves, or we may not be able
+to acquire such properties at prices acceptable to us. Without
+successful drilling or acquisition activities, our reserves, production, and
+revenues will decline over time. 
+Competition
+in our industry is intense, and many of our competitors have greater financial,
+technical and human resources than we do. 
+We face
+intense competition from major oil companies, independent oil and natural gas
+exploration and production companies, financial buyers, and institutional and
+individual investors who are actively seeking oil and natural gas properties
+throughout the world, as well as the equipment, expertise, labor, and materials
+required to operate oil and natural gas properties. Many of our
+competitors have financial and technical resources vastly exceeding those
+available to us, and many oil and natural gas properties are sold in a
+competitive bidding process in which our competitors may be able or willing to
+pay more for development prospects and productive properties or in which our
+competitors have technological information or expertise that is not available to
+us to evaluate and successfully bid for the properties. In addition,
+shortages of equipment, labor, or materials as a result of intense competition
+may result in increased costs or the inability to obtain those resources as
+needed. We may not be successful in acquiring and developing
+profitable properties in the face of this competition. 
+We also
+compete for people. The need for talented people across all
+disciplines in the industry has grown at a time when the number of people
+available is constrained. 
+The
+actual quantities and present values of our proved oil and natural gas reserves
+may be less than we have estimated. 
+This Form
+10-K and other SEC filings by us contain estimates of our proved oil and natural
+gas reserves and the estimated future net revenues from those
+reserves. Reserve estimates are based on various assumptions,
+including assumptions required by the SEC relating to oil and natural gas
+prices, drilling and operating expenses, capital expenditures, taxes, timing of
+operations, and availability of funds. The process of estimating
+reserves is complex. This process requires significant decisions and
+assumptions in the evaluation of available geological, geophysical, engineering,
+and economic data for each reservoir. These estimates are dependent
+on many variables and therefore changes often occur as these variables
+evolve. Therefore, these estimates are inherently
+imprecise. 
+Actual
+future production, oil and natural gas prices, revenues, production taxes,
+development expenditures, operating expenses, and quantities of recoverable oil
+and natural gas reserves will most likely vary from those
+estimated. Any significant variance could materially affect the
+estimated quantities of and present values related to proved reserves disclosed
+by us, and the actual quantities and present values may be less than we have
+previously estimated. In addition, we may adjust estimates of proved
+reserves to reflect production history, results of exploration and development
+activity, prevailing oil and natural gas prices, costs to develop and operate
+properties, and other factors, many of which are beyond our
+control. Our properties may also be susceptible to hydrocarbon
+drainage from production by operators on adjacent properties. 
+21 
+As of
+December 31, 2007, approximately 23 percent, or 250.2 BCFE,
+of our estimated proved reserves were proved undeveloped and approximately 11
+percent or 116.0 BCFE, were proved developed non-producing. Estimates
+of proved undeveloped reserves and proved developed non-producing reserves are
+nearly always based on volumetric calculations rather than the performance data
+used to estimate producing reserves. In order to recover our proved
+undeveloped reserves, an estimated $234 million of capital expenditures will be
+spent during 2008. Production revenues from proved developed
+non-producing reserves will not be realized until some time in the
+future. In order to bring production on-line for our proved developed
+non-producing reserves, we estimate capital expenditures of $12 million for
+2008. Although we have estimated our reserves and the costs
+associated with these reserves in accordance with industry standards, estimated
+costs may not be accurate, development may not occur as scheduled and actual
+results may not occur as estimated. The balance of our capital
+expenditure budget for 2008 is directed towards projects that are not yet
+classified within the construct of proved reserves as defined by Regulation S-X
+of the Securities and Exchange Commission. 
+You
+should not assume that the PV-10 value and standardized measure of discounted
+future net cash flows included in this Form 10-K represent the current market
+value of our estimated proved oil and natural gas
+reserves. Management has based the estimated discounted future net
+cash flows from proved reserves on prices and costs as of the date of the
+estimate, in accordance with SEC requirements, whereas actual future prices and
+costs may be materially higher or lower. For example, values of our
+reserves as of December 31, 2007, were estimated using a calculated sales price
+of $6.80 per MMBtu of natural gas (NYMEX Henry Hub spot price) and
+$95.98 per Bbl of oil (NYMEX West Texas Intermediate spot
+price). We then adjust this base price to ensure we consider the
+appropriate basis and location differentials as of that date in estimating our
+proved reserves. During 2007, our monthly average realized natural
+gas prices, excluding the effect of hedging, were as high as $7.83 per Mcf
+and as low as $5.42 per Mcf. For the same period our monthly
+average realized oil prices before hedging were as high as $91.53 per Bbl
+and as low as $48.88 per Bbl. Many other factors will affect
+actual future net cash flows, including: 
+· 
+Amount
+and timing of actual production 
+· 
+Supply
+and demand for oil and natural gas 
+· 
+Curtailments
+or increases in consumption by oil purchasers and natural gas
+pipelines 
+· 
+Changes
+in governmental regulations or
+taxes. 
+The
+timing of production from oil and natural gas properties and of related expenses
+affects the timing of actual future net cash flows from proved reserves and thus
+their actual present value. Our actual future net cash flows could be
+less than the estimated future net cash flows for purposes of computing PV-10
+values. In addition, the ten percent discount factor required by
+the SEC to be used to calculate PV-10 values for reporting purposes is not
+necessarily the most appropriate discount factor given actual interest rates and
+risks to which our business and the oil and natural gas industry in general are
+subject. 
+Our
+producing property acquisitions may not be worth what we paid due to
+uncertainties in evaluating recoverable reserves and other expected benefits, as
+well as potential liabilities. 
+Successful
+property acquisitions require an assessment of a number of factors beyond our
+control. These factors include exploration potential, future oil and
+natural gas prices, operating costs, and potential environmental and other
+liabilities. These assessments are not precise and their accuracy is
+inherently uncertain. 
+In
+connection with our acquisitions, we perform a customary review of the acquired
+properties that will not necessarily reveal all existing or potential
+problems. In addition, our review may not allow us to fully assess
+the potential deficiencies of the properties. We do not inspect every
+well, and even when we inspect a well we may not discover structural,
+subsurface, or environmental problems that may exist or arise. We may
+not be entitled to contractual indemnification for pre-closing liabilities,
+including environmental liabilities. Normally, we acquire interests
+in properties on an “as is” basis with limited remedies for breaches of
+representations and warranties. 
+22 
+In
+addition, significant acquisitions can change the nature of our operations and
+business if the acquired properties have substantially different operating and
+geological characteristics or are in different geographic locations than our
+existing properties. To the extent acquired properties are
+substantially different than our existing properties, our ability to efficiently
+realize the expected economic benefits of such acquisitions may be
+limited. 
+Integrating
+acquired properties and businesses involves a number of other special risks,
+including the risk that management may be distracted from normal business
+concerns by the need to integrate operations and systems as well as retain and
+assimilate additional employees. Therefore, we may not be able to
+realize all of the anticipated benefits of our acquisitions. 
+Exploration
+and development drilling may not result in commercially productive
+reserves. 
+Oil and
+natural gas drilling and production activities are subject to numerous risks,
+including the risk that no commercially productive oil or natural gas will be
+found. The cost of drilling and completing wells is often uncertain,
+and oil and natural gas drilling and production activities may be shortened,
+delayed, or canceled as a result of a variety of factors, many of which are
+beyond our control. These factors include: 
+· 
+Unexpected
+drilling conditions 
+· 
+Title
+problems 
+· 
+Pressure
+or geologic irregularities in
+formations 
+· 
+Equipment
+failures or accidents 
+· 
+Hurricanes
+and other adverse weather
+conditions 
+· 
+Compliance
+with environmental and other governmental
+requirements 
+· 
+Shortages
+or delays in the availability of or increases in the cost of drilling rigs
+and crews, fracture stimulation crews and equipment, chemicals, and
+supplies. 
+The
+prevailing prices of oil and natural gas affect the cost of and the demand for
+drilling rigs, production equipment, and related services. The
+availability of drilling rigs can vary significantly from region to region at
+any particular time. Although land drilling rigs can be moved from
+one region to another in response to changes in levels of demand, an undersupply
+of rigs in any region may result in drilling delays and higher drilling costs
+for the rigs that are available in that region. 
+Another
+significant risk inherent in our drilling plans is the need to obtain drilling
+permits from state, local, and other governmental authorities. Delays
+in obtaining regulatory approvals and drilling permits, including delays which
+jeopardize our ability to realize the potential benefits from leased properties
+within the applicable lease periods, the failure to obtain a drilling permit for
+a well, or the receipt of a permit with unreasonable conditions or costs could
+have a materially adverse effect on our ability to explore on or develop our
+properties. 
+The wells
+we drill may not be productive and we may not recover all or any portion of our
+investment in such wells. The seismic data and other technologies we
+use do not allow us to know conclusively prior to drilling a well if oil or
+natural gas is present, or whether it can be produced
+economically. The cost of drilling, completing, and operating a well
+is often uncertain, and cost factors can adversely affect the economics of a
+project. Drilling activities can result in dry holes or wells that
+are productive but do not produce sufficient net revenues after operating and
+other costs to cover initial drilling and completion costs. 
+Our
+future drilling activities may not be successful. Our overall
+drilling success rate or our drilling success rate for activity within a
+particular area may decline. In addition, we may not be able to
+obtain any 
+23 
+options
+or lease rights in potential drilling locations that we
+identify. Although we have identified numerous potential drilling
+locations, we may not be able to economically produce oil or natural gas from
+all of them. 
+Our
+hedging transactions may limit the prices that we receive for oil and natural
+gas sales and involve other risks. 
+To manage
+our exposure to price risks in the sale of our oil and natural gas, we enter
+into commodity price risk management arrangements periodically with respect to a
+portion of our current or future production. We have hedged a
+significant portion of anticipated future production from our currently
+producing properties using zero-cost collars and swaps. Commodity
+price hedging may limit the prices that we receive for our oil and natural gas
+sales if oil or natural gas prices rise substantially over the price established
+by the hedge. In addition, these transactions may expose us to the
+risk of financial loss in certain circumstances, including instances in
+which: 
+· 
+Our
+production is less than expected 
+· 
+There
+is a widening of price differentials between delivery points for our
+production and the delivery point assumed in the hedge
+arrangement 
+· 
+The
+counterparties to our hedge contracts fail to perform under the
+contracts. 
+Some of
+our hedging agreements may also require us to furnish cash collateral, letters
+of credit, or other forms of performance assurance in the event that
+mark-to-market calculations result in settlement obligations by us to the
+counterparties, which could impact our liquidity and capital
+resources. In addition, some of our hedging transactions use
+derivative instruments that may involve basis risk. Basis risk in a
+hedging contract occurs when the index upon which the contract is based is more
+or less variable than the index upon which the hedged asset is based, thereby
+making the hedge less effective. For example, a NYMEX index used for
+hedging certain volumes of production may have more or less variability than the
+regional price index used for the sale of that production. 
+Future
+oil and natural gas price declines or unsuccessful exploration efforts may
+result in write-downs of our asset carrying values. 
+We follow
+the successful efforts method of accounting for our oil and natural gas
+properties. All property acquisition costs and costs of exploratory
+and development wells are capitalized when incurred, pending the determination
+of whether proved reserves have been discovered. If proved reserves
+are not discovered with an exploratory well, the costs of drilling the well are
+expensed. 
+The
+capitalized costs of our oil and natural gas properties, on a field basis,
+cannot exceed the estimated undiscounted future net cash flows of that
+field. If net capitalized costs exceed future net revenues, we must
+write down the costs of each such field to our estimate of its fair market
+value. Unproved properties are evaluated at the lower of cost or fair
+market value. Accordingly, a significant decline in oil or natural
+gas prices or unsuccessful exploration efforts could cause a future write-down
+of capitalized costs. 
+We review
+the carrying value of our properties quarterly based on prices in effect as of
+the end of each quarter or as of the time of reporting our
+results. Once incurred, a write-down of oil and natural gas
+properties cannot be reversed at a later date even if oil or natural gas prices
+increase. 
+Substantial
+capital is required to replace our reserves. 
+We need
+to make substantial capital expenditures to find, acquire, develop, and produce
+oil and natural gas reserves. Future cash flows and the availability
+of financing are subject to a number of factors, such as the level of production
+from existing wells, our success in locating and acquiring new reserves, and
+prices paid for oil and natural gas. If oil or natural gas prices
+decrease or we encounter operating difficulties that result in our cash flows
+from operations being less than expected, we may have to reduce our capital
+expenditures unless we can raise additional funds through debt or equity
+financing or the divestment of assets. Debt or equity financing may
+not always be available to us in sufficient amounts or on acceptable
+terms. The proceeds offered to us for potential divestitures may not
+always be of acceptable value to us. 
+24 
+If our
+revenues were to decrease due to lower oil or natural gas prices, decreased
+production, or other reasons, and if we could not obtain capital through our
+revolving credit facility, other acceptable debt or equity financing
+arrangements, or sale of non-core assets, our ability to execute our development
+plans, replace our reserves, or maintain production levels could be greatly
+limited. 
+The
+markets for raising public debt are quite constrained at the current time, given
+the overall liquidity concerns arising from the widely reported difficulties in
+the sub-prime and leveraged loan markets. While we continue to
+believe that our secured revolving credit facility will be sufficient for the
+foreseeable future, we must continually monitor the overall condition of the
+markets as a whole and remain cognizant that an overall pressure on the credit
+markets has the risk of increasing the cost of borrowings or decreasing the
+availability of new capital or the capacity of existing debt
+instruments. 
+A
+decrease in oil or natural gas prices could limit our ability to borrow under
+our revolving credit facility. 
+Our
+revolving credit facility currently has a maximum commitment amount of $500
+million, subject to a borrowing base of $1.25 billion that the lenders
+periodically redetermine based on the bank groups’ assessment of the value of
+our oil and natural gas properties, which in turn is based in part on oil and
+natural gas prices. Lower oil or natural gas prices in the future
+could limit our borrowing base and reduce our ability to borrow under the credit
+facility. 
+Our
+amount of debt may limit our ability to obtain financing for acquisitions, make
+us more vulnerable to adverse economic conditions, and make it more difficult
+for us to make payments on our debt. 
+As of
+December 31, 2007, we had $287.5 million of total long-term senior
+unsecured debt outstanding under our 3.50 % Senior Convertible Notes due
+2027 and $285.0 million of secured debt outstanding under our revolving
+credit facility. As of February 15, 2008, we had an outstanding
+balance of $180.0 million drawn against our revolving credit facility resulting
+in $320.0 million of available debt capacity under our revolving credit
+facility, assuming the borrowing conditions of this facility were
+met. Our long-term debt represented 40 percent of our total book
+capitalization as of December 31, 2007. The decrease in the
+borrowings subsequent to year end is a result of using the net proceeds from the
+sale of non-core properties on January 31, 2008. Our revolving credit
+facility has a maximum loan amount of $500 million, a current borrowing base of
+$1.25 billion, and we have elected a current commitment amount of $500
+million. 
+Our
+amount of debt could have important consequences for our operations,
+including: 
+· 
+Making
+it more difficult for us to obtain additional financing in the future for
+our operations and potential acquisitions, working capital requirements,
+capital expenditures, debt service, or other general corporate
+requirements 
+· 
+Requiring
+us to dedicate a substantial portion of our cash flows from operations to
+the repayment of our debt and the service of interest associated with our
+debt rather than to productive
+investments. 
+· 
+Limiting
+our operating flexibility due to financial and other restrictive
+covenants, including restrictions on incurring additional debt, creating
+liens on our properties, making acquisitions, and paying
+dividends 
+· 
+Placing
+us at a competitive disadvantage compared to our competitors that have
+less debt 
+· 
+Making
+us more vulnerable in the event of adverse economic or industry conditions
+or a downturn in our business. 
+Our
+ability to make payments on our debt and to refinance our debt and fund planned
+capital expenditures will depend on our ability to generate cash in the
+future. This, to a certain extent, is subject to general economic,
+financial, competitive, legislative, regulatory, and other factors that are
+beyond our control. If our business does not generate sufficient cash
+flow from operations or future sufficient borrowings are not available to us
+under our 
+25 
+revolving
+credit facility or from other sources we might not be able to service our debt
+or to fund our other liquidity needs. If we are unable to service our
+debt, due to inadequate liquidity or otherwise, we may have to delay or cancel
+acquisitions, sell equity securities, sell assets, or restructure or refinance
+our debt. We might not be able to sell our equity securities, sell
+our assets or restructure or refinance our debt on a timely basis or on
+satisfactory terms or at all. In addition, the terms of our existing
+or future debt agreements, including our existing and future credit agreements,
+may prohibit us from pursuing any of these alternatives. 
+Our debt
+instruments, including our revolving credit agreement, also permit us to incur
+additional debt in the future. In addition, the entities we may
+acquire in the future could have significant amounts of debt outstanding which
+we could be required to assume in connection with the acquisition, or we may
+incur our own significant indebtedness to consummate an
+acquisition. 
+In
+addition, our revolving credit facility is subject to periodic borrowing base
+redeterminations. We could be forced to repay a portion of our bank
+borrowings in the event of a downward redetermination of our borrowing base, and
+we may not have sufficient funds to make such repayment at that
+time. If we do not have sufficient funds and are otherwise unable to
+negotiate renewals of our borrowing base or arrange new financing, we may be
+forced to sell significant assets. 
+We
+are subject to operating and environmental risks and hazards that could result
+in substantial losses. 
+Oil and
+natural gas operations are subject to many risks, including well blowouts,
+craterings, explosions, uncontrollable flows of oil, natural gas or well fluids,
+fires, adverse weather such as hurricanes in the Gulf Coast region, freezing
+conditions, formations with abnormal pressures, pipeline ruptures or spills,
+pollution, releases of toxic gas, and other environmental risks and
+hazards. If any of these types of events occurs, we could sustain
+substantial losses. 
+Under
+certain limited circumstances we may be liable for environmental damage caused
+by previous owners or operators of properties that we own, lease, or
+operate. As a result, we may incur substantial liabilities to third
+parties or governmental entities, which could reduce or eliminate funds
+available for exploration, development, or acquisitions or cause us to incur
+losses. 
+We
+maintain insurance against some, but not all, of these potential risks and
+losses. We have significant but limited coverage for sudden
+environmental damages. We do not believe that insurance coverage for
+the full potential liability that could be caused by sudden environmental
+damages or insurance coverage for environmental damage that occurs over time is
+available at a reasonable cost. In addition, pollution and
+environmental risks generally are not fully insurable. Further, we
+may elect not to obtain other insurance coverage under circumstances where we
+believe that the cost of available insurance is excessive relative to the risks
+presented. Accordingly, we may be subject to liability or may lose
+substantial portions of certain properties in the event of environmental or
+other damages. If a significant accident or other event occurs and is
+not fully covered by insurance, we could suffer a material loss. 
+Following
+the severe Atlantic hurricanes in 2004 and 2005, the insurance markets suffered
+significant losses. As a result, the availability of coverage and the
+cost at which such coverage will be available in the future is uncertain, and
+such coverage has become substantially more expensive. 
+Our
+operations are subject to complex laws and regulations, including environmental
+regulations that result in substantial costs and other risks. 
+Federal,
+state, and local authorities extensively regulate the oil and natural gas
+industry. Legislation and regulations affecting the industry are
+under constant review for amendment or expansion, raising the possibility of
+changes that may affect, among other things, the pricing or marketing of oil and
+natural gas production. Noncompliance with statutes and regulations
+may lead to substantial penalties, and the overall regulatory burden on the
+industry increases the cost of doing business and, in turn, decreases
+profitability. 
+26 
+Governmental
+authorities regulate various aspects of oil and natural gas drilling and
+production, including the drilling of wells (through permit and bonding
+requirements), the spacing of wells, the unitization or pooling of interests in
+oil and natural gas properties, environmental matters, safety standards, the
+sharing of markets, production limitations, plugging and abandonment standards,
+and restoration. To cover the various obligations of leaseholders in
+federal waters, federal authorities generally require that leaseholders have
+substantial net worth or post bonds or other acceptable assurances that such
+obligations will be met. The cost of these bonds or other assurances
+can be substantial, and we may not be able to obtain bonds or other assurances
+in all cases. Under limited circumstances, federal authorities may
+require any of our ongoing or planned operations on federal leases to be
+delayed, suspended or terminated. Any such delay, suspension or
+termination could have a material adverse effect on our
+operations. Our coalbed methane development at Hanging Woman Basin is
+particularly affected, as a portion of our acreage is on federal lands in
+Montana which have been subject to delays in permitting. 
+Our
+operations are also subject to complex and constantly changing environmental
+laws and regulations adopted by federal, state, and local governmental
+authorities in jurisdictions where we are engaged in exploration or production
+operations. New laws or regulations, or changes to current
+requirements, could result in material costs or claims with respect to
+properties we own or have owned. We will continue to be subject to
+uncertainty associated with new regulatory interpretations and inconsistent
+interpretations between state and federal agencies. Under existing or
+future environmental laws and regulations, we could face significant liability
+to governmental authorities and third parties, including joint and several as
+well as strict liability, for discharges of oil, natural gas, or other
+pollutants into the air, soil, or water, and we could be required to spend
+substantial amounts on investigations, litigation, and
+remediation. Existing environmental laws or regulations, as currently
+interpreted or enforced, or as they may be interpreted, enforced, or altered in
+the future, may have a materially adverse effect on us. 
+In
+addition, recent studies have suggested that emissions of certain gases,
+commonly referred to as “greenhouse gases,” may be contributing to warming of
+the Earth’s atmosphere. Methane, a primary component of natural gas,
+and carbon dioxide, a byproduct of the burning of refined oil products and
+natural gas, are examples of greenhouse gases. In response to these
+studies, the U.S. Congress is considering legislation to reduce emissions of
+greenhouse gases. In addition, at least nine states in the Northeast
+and five states in the West have separately taken legal measures to reduce
+emissions of greenhouse gases, primarily through the planned development of
+greenhouse gas emissions inventories and/or regional greenhouse gas cap and
+trade programs. Also, as a result of the U.S. Supreme Court’s
+decision on April 2, 2007 in Massachusetts et al. v.
+Environmental Protection Agency et al. , the U.S. Environmental Protection
+Agency must reconsider whether it is required to regulate greenhouse gas
+emissions from motor vehicles even if Congress does not adopt new legislation
+specifically addressing emissions of greenhouse gases. The Court’s
+holding in Massachusetts that greenhouse
+gases fall under the Federal Clean Air Act’s definition of “air pollutant” may
+also result in future regulation of greenhouse gas emissions from stationary
+sources under certain Clean Air Act programs. Passage of climate
+change legislation or other regulatory initiatives by Congress or various states
+or the adoption of regulations by the EPA or analogous state agencies that
+restrict emissions of greenhouse gases, including methane or carbon dioxide, in
+areas in which we conduct business could adversely affect our operations and the
+demand for our products. 
+We
+depend on transportation facilities owned by others. 
+The
+marketability of our oil and natural gas production depends in part on the
+availability, proximity, and capacity of pipeline transportation systems owned
+by third parties. The lack of available transportation capacity on
+these systems and facilities could result in the shutting-in of producing wells,
+the delay or discontinuance of development plans for properties, or lower price
+realizations. Although we have some contractual control over the
+transportation of our production, material changes in these business
+relationships could materially affect our operations. Federal and
+state regulation of oil and natural gas production and transportation, tax and
+energy policies, changes in supply and demand, pipeline pressures, damage to or
+destruction of pipelines, and general economic conditions could adversely affect
+our ability to produce, gather, and transport oil and natural gas. 
+27 
+Risks
+Related to Our Common Stock 
+The
+price of our common stock may fluctuate significantly, which may result in
+losses for investors. 
+From
+January 1, 2007 to February 15, 2008, the closing daily sales price of
+our common stock as reported by the New York Stock Exchange ranged from a low of
+$31.80 per share to a high of $44.07 per share. We expect our stock
+to continue to be subject to fluctuations as a result of a variety of factors,
+including factors beyond our control. These factors
+include: 
+· 
+Changes
+in oil or natural gas prices 
+· 
+Variations
+in quarterly drilling, recompletions, acquisitions, and operating
+results 
+· 
+Changes
+in financial estimates by securities
+analysts 
+· 
+Changes
+in market valuations of comparable
+companies 
+· 
+Additions
+or departures of key personnel 
+· 
+Future
+sales of our common stock 
+· 
+Changes
+in the national and global economic
+outlook. 
+We may
+fail to meet expectations of our stockholders and/or of securities analysts at
+some time in the future, and our stock price could decline as a
+result. 
+Our
+certificate of incorporation and bylaws have provisions that discourage
+corporate takeovers and could prevent stockholders from receiving a takeover
+premium on their investment. 
+Our
+certificate of incorporation and bylaws contain provisions that may have the
+effect of delaying or preventing a change of control. These
+provisions, among other things, provide for non-cumulative voting in the
+election of the Board of Directors and impose procedural requirements on
+stockholders who wish to make nominations for the election of Directors or
+propose other actions at stockholder meetings. These provisions,
+alone or in combination with each other and with the shareholder rights plan
+described below, may discourage transactions involving actual or potential
+changes of control, including transactions that otherwise could involve payment
+of a premium over prevailing market prices to stockholders for their common
+stock. 
+Under our
+shareholder rights plan, if the Board of Directors determines that the terms of
+a potential acquisition do not reflect the long-term value of St. Mary, the
+Board of Directors could allow the holder of each outstanding share of our
+common stock other than those held by the potential acquirer to purchase one
+additional share of our common stock with a market value of twice the exercise
+price. This prospective dilution to a potential acquirer would make
+the acquisition impracticable unless the terms were improved to the satisfaction
+of the Board of Directors. The existence of the plan may impede a
+takeover not supported by our Board even though such takeover may be desired by
+a majority of our stockholders or may involve a premium over the prevailing
+stock price. 
+Shares
+eligible for future sale may cause the market price of our common stock to drop
+significantly, even if our business is doing well. 
+The
+potential for sales of substantial amounts of our common stock in the public
+market may have a material adverse effect on our stock price. As of
+February 15, 2008, 62,915,531 shares of our common stock were freely tradable
+without substantial restriction or the requirement of future registration under
+the Securities Act of 1933. Also as of that date, options to purchase
+2,367,914 shares of our common stock were outstanding, of which 2,360,414
+were exercisable. These options are exercisable at prices ranging
+from $4.63 to $20.87 per share. In addition, restricted stock units
+providing for the issuance of up to a total of 682,446 shares of our common
+stock were outstanding. As of February 15, 2008, there were 63,020,524
+shares of common stock outstanding, which is net of 1,009,712 treasury
+shares. 
+28 
+We
+may not always pay dividends on our common stock. 
+The
+payment of future dividends remains in the discretion of the Board of Directors
+and will continue to depend on our earnings, capital requirements, financial
+condition, and other factors. In addition, the payment of dividends
+is subject to covenants in our credit facility, including a covenant regarding
+the level of our current ratio of current assets to current liabilities and a
+limit on the annual dividend rate that we may pay to no more than $0.25 per
+share. The Board of Directors may determine in the future to reduce
+the current semi-annual dividend rate of $0.05 per share or discontinue the
+payment of dividends altogether. 
+ITEM
+1B. UNRESOLVED
+STAFF COMMENTS 
+St. Mary
+has no unresolved comments from the SEC staff regarding its periodic or current
+reports under the Securities Exchange Act of 1934. 
+ITEM
+3. LEGAL
+PROCEEDINGS 
+From time
+to time, we may be involved in litigation relating to claims arising out of our
+operations in the normal course of business. As of the date of this
+report, no legal proceedings are pending against us that we believe individually
+or collectively could have a materially adverse effect upon our financial
+condition, results of operations or cash flows. 
+ITEM
+4. SUBMISSION
+OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+There
+were no matters submitted to a vote of our security holders during the fourth
+quarter of 2007. 
+ITEM
+4A. EXECUTIVE
+OFFICERS OF THE REGISTRANT 
+The
+following table sets forth the names, ages and positions held by St. Mary’s
+executive officers. The age of the executive officers is as of
+February 15, 2008. 
+Name 
+Age 
+Position 
+Anthony
+J. Best 
+58 
+Chief
+Executive Officer and President 
+Javan
+D. Ottoson 
+49 
+Executive
+Vice President and Chief Operating Officer 
+David
+W. Honeyfield* 
+41 
+Senior
+Vice President - Chief Financial Officer and Secretary 
+Mark
+D. Mueller 
+43 
+Senior
+Vice President and Regional Manager 
+Stephen
+C. Pugh 
+49 
+Senior
+Vice President and Regional Manager 
+Paul
+M. Veatch 
+41 
+Senior
+Vice President and Regional Manager 
+Jerold
+M. Hertzler 
+50 
+Vice
+President - Business Development 
+Gregory
+T. Leyendecker 
+50 
+Vice
+President - Regional Manager 
+Lehman
+E. Newton, III 
+52 
+Vice
+President - Regional Manager 
+Milam
+Randolph Pharo 
+55 
+Vice
+President - Land and Legal and Assistant Secretary 
+Garry
+A. Wilkening 
+57 
+Vice
+President - Human Resources and Administration 
+Mark
+T. Solomon 
+39 
+Controller 
+*Mr.
+Honeyfield has announced that he will resign from his position of Senior Vice
+President - Chief Financial Officer and Secretary effective March 21, 2008,
+in order to pursue an opportunity in an unrelated industry. 
+Each
+executive officer has held his respective position during the past five years,
+except as follows: 
+Anthony
+J. Best joined St. Mary in June 2006 as President and Chief Operating
+Officer. In December 2006, Mr. Best relinquished his position as
+Chief Operating Officer when Javan D. Ottoson was elected to that
+office. Mr. Best was elected Chief Executive Officer of St. Mary in
+February 2007. From November 2005 to 
+29 
+June
+2006, Mr. Best was developing a business plan and attempting to raise capital
+for a start-up exploration and production entity. From 2003 to
+October 2005, Mr. Best was President and Chief Executive Officer of Pure
+Resources, Inc., a subsidiary of Unocal Corporation, where he managed all of
+Unocal’s onshore U.S. assets. From 2000 to 2002, Mr. Best had an oil and gas
+consulting practice working with public, private, and small startup exploration
+and production firms. From 1979 to 2000, Mr. Best was with ARCO in a
+variety of positions, including a period as President - ARCO Permian, President
+- ARCO Latin America, Field Manager for Prudhoe Bay, and VP - External Affairs
+for ARCO Alaska. 
+Javan D.
+Ottoson joined St. Mary in December 2006 as Executive Vice President and Chief
+Operating Officer. Mr. Ottoson has been in the oil and gas industry
+for over 20 years. From April 2006 until he joined St. Mary in
+December 2006, Mr. Ottoson was Senior Vice President – Drilling and Engineering
+at Energy Partners, Ltd. Mr. Ottoson managed the Permian Basin assets
+for Pure Resources, Inc., a subsidiary of Unocal Corporation, and its successor
+owner, Chevron, from July 2003 to April 2006. From April 2000 to July
+2003, Mr. Ottoson owned and operated a homebuilding company in Colorado and ran
+his family farm. Prior to 2000, Mr. Ottoson worked for ARCO in
+management and operational roles. These roles included President -
+ARCO China, Commercial Director of ARCO British, and Vice President of
+Operations and Development - ARCO Permian. 
+David W.
+Honeyfield was appointed as Chief Financial Officer in May 2005 and Senior Vice
+President in March 2007. Mr. Honeyfield joined St. Mary in May
+2003 as Vice President - Finance, Treasurer and Secretary. Prior to
+joining St. Mary, Mr. Honeyfield was Controller and Chief Accounting
+Officer of Cimarex Energy from September 2002 to May 2003 and Controller and
+Chief Accounting Officer of Key Production Company, Inc., which was acquired by
+Cimarex in September 2002. Prior to joining Key Production Company in
+April 2002, Mr. Honeyfield was a senior audit manager with Arthur Andersen
+LLP in Denver. Mr. Honeyfield had been with Arthur Andersen since
+January 1991. 
+Mark D.
+Mueller joined St. Mary in September 2007 as Senior Vice
+President. Mr. Mueller was appointed as the Regional Manager of the
+Rocky Mountain region effective January 1, 2008. Mr. Mueller has been
+in the energy industry for 21 years and was Vice President and General Manager
+at Samson Exploration Ltd. in Calgary, Canada from September 2006 to September
+2007. Mr. Mueller was Vice President and General Manager for Samson
+Canada Ltd. from April 2005 until its sale in August 2006. Mr.
+Mueller joined Samson Canada Ltd. as Project Manager in May 2003 to build a new
+basin-centered gas business unit and was Vice President from December 2003 to
+August 2006. Prior to joining Samson, Mr. Mueller was West Central
+Alberta Engineering Manager for Northrock Resources Ltd. (a wholly-owned
+subsidiary of Unocal Corporation) in Calgary, Canada. From 1986 to
+2003, Mr. Mueller held positions of increasing responsibility in engineering and
+management for Unocal throughout North America and Southeast Asia. 
+Stephen
+C. Pugh joined St. Mary as Senior Vice President and Regional Manager of the
+ArkLaTex region in July 2007. Stephen Pugh has over 26 years of
+experience in the oil and gas industry. He was a Managing Director
+for Scotia Waterous in the Houston office from July 2006 to July
+2007. Prior to joining Scotia Waterous, Mr. Pugh had over 17 years of
+experience in acquisition and divestiture, operations and engineering with
+Burlington Resources (subsequently ConocoPhillips). His most recent
+title there was General Manager, Engineering and Operations – Gulf Coast, a
+position he held from May 2004 to June 2006. Prior to that, he was
+Vice President - Acquisitions and Divestitures for Burlington Resources Canada.
+He held that position from May 2000 to May 2004. Mr. Pugh began his
+career with Superior Oil (subsequently Mobil Oil) in Lafayette, Louisiana, where
+he worked in production, drilling, and reservoir engineering. 
+30 
+Paul M.
+Veatch was appointed Senior Vice President and Regional Manager of the
+Mid-Continent region in March 2006. Mr. Veatch joined St. Mary in
+April 2001 as Regional Acquisition and Divestiture Engineer of the ArkLaTex
+region. He was Manager of Engineering from April 2003 to August 2004
+and Vice President – General Manager, ArkLaTex from August 2004 to March
+2006. Prior to joining St. Mary, Mr. Veatch worked in various
+engineering and supervisory roles at Burlington Resources from November 1994 to
+April 2001. Prior to joining Burlington Resources, Mr. Veatch held
+various engineering and operations positions for Arco Oil & Gas Company
+(subsequently Vastar Resources) in Louisiana and Texas from July 1989 until
+November 1994. 
+Jerold M.
+Hertzler was appointed Vice President - Business Development in March
+2007. Mr. Hertzler joined St. Mary in October 1998 as Manager of
+Reservoir Engineering. He assumed the role of Acquisitions Manager in
+July 2003 and was promoted to Director and Business Development in March
+2005. Mr. Hertzler entered the petroleum industry in December of
+1979 and has served in various operations and reservoir engineering roles since
+then, including nine years with Tenneco Oil Company and seven years with
+Meridian Oil Company. 
+Gregory
+T. Leyendecker was appointed Vice President - Regional Manager of the Gulf Coast
+region in July 2007. Mr. Leyendecker joined St. Mary in December
+2006 as Operations Manager for the Gulf Coast region in Houston. Mr.
+Leyendecker has worked for 27 years in the energy industry and held various
+positions with the Unocal Corporation from 1980 until its acquisition in
+2005. During this time he was the Asset Manager for Unocal Gulf
+Region USA from 2003 to June 2004 and Production and Reservoir Engineering
+Technology Manager for Unocal from June 2004 to August 2005. He was
+appointed Drilling and Workover Manager for Chevron’s San Joaquin Valley
+business unit in Bakersfield, California in August 2005 and held this position
+until January 2006. Immediately prior to joining St. Mary, Mr. Leyendecker was
+Vice President of Drilling Management Services for Enventure Global Technology,
+a position he held from February 2006 to November 2006. 
+Lehman E.
+Newton III joined St. Mary in December 2006 as General Manager for the Midland
+office and was appointed Vice President - Regional Manager of the Permian region
+in June 2007. Mr. Newton has over 27 years of exploration and
+production experience in engineering, operations and business
+development. From November 2005 to November 2006 Mr. Newton served as
+Project Manager for one of Chevron’s largest projects in the continental United
+States. Mr. Newton joined Pure Resources in February 2003 as the
+Business Development Manager and worked in that capacity until October
+2005. Mr. Newton was a founding partner in Westwin Energy, an
+independent exploration and production company in the Permian Basin, from June
+2000 to January 2003. Prior to that, Mr. Newton spent 21 years with
+ARCO in various engineering, operations and management roles. These
+assignments included Asset Manager, ARCO’s East Texas operations, Vice
+President, Business Development, ARCO Permian, and Vice President of Operations
+and Development, ARCO Permian. 
+Garry A.
+Wilkening was appointed Vice President - Human Resources and Administration in
+November 2007 and served as Vice President of Administration from January 2007
+to November 2007. Mr. Wilkening relinquished his position as
+Controller in January 2007 when Mark T. Solomon was elected to that
+office. Mr. Wilkening was Vice President - Administration and
+Controller from 1999 to 2007. 
+31 
+Mark T.
+Solomon was appointed Controller in January 2007. Mr. Solomon joined
+St. Mary in 1996. He served as Financial Reporting Manager from
+February 1999 to September 2002, Assistant Vice President of Financial Reporting
+from September 2002 to May 2006 and Assistant Vice President and Assistant
+Controller from May 2006 to January 2007. Prior to joining St. Mary, Mr. Solomon
+was an auditor with Ernst & Young. 
+Executive
+officers generally are elected at the regular meeting of the Board immediately
+following the annual stockholders meeting, to serve for the ensuing year or
+until their successors are duly qualified and elected. The executive
+officers of St. Mary do not have fixed terms and serve at the discretion of the
+Board of Directors. Any officer elected by the Board may be removed
+by the Board with or without cause, subject to any contractual rights of the
+person so removed. 
+Mr. Best
+has an employment agreement with St. Mary. Upon any termination of
+the employment of Mr. Best by St. Mary for any reason other than death,
+disability, or misconduct by Mr. Best, St. Mary is generally obligated to
+continue to pay his base salary and insurance benefits for a period of two years
+after termination. In addition, upon commencement of employment, Mr.
+Best received a cash bonus and a special restricted stock award of 20,000 shares
+that are vested immediately and not subject to forfeiture. Over the
+next two years Mr. Best is also eligible to earn additional restricted
+shares in varying amounts, a portion of which are based on the Company’s net
+asset value growth. 
+There are
+no family relationships between any executive officer and any other executive
+officer or director. There are no arrangements or understandings
+between any officer and any other person pursuant to which that officer was
+elected. 
+32 
+PART
+II 
+ITEM
+5. 
+MARKET
+FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
+PURCHASES OF EQUITY SECURITIES 
+Market
+Information . St. Mary's common stock is currently traded
+on the New York Stock Exchange under the symbol SM. The range of high
+and low sales prices for the quarterly periods in 2007 and 2006, as reported by
+the New York Stock Exchange. 
+Quarter
+Ended 
+High 
+Low 
+December
+31, 2007 
+$ 
+44.50 
+$ 
+35.40 
+September
+30, 2007 
+37.15 
+31.20 
+June
+30, 2007 
+40.19 
+34.91 
+March
+31, 2007 
+38.20 
+33.55 
+December
+31, 2006 
+$ 
+40.85 
+$ 
+33.43 
+September
+30, 2006 
+43.92 
+34.77 
+June
+30, 2006 
+45.59 
+34.38 
+March
+31, 2006 
+44.69 
+34.70 
+33 
+PERFORMANCE
+GRAPH 
+The
+following performance graph compares the cumulative total stockholder return on
+St. Mary’s common stock for the period December 31, 2002, to December 31, 2007,
+with the cumulative total return of the Dow Jones U.S. Exploration and
+Production Broad Index, and the Standard & Poor’s 500 Stock
+Index. 
+COMPARE
+5-YEAR CUMULATIVE TOTAL RETURN 
+AMONG
+ST. MARY LAND & EXPLORATION COMPANY 
+The
+preceding information under the caption “Performance Graph” shall be deemed to
+be “furnished” but not “filed” with the Securities and Exchange
+Commission. 
+Holders . As of
+February 15, 2008, the number of record holders of St. Mary's common stock
+was 116. Based on inquiry, management believes that the number of
+beneficial owners of our common stock is approximately 21,700. 
+Dividends . St. Mary
+has paid cash dividends to stockholders every year since
+1940. Semi-annual dividends of $0.025 per share were paid in each of
+the years 1998 through 2004. Semi-annual dividends of $0.05 per share
+were paid in 2005, 2006 and 2007. We expect that our practice of
+paying dividends on our common stock will continue, although the payment of
+future dividends will continue to depend on our earnings, capital requirements,
+financial condition, and other factors. In addition, the payment of
+dividends is subject to covenants in our credit facility, including the
+requirement that we maintain certain levels of stockholders’ equity and the
+limitation of our annual dividend rate to no more than $0.25 per share per
+year. Dividends are currently paid on a semi-annual
+basis. Dividends paid totaled $6.3 million in 2007. 
+Restricted
+Shares. Aside from Rule 144 restrictions on shares for
+insiders, shares subject to transfer restrictions under the provisions of the
+Employee Stock Purchase Plan, restricted shares issued to directors under the
+Non-Employee Director Stock Compensation Plan, and restricted shares issued to
+directors under the 2006 Equity Incentive Compensation Plan (the “2006 Equity
+Plan”), St. Mary has no restricted shares outstanding as of December 31,
+2007. 
+34 
+Equity Compensation
+Plans . St. Mary has the 2006 Equity Plan under which
+options and shares of St. Mary common stock are authorized for grant or
+issuance as compensation to eligible employees, consultants, and members of the
+Board of Directors. Our stockholders have approved this
+plan. See Note 7 - Compensation Plans in the Notes to Consolidated
+Financial Statements included in Part IV, Item 15 of this report for further
+information about the material terms of these plans. The following
+table is a summary of the shares of common stock authorized for issuance under
+our equity compensation plans as of December 31, 2007: 
+( a
+) 
+( b
+) 
+( c
+) 
+Plan
+Category 
+Number
+of securities to be issued upon exercise of outstanding options, warrants,
+and rights 
+Weighted-average
+exercise price of outstanding options, warrants, and
+rights 
+Number
+of securities remaining available for future issuance under equity
+compensation plans (excluding securities reflected in column
+(a)) 
+2006
+Equity Incentive Compensation Plan 
+Stock
+Options and Incentive Stock Options 
+2,385,500 
+$ 
+12.62 
+- 
+(1 
+) 
+Restricted
+Stock Plan 
+684,264 
+N/A 
+2,560,224 
+(1 
+) 
+Employee
+Stock Purchase Plan 
+- 
+- 
+1,599,811 
+(2 
+) 
+Equity
+compensation plans not approved by security holders 
+- 
+- 
+- 
+Total 
+3,069,764 
+$ 
+12.62 
+4,160,035 
+______________ 
+(1) In
+May 2006 the stockholders approved the 2006 Equity Plan to authorize the
+issuance of restricted stock, restricted stock units, non-qualified stock
+options, incentive stock options, stock appreciation rights, and stock-based
+awards to key employees, consultants, and members of the Board of Directors of
+St. Mary or any affiliate of St. Mary. The 2006 Equity Plan serves as
+the successor to the St. Mary Land & Exploration Company Stock Option
+Plan, the St. Mary Land & Exploration Company Incentive Stock
+Option Plan, the St. Mary Land & Exploration Company Restricted Stock
+Plan, and the St. Mary Land & Exploration Company Non-Employee Director
+Stock Compensation Plan (collectively, the “Predecessor Plans”). All
+grants of equity are now made out of the 2006 Equity Plan, and no further grants
+will be made under the Predecessor Plans. Each outstanding award
+under a Predecessor Plan immediately prior to the effective date of the 2006
+Equity Plan continues to be governed solely by the terms and conditions of the
+instruments evidencing such grants or issuances. Awards granted in
+2007, 2006, and 2005 under the 2006 Equity Plan and the Predecessor Plans were
+135,138, 527,678, and 209,238, respectively. 
+(2) Under
+the St. Mary Land & Exploration Company Employee Stock Purchase Plan,
+eligible employees may purchase shares of the Company’s common stock through
+payroll deductions of up to 15 percent of their eligible
+compensation. The purchase price of the stock is 85 percent of the
+lower of the fair market value of the stock on the first or last day of the
+purchase period, and shares issued under the Employee Stock Purchase Plan are
+restricted for a period of 18 months from the date issued. The
+Employee Stock Purchase Plan is intended to qualify under Section 423 of the
+Internal Revenue Code. There have been 29,534, 26,046, and 28,447
+shares issued under this plan in 2007, 2006, and 2005,
+respectively. 
+35 
+The
+following table provides information about purchases by the Company or
+“affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act)
+during the quarters and year ended December 31, 2007, of shares of the
+Company’s common stock, which is the sole class of equity securities registered
+by the Company pursuant to Section 12 of the Exchange Act. 
+PURCHASES
+OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS 
+Total
+Number of Shares Purchased 
+Average
+Price Paid per Share 
+Total
+Number of Shares Purchased as Part of Publicly Announced
+Program 
+Maximum
+Number of Shares that May Yet be Purchased Under the Program (2) 
+January
+1, 2007 – 
+March 31, 2007 
+- 
+$ 
+- 
+- 
+6,000,000 
+April
+1, 2007 - 
+June 30, 2007 
+- 
+$ 
+- 
+- 
+6,000,000 
+July
+1, 2007 - 
+September 30,
+2007 
+791,816 
+(1) 
+$ 
+32.76 
+790,816 
+5,209,184 
+October
+1, 2007 - 
+October 31,
+2007 
+- 
+$ 
+- 
+- 
+5,209,184 
+November
+1, 2007 - 
+November 30,
+2007 
+- 
+$ 
+- 
+- 
+5,209,184 
+December
+1, 2007 - 
+December 31,
+2007 
+1,400 
+$ 
+37.52 
+1,400 
+5,207,784 
+Total
+October 1, 2007 - 
+December 31,
+2007 
+1,400 
+$ 
+37.52 
+1,400 
+5,207,784 
+Total 
+793,216 
+$ 
+32.76 
+792,216 
+5,207,784 
+(1) 
+Includes a total of 1,000 shares purchased by Anthony J. Best, St. Mary’s
+President and Chief Executive Officer, in open market transactions that were not
+made pursuant to our stock repurchase program. The table does not
+include the 678 shares purchased by Mr. Best under the Company’s employee stock
+purchase plan. 
+(2) In
+July 2006 the Company’s Board of Directors approved an increase in the number of
+shares that may be repurchased under the original August 1998 authorization to
+6,000,000 as of the effective date of the resolution. Accordingly, as
+of the date of this filing, the Company has Board authorization to repurchase
+5,207,784 shares of common stock on a prospective basis. The shares
+may be repurchased from time to time in open market transactions or privately
+negotiated transactions, subject to market conditions and other factors,
+including certain provisions of St. Mary’s existing bank credit facility
+agreement and compliance with securities laws. Stock repurchases may
+be funded with existing cash balances, internal cash flow, and borrowings under
+St. Mary’s bank credit facility. The stock repurchase program may be suspended
+or discontinued at any time. 
+The stock repurchases are subject to
+covenants in our bank credit facility, including the requirement that we
+maintain certain levels of stockholders’ equity . 
+36 
+ITEM
+6. SELECTED
+FINANCIAL DATA 
+The
+following table sets forth supplemental selected financial and operating data
+for St. Mary as of the dates and for the periods indicated. The
+financial data for each of the five years presented were derived from the
+consolidated financial statements of St. Mary. The following
+data should be read in conjunction with "Management's Discussion and Analysis of
+Financial Condition and Results of Operations," which includes a discussion of
+factors materially affecting the comparability of the information presented, and
+in conjunction with St. Mary's consolidated financial statements included
+in this report. In March 2005 the Company’s Board of Directors
+approved a two-for-one stock split in the form of a stock dividend whereby one
+additional share of common stock was distributed for each common share
+outstanding. The stock dividend was distributed on March 31, 2005, to
+shareholders of record as of the close of business on
+March 21, 2005. All share and per share amounts for all
+prior periods presented herein have been reclassified to reflect this stock
+split. 
+Years
+Ended December 31, 
+2007 
+2006 
+2005 
+2004 
+2003 
+(In
+thousands, except per share data) 
+Total
+operating revenues 
+$ 
+990,094 
+$ 
+787,701 
+$ 
+739,590 
+$ 
+433,099 
+$ 
+393,708 
+Income
+before cumulative effect of change in accounting
+principle 
+$ 
+189,712 
+$ 
+190,015 
+$ 
+151,936 
+$ 
+92,479 
+$ 
+90,140 
+Net
+income per share: 
+Basic 
+$ 
+3.07 
+$ 
+3.38 
+$ 
+2.67 
+$ 
+1.60 
+$ 
+1.53 
+Diluted 
+$ 
+2.94 
+$ 
+2.94 
+$ 
+2.33 
+$ 
+1.44 
+$ 
+1.40 
+Total
+assets at year end 
+$ 
+2,571,680 
+$ 
+1,899,097 
+$ 
+1,268,747 
+$ 
+945,460 
+$ 
+735,854 
+Long-term
+obligations: 
+Line
+of credit 
+$ 
+285,000 
+$ 
+334,000 
+$ 
+- 
+$ 
+37,000 
+$ 
+11,000 
+Senior
+convertible notes 
+$ 
+287,500 
+$ 
+99,980 
+$ 
+99,885 
+$ 
+99,791 
+$ 
+99,696 
+Cash
+dividends declared and paid per common share 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.05 
+$ 
+0.05 
+37 
+Supplemental
+Selected Financial and Operational Data: 
+Years
+Ended December 31, 
+2007 
+2006 
+2005 
+2004 
+2003 
+( In thousands, except per share
+data ) 
+Balance
+Sheet Data: 
+Total
+working capital (deficit) 
+$ 
+(92,604 
+) 
+$ 
+22,870 
+$ 
+4,937 
+$ 
+12,035 
+$ 
+3,101 
+Total
+stockholders’ equity 
+$ 
+863,345 
+$ 
+743,374 
+$ 
+569,320 
+$ 
+484,455 
+$ 
+390,653 
+Weighted-average 
+shares
+outstanding : 
+Basic 
+61,852 
+56,291 
+56,907 
+57,702 
+62,467 
+Diluted 
+64,850 
+65,962 
+66,894 
+66,894 
+71,069 
+Reserves: 
+Oil
+(MMBbl) 
+78.8 
+74.2 
+62.9 
+56.6 
+47.8 
+Gas
+(Mcf) 
+613.5 
+482.5 
+417.1 
+319.2 
+307.0 
+MCFE 
+1,086.5 
+927.6 
+794.5 
+658.6 
+593.7 
+Production
+and Operational: 
+Oil
+and gas production revenues, including hedging 
+$ 
+936,577 
+$ 
+758,913 
+$ 
+711,005 
+$ 
+413,318 
+$ 
+365,114 
+Oil
+and gas production expenses 
+$ 
+218,208 
+$ 
+176,590 
+$ 
+142,873 
+$ 
+95,518 
+$ 
+88,509 
+DD&A 
+$ 
+227,596 
+$ 
+154,522 
+$ 
+132,758 
+$ 
+92,223 
+$ 
+81,960 
+General
+and administrative 
+$ 
+60,149 
+$ 
+38,873 
+$ 
+32,756 
+$ 
+22,004 
+$ 
+21,197 
+Production
+Volumes: 
+Oil
+(MMBbl) 
+6.9 
+6.1 
+5.9 
+4.8 
+4.5 
+Gas
+(Bcf) 
+66.1 
+56.4 
+51.8 
+46.6 
+49.7 
+BCFE 
+107.5 
+92.8 
+87.4 
+75.4 
+76.9 
+Realized
+Price – pre hedging: 
+Per
+Bbl 
+$ 
+67.56 
+$ 
+59.33 
+$ 
+53.18 
+$ 
+39.77 
+$ 
+29.40 
+Per
+Mcf 
+$ 
+6.74 
+$ 
+6.58 
+$ 
+8.08 
+$ 
+5.85 
+$ 
+5.12 
+Realized
+Price – net of hedging: 
+Per
+Bbl 
+$ 
+62.60 
+$ 
+56.60 
+$ 
+50.93 
+$ 
+32.53 
+$ 
+26.96 
+Per
+Mcf 
+$ 
+7.63 
+$ 
+7.37 
+$ 
+7.90 
+$ 
+5.52 
+$ 
+4.89 
+Expense
+per MCFE: 
+LOE 
+$ 
+1.31 
+$ 
+1.25 
+$ 
+0.99 
+$ 
+0.81 
+$ 
+0.77 
+Transportation 
+$ 
+0.14 
+$ 
+0.12 
+$ 
+0.09 
+$ 
+0.10 
+$ 
+0.09 
+Production
+taxes 
+$ 
+0.58 
+$ 
+0.54 
+$ 
+0.56 
+$ 
+0.36 
+$ 
+0.29 
+DD&A 
+$ 
+2.12 
+$ 
+1.67 
+$ 
+1.52 
+$ 
+1.22 
+$ 
+1.07 
+General
+and administrative 
+$ 
+0.56 
+$ 
+0.42 
+$ 
+0.37 
+$ 
+0.29 
+$ 
+0.28 
+Cash
+Flow: 
+From
+operations 
+$ 
+630,792 
+$ 
+467,700 
+$ 
+409,379 
+$ 
+237,162 
+$ 
+204,319 
+Used
+in investing 
+$ 
+(803,872 
+) 
+$ 
+(724,719 
+) 
+$ 
+(339,779 
+) 
+$ 
+(247,006 
+) 
+$ 
+(196,939 
+) 
+From
+(used in) financing 
+$ 
+215,126 
+$ 
+243,558 
+$ 
+(61,093 
+) 
+$ 
+1,435 
+$ 
+(3,707 
+) 
+38 
+ITEM
+7. 
+MANAGEMENT’S
+DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
+OPERATIONS 
+This
+discussion includes forward-looking statements. Please refer to
+“Cautionary Information about Forward-Looking Statements” in Part I, Items 1 and
+2 of this Form 10-K for important information about these types of
+statements. 
+Overview
+of the Company 
+General
+Overview 
+We are an
+independent energy company focused on the development, exploration,
+exploitation, acquisition, and production of natural gas and crude oil in the
+United States. We earn 95 percent of our revenues and generate our
+cash flows from operations primarily from the sale of produced natural gas and
+crude oil. Our oil and gas reserves and operations are concentrated
+primarily in various Rocky Mountain basins, including the Williston, Big Horn,
+Wind River, Powder River and Greater Green River basins; the Mid-Continent
+Anadarko and Arkoma basins; the Permian Basin; the tight sandstone reservoirs of
+East Texas and North Louisiana; South Texas assets targeting the Olmos shallow
+gas formation; and the onshore Gulf Coast and offshore Gulf of
+Mexico. We have developed a balanced and diverse portfolio of proved
+reserves, development drilling opportunities, and unconventional resource
+prospects. 
+In 2007,
+we achieved the following financial and operational results: 
+· 
+Average
+daily gas production of 181.0 MMcf per day, up 17 percent from
+2006. Average daily oil production of 18.9 MBbl per day, up 14
+percent from 2006. Average total equivalent daily production
+was 294.5 MMCFE which was an annual record for the
+Company. 
+· 
+Estimated
+proved reserves of 78.8 MMBbls of oil and 613.5 Bcf of natural gas, or
+1,086.5 BCFE, as of December 31, 2007. This was an increase of
+17 percent from year-end 2006 proved reserves of 927.6
+BCFE. 
+· 
+Diluted
+earnings per share for 2007 were $2.94 on net income of $189.7
+million. This reflects a slight decrease in net income
+when compared to 2006. The earnings per share benefited from
+the 0.8 million shares acquired by the Company during
+2007. 
+· 
+Cash
+flow from operating activities of $630.8 million, an increase of 35
+percent from 2006. 
+· 
+Debt
+to capitalization ratio is 40 percent. The 2007 amount does not
+consider proceeds from our divestiture of non-core assets that closed on
+January 31, 2008, described in Note 3 of Part IV, Item 15 of this report,
+which were used to pay down outstanding bank
+borrowings. 
+Our
+business objective is to economically grow our production and proved reserves
+through development, exploitation, and exploration activities, as well as
+through acquisitions of developed and undeveloped properties. Our
+operations are generally funded first through cash flows from operating
+activities, and then borrowings under our existing credit
+facility. Acquisitions may be funded with proceeds from sales of
+public or private debt and equity, borrowings under our existing credit
+facility, and cash flow from operating activities. In 2007, we
+deployed $740.9 million for development and exploration and invested
+$185.2 million for acquisitions of oil and gas properties. 
+A major
+determinant of the value of our Company is the value of our proved
+reserves. At year-end 2007, we had proved reserves of 1,086.5 BCFE of
+which 56 percent were natural gas and 77 percent were characterized as proved
+developed. Based on our year-end oil and gas reserve estimation
+process, we determined that we added 94.8 BCFE of proved reserves through
+acquisitions in 2007, 96 percent of which was natural gas and 42 percent
+of which was proved developed. Upward price revisions resulted
+in an increase of 34.5 BCFE which were driven primarily by higher oil
+prices at December 31, 2007, compared to the prior year. We
+experienced positive 
+39 
+performance
+revisions of 6.4 BCFE and divested 1.4 BCFE of proved reserves. The
+before income tax PV-10 value of our proved reserves was $3.9 billion as of
+December 31, 2007. The after tax value of $2.7 billion as represented
+by the standardized measure calculation is presented in Note 13 of Part IV, Item
+15 of this report. A reconciliation between these two amounts is
+shown under Reserves in Part I, Items 1 and 2 of this report. This
+value is based on adjusted year-end pricing of $7.56 per Mcf and $88.71 per Bbl,
+which are up 36 percent and 65 percent, respectively, from the prior
+year. 
+Chief
+Executive Officer, Chief Financial Officer and Senior and Regional Management
+Transitions 
+During
+2007, the Company underwent or announced personnel changes in the chief
+executive position and several regional manager positions. On
+February 23, 2007, Mark Hellerstein, retired as Chief Executive Officer after
+serving in that role since 1995. Tony Best, President of the Company,
+was appointed as Chief Executive Officer on that date. Mr.
+Hellerstein continues to serve as the Chairman of the Board. In June
+2007, Jerry Schuyler, the Senior Vice President responsible for the Gulf Coast
+and Permian regions, left St. Mary to pursue other professional
+opportunities. Greg Leyendecker, then Operations Manager for the Gulf
+Coast region, assumed responsibility for the Gulf Coast and is now Vice
+President - Regional Manager of the Gulf Coast region. We also made
+the Midland office a stand-alone regional office which is headed by Lehman
+Newton III, as Vce President - Regional Manager of the Permian
+region. Mr. Leyendecker and Mr. Newton both joined St. Mary in 2006
+and each have over 25 years of management and operational experience in the oil
+and gas industry. In July 2007, Stephen Pugh joined the Company as
+Senior Vice President - Regional Manager of the ArkLaTex region. Mr.
+Pugh succeeded David Hart, who retired from St. Mary after 15 years in various
+roles at the Company. Mr. Pugh came to St. Mary with over 25 years of
+engineering, operations, and business development experience in the oil and gas
+industry. In August of this year, Robert Nance, Senior Vice President
+- Regional Manager of the Rocky Mountain region announced his decision to retire
+in the first quarter of 2008 after more than 40 years in the oil and gas
+industry. Mark Mueller joined the Company as Senior Vice President
+in September and is now responsible for the Rocky Mountain
+region. Mr. Mueller has 20 years of management and technical
+experience in the oil and gas industry. Effective January 1, 2008,
+Mark Mueller became the Senior Vice President and Regional
+Manager. Subsequent to year end, David Honeyfield, Senior Vice
+President - Chief Financial Officer, announced he will resign effective March
+21, 2008, to accept an executive position in an unrelated industry. 
+2007
+Acquisition of South Texas Oil and Natural Gas Assets 
+We
+entered the greater Maverick Basin with two acquisitions in South Texas that
+target the Olmos shallow gas formation. These two
+acquisitions comprised the majority of the 94.8 BCFE of reserves classified as
+purchases of minerals in place. These properties added a
+sizable inventory of lower risk drilling locations to our
+portfolio. The first was the $30.0 million Catarina acquisition that
+closed in June 2007, in which we acquired 14.0 BCFE of proved reserves that were
+99 percent gas and 65 percent proved developed. The average working
+interest in these assets is 30 percent; however we are the operator of the
+project area. The more significant transaction was the $148.9 million
+Rockford acquisition that closed in October 2007, where we have a nearly 100
+percent working interest and are the operator. As mentioned elsewhere
+in this report, the final year-end reserve estimates we recorded were lower than
+the initial estimates we previously disclosed at the time of
+acquisition. We initially estimated reserves on a dry gas basis in
+our previous disclosure at the time of the acquisition whereas our annual report
+on Form 10-K disclosures utilize a wet gas presentation
+convention. This accounted for approximately ten BCFE of the
+difference in volumes, without any impact on value. The remaining
+difference was a result of our final year end assessment of proved non-producing
+reserves and our proved undeveloped reserves which were each lower than the
+amounts preliminarily estimated at the time of acquisition. The
+Rockford properties are adjacent to the Catarina assets. Consistent
+with prior acquisitions, we hedged several years of risked production related to
+these assets at the time of acquisition. These assets will be managed
+by our Gulf Coast region based in Houston, Texas. 
+2007
+Capital Markets Activity 
+In March
+of 2007 we called for redemption of the then outstanding $100.0 million 5.75%
+Senior Convertible Notes. The notes had a conversion price of $13.00 per
+share. One hundred percent of the holders of the notes elected to convert
+their notes into shares of common stock. As a result of the conversion,
+7.7 million shares of stock were issued to the note holders. This resulted
+in a decrease to long-term debt of $100.0 million, and an increase to common
+stock associated with the conversion together with the recognition of the excess
+tax benefit 
+40 
+associated
+with the contingent interest feature associated with the notes. In April
+of 2007, we completed the private placement of $287.5 million of 3.50%
+Senior Convertible Notes. The net proceeds from the 3.50% Senior
+Convertible Notes were used to repay outstanding borrowings under our revolving
+credit facility. 
+Reserve
+Replacement, Finding Costs and Growth 
+Like all
+oil and gas exploration and production companies, we face the challenge of
+natural production declines of oil and natural gas resources. An oil
+and gas exploration and production company depletes part of its asset base with
+each unit of oil and gas it produces. Historically, we have been able
+to grow our production despite this natural decline by adding more reserves
+through acquisitions and drilling activities than we produce. Future
+growth will depend on our ability to economically continue adding reserves in
+excess of production. 
+We
+believe growth in net asset value per share drives appreciation in our stock
+price over the long term. Our challenge is to grow net asset value
+per share. To accomplish this, our goal is to economically replace at
+least 200 percent of annual production with new reserves and to grow production
+by ten to 15 percent per year. In 2007, we replaced 248 percent of our
+production at a finding cost of $3.48 per MCFE. The reserve
+replacement percentages and finding cost terms are defined in the glossary at
+the end of Part I, Items 1 and 2 of this report. Excluding
+acquisitions, we replaced 161 percent of our production at a cost of $4.42
+per MCFE. Through acquisition activities we replaced 88 percent of
+production at an acquisition cost of $1.71 per MCFE. We sold reserves
+representing 1.4 BCFE of our proved reserves during 2007. We believe
+annual reserve replacement percentage and finding cost amounts are important
+analytical measures that are widely used by investors and industry peers in
+evaluating and comparing the performance of oil and gas
+companies. While single year measurements have some meaning in terms
+of a trend, we believe that evaluating these items over an extended period of
+time is a better indication of performance. We note that aberrations,
+causing both relatively good and bad results, will occur over short intervals of
+time. Our three-year average reserve replacement ratio – including
+sales is 249 percent and our three-year average all-in finding cost is $3.01 per
+MCFE. Our finding cost numbers, particularly those related to
+drilling activities, have been notably higher in recent years. Part
+of this is explained by increases in completed well costs that have occurred in
+recent years which have affected all exploration and production
+companies. A significant part has related to the performance of our
+capital investments being less than anticipated. We will need to see
+an improvement in the types of projects we are pursuing and/or see an
+improvement in our operating abilities to meaningfully bring our finding cost
+numbers down. We believe that we have taken steps through recent
+acquisitions and portfolio screenings to improve the projects in which we are
+investing. Our operating teams are also performing technological
+reviews to see where we can improve our operations. 
+Sustainability
+in our business is dependent on the ability to create new ideas and new value
+year-after-year. The challenges we face are increasingly more
+difficult each year as North American oil and gas production continues to
+decline and other exploration and production companies compete for available
+reserves. We believe we have a formula for meeting these
+challenges. We have placed talented geoscientists, engineers, and
+landmen in each of our regional offices where their experience and knowledge of
+the local area can be fully utilized. We provide a compensation
+package that aligns their goals with those of the Company and in turn with those
+of our stockholders. We support our personnel with a strong balance
+sheet and fiscal and operating discipline. Even so, we are subject to
+similar constraints as other companies in the exploration and production
+industry. Limitations to future growth will be based on overall
+availability of additional qualified personnel and the generation of new ideas
+and the utilization of appropriate technology to improve the economics of our
+operations. We believe that we have sufficient capital resources for
+the foreseeable future, that we have the ability to grow our workforce, and that
+we have the necessary access to drilling rigs and services to execute our
+drilling budget for 2008 in a successful and profitable manner. 
+Oil
+and Gas Prices 
+Results
+of our operations and financial condition are significantly affected by oil and
+natural gas commodity prices, which fluctuate dramatically. In 2007,
+we saw a net increase in oil prices throughout the year. Geopolitical
+unrest in various producing regions overseas and concerns domestically related
+to refinery utilization and petroleum product inventories were the principal
+drivers of the increase in oil prices in 2007. Natural gas
+41 
+prices
+were moderated throughout 2007 by high levels of natural gas in storage and a
+lack of significant disruptive hurricane activity during year. 
+Repurchase
+of Common Stock 
+We
+evaluate the market price of our common stock relative to our internal
+assessment of net asset value per share. To the extent that the
+market price per share is below what we believe to be the net asset value per
+share and when the trading window for the Company and executive management is
+open, we may repurchase shares under the program. In 2007, we
+repurchased 792,216 shares of our common stock in the open market for a
+weighted-average price of $32.76 per share, including
+commissions. These shares were purchased under a share repurchase
+program approved by the Board. At the time we repurchased our shares,
+we entered into hedges for a commensurate amount of our production that was
+represented by the share repurchase in order to lock in the discounted price at
+which our shares were trading. As of the date of this filing, we are
+authorized to repurchase an additional 5,207,784 million shares under this
+program. 
+Hedging
+Activities 
+We have
+an active hedging program in which we hedge the first two to five years of an
+acquisition’s risked production. We will also on occasion enter into
+derivative transactions to hedge a portion of our existing forecasted
+production. In October 2005, we hedged a significant portion of
+anticipated future production from our current producing properties using
+zero-cost collars. We also hedged a portion of specific forecasted
+natural gas production for 2006, 2007, and 2008 using swap
+contracts. Taking into account all oil and gas production hedge
+contracts in place through February 15, 2008, we have hedged anticipated
+future production of approximately 11 million Bbls of oil,
+70 million MMBtu of natural gas, and 1 million Bbls of
+natural gas liquids through the year 2011. We believe we have
+established an economic base for our future operations, and the spread between
+the price floors and ceilings on our collars allows us to continue to
+participate in a higher oil and gas price environment. Please see
+Note 10 of Part IV, Item 15 of this report for additional information regarding
+our oil and gas hedges, and see the caption, Summary of Oil and Gas Production
+Hedges in Place, later in this section. 
+Net Profits Plan 
+Payments
+made for distributions from the Net Profits Plan have been expensed as
+compensation costs in the amounts of $31.9 million, $26.1 million, and
+$20.8 million for the years ended December 31, 2007, 2006, and 2005,
+respectively. Although increasing each year, these payments for 2007
+were lower than originally budgeted due to the effects of increased oil and gas
+production expense and additional capital expenditures, both of which decreased
+the current impact of and delayed the timing of payout for the 2004 pool. The
+actual cash payments we make are dependent on actual production, realized
+prices, and operating and capital costs associated with the properties in each
+individual pool. Actual cash payments will be inherently different
+from the estimated liability amounts. More detailed discussion is
+included in the analysis in the Comparison of Financial Results and
+Trends sections below. An increasing percentage of the costs
+associated with the payments for the Net Profits Plan are attributable to
+general and administrative expense as compared to exploration
+expense. This is a function of the normal departure of employees who
+previously contributed to our past exploration efforts. We have
+determined that because of the change in circumstances, a greater percentage of
+the payments should be recorded as general and administrative expense beginning
+in 2007. 
+With
+respect to the accounting estimate of the liability associated with future
+estimated payments from our Net Profits Plan, we have recorded $50.8 million of
+net expense for the year ended December 31, 2007, thereby increasing the
+long-term liability associated with this item. This increase is
+related to an increase in the estimated future prices used to calculate the
+liability driven by overall commodity price increases, the accretion of the
+discount used for the calculation, and the addition of the 2007
+pool. Additionally, we adjusted our discount rate used to calculate
+the present value of future payments during the fourth quarter of 2007 from a
+base rate of 15 percent to 12 percent. The single largest
+item was the impact from the change in discount rate, which drove an increase in
+the liability of $29 million as of December 31, 2007. As a
+result of these factors the liability increased to $211.4 million at
+December 31, 2007. While we have forecast that this
+liability will again increase in 2008, it 
+42 
+is not
+possible to predict this with certainty due to the impact of commodity prices
+and reserve estimates on the valuation of this estimated
+liability. The Company will not be adding new Net Profits Plan pools
+prospectively as this benefit has been replaced with a different program, which
+is described in Footnote 7 of Part IV, Item 15 of this Form 10-K. The
+Company will continue to make payments from the established Net Profits Plan
+pools, as well as make prospective adjustments to the long-term liability, as
+necessary for current conditions. We expect general and
+administrative expense to increase due to changes in our incentive compensation
+program. Beginning in 2008, grants from the restricted stock units
+program and the Net Profits Plan are being replaced with grants of market-based
+performance shares under our 2006 Equity Plan. Although the total
+value of the compensation package to employees is essentially unchanged, we do
+expect general and administrative expense to increase as the cost of the grants
+of performance shares under the 2006 Equity Plan will be amortized over a much
+shorter time than the functional expense recorded under the Net Profits
+Plan. 
+The
+calculation of the estimated liability associated with the Net Profits Plan
+requires management to prepare an estimate of future amounts payable from the
+Net Profits Plan. On a monthly basis, we calculate estimates of the
+payments to be made for each individual pool. The underlying
+principal factors for our estimates are forecasted oil and gas production from
+the properties that comprise each individual pool, price assumptions, cost
+assumptions, and discount rate. In most cases, the cash flow streams
+used in these calculations will span more than 20 years. The
+decrease in the discount rate to 12 percent was a result of the ever
+increasing competitive environment for proven oil and gas properties and our
+assessment of the overall market for proved oil and gas
+reserves. Commodity prices impact the calculated cash flows during
+periods after payout and can dramatically affect the timing of the estimated
+date of payout of the individual pools. Our commodity price
+assumptions are currently determined from an average of actual prices realized
+over the prior 24 months together with adjusted NYMEX strip prices for the
+ensuing 12 months for a total of 36 months of data. This average is
+supplemented by including the effect of realized and anticipated hedge prices
+for the percentage of forecasted hedged production in the relevant
+period. 
+The
+calculation of the estimated liability for the Net Profits Plan is highly
+sensitive to our price estimates and discount rate assumptions. For example, if
+we changed the commodity prices in our calculation by five percent, the
+liability recorded on the balance sheet at December 31, 2007, would differ
+by approximately $19 million. A one percentage
+point decrease in the discount rate would result in an increase to the
+liability of approximately $12 million, while a one percentage point
+increase in the discount rate would result in a decrease to the liability of
+appoximately $10 million. We
+frequently re-evaluate the assumptions used in our calculations and consider the
+possible impacts stemming from the current market environment including current
+and future oil and gas prices, discount rates, and overall market
+conditions. 
+43 
+The table
+below provides information regarding selected production and financial
+information for the quarter ended December 31, 2007, and the
+immediately preceding three quarters. Additional details of per MCFE
+costs are contained later in this section. 
+For
+the Three Months Ended 
+December
+31, 
+September
+30, 
+June
+30, 
+March
+31, 
+2007 
+2007 
+2007 
+2007 
+(In
+millions, except production sales data) 
+Production
+(BCFE) 
+28.5 
+27.5 
+26.0 
+25.5 
+Oil
+and gas production revenue, 
+excluding
+the effects of hedging 
+$ 
+273.7 
+$ 
+228.5 
+$ 
+216.2 
+$ 
+193.7 
+Lease
+operating expense 
+$ 
+37.8 
+$ 
+36.9 
+$ 
+31.6 
+$ 
+34.1 
+Transportation
+costs 
+$ 
+3.8 
+$ 
+3.2 
+$ 
+4.2 
+$ 
+4.4 
+Production
+taxes 
+$ 
+19.1 
+$ 
+14.9 
+$ 
+14.5 
+$ 
+13.7 
+DD&A 
+$ 
+64.8 
+$ 
+59.1 
+$ 
+54.7 
+$ 
+49.0 
+Exploration* 
+$ 
+16.0 
+$ 
+12.6 
+$ 
+11.1 
+$ 
+19.0 
+General
+and administrative expense* 
+$ 
+15.1 
+$ 
+15.8 
+$ 
+16.3 
+$ 
+12.9 
+Net
+income 
+$ 
+32.8 
+$ 
+57.7 
+$ 
+59.2 
+$ 
+40.0 
+Percentage change from
+previous quarter: 
+Production
+(BCFE) 
+4% 
+6% 
+2% 
+2% 
+Oil
+and gas production revenues, 
+excluding
+the effects of hedging 
+20% 
+6% 
+12% 
+7% 
+Lease
+operating expense 
+2% 
+17% 
+(7)% 
+9% 
+Transportation
+costs 
+19% 
+(24)% 
+(5)% 
+47% 
+Production
+taxes 
+28% 
+3% 
+6% 
+6% 
+DD&A 
+10% 
+8% 
+12% 
+10% 
+Exploration* 
+27% 
+14% 
+(42)% 
+19% 
+General
+and administrative expense* 
+(4)% 
+(3)% 
+26% 
+63% 
+Net
+income 
+(43)% 
+(3)% 
+48% 
+(8)% 
+*As
+a result of a change in circumstances in 2007, we have begun
+classifying payments made under the Net Profits Plan to exploration
+overhead only for those individuals who are currently employed by us and who
+continue to be involved in our exploration efforts. Therefore,
+the quarterly financial information presented in the above table reflects that
+Net Profits Plan payments associated with the distributions under the Net
+Profits Plan for ex-employees were recorded to general and administrative
+expense since there is no longer any functional link to exploration expense as
+there is by definition no periodic costs associated with geologic and
+geophysical, exploration related work by those ex-employees. The
+impact to any prior comparative quarter was not material. 
+2007 Financial
+Highlights 
+In 2007,
+we experienced record production and strong earnings. Our record
+production is the realization of operational and investment decisions made in
+prior years as well as the current period. Our solid earnings reflect
+our balanced production profile and high oil prices throughout the
+year. Our hedging program contributed to our earnings as we received
+meaningful cash flows from the realization of in-the-money natural gas
+hedges. Our operating margins remained strong in 2007 despite
+increasing operating costs. Our 2007 operating margin was $6.68 per
+MCFE compared to $6.27 per MCFE in 2006. 
+Net
+income for 2007 was $189.7 million or $2.94 per diluted share compared to
+$190.0 million or $2.94 per diluted share for the prior
+year. Net cash provided by operating activities was
+$630.8 million, up 35 percent from 2006. Average daily
+production for the year increased 16 percent to a record 294.5
+MMCFE. Our average net realized price increased $0.53 to $8.71 per
+MCFE. Unit costs increased for the period as lease operating expenses
+increased $0.06 to $1.31 per MCFE. While general industry costs
+associated with drilling and completing wells are flat or declining year over
+year, costs related to the ongoing operation of oil and gas 
+44 
+properties
+continue to experience upward pressure. This increase over last
+year’s comparable period is driven by continued pressure on costs related to the
+servicing of wells, such as disposal and trucking, as well as workover and labor
+costs. As a company with a significant oil component to our
+production mix, our property base inherently requires more labor than operations
+that are dominated by natural gas production. Labor costs continue to
+be a significant driver of our lease operating expense. In addition
+to the higher costs we are incurring on our base activity, we also have been
+actively incurring workover expense to restore or increase production in the
+Gulf Coast and Rocky Mountain regions. Per MCFE transportation costs
+increased $0.02 per MCFE, or 17 percent, to $0.14 per MCFE as compared to a year
+ago. The increase is due to newly drilled wells with higher
+transportation costs. Production taxes increased $0.04 per MCFE to
+$0.58 per MCFE and are a reflection of higher commodity prices. 
+Depletion,
+depreciation, and amortization, including asset retirement obligation accretion
+expense, per MCFE increased $0.45 to $2.12 per MCFE. The depletion,
+depreciation, and amortization increase is reflective of higher costs on a per
+MCFE basis for new reserve additions relative to the base per MCFE cost of oil
+and gas properties. General and administrative expense increased
+$0.14 per MCFE to $0.56 per MCFE. The increase in general and
+administrative expenses is driven by our growing employee base and higher
+payments from the Net Profits Plan. Exploration expense for 2007 was
+$58.7 million, which was $6.8 million higher than the $51.9 million
+incurred during 2006 due to an increase in exploratory dry hole expense as well
+as the overall increase in the level of exploration activity during
+2007. We discuss these financial results and trends in more detail
+below. 
+Outlook
+for 2008 
+Our
+anticipated exploration and development drilling budget is $626 million for
+2008, which is 16 percent smaller than the $740.9 million we spent on
+development and exploration in 2007. The decrease in our development
+and exploration budget reflects our desire to improve the capital efficiency of
+our investments and to manage the balance sheet to improve financial flexibility
+in the future. Planned expenditures for programs that failed to meet
+our expectations in 2007 were either omitted or substantially reduced in
+2008. The reduced budget for 2008 is also expected to allow for cash
+flow in excess of our capital investments for the year. We believe
+that this will provide us the financial flexibility to accelerate successful
+drilling programs, pursue potential acquisition opportunities, repurchase
+outstanding shares of common stock, or repay bank borrowings when the
+opportunity arises. We have not budgeted any capital for acquisitions
+in 2008, however we believe our solid financial condition provides us the
+ability to execute significant transactions we believe will be accretive to the
+Company. We anticipate production for the first half of 2008 to be
+slightly lower than the last quarter of 2007 due to the divestiture of non-core
+properties that closed subsequent to year-end. We project production
+will ramp up in the second half of 2008 as many of our exploration and
+development projects are scheduled to come on-line in the second half of
+the year. 
+Our 2008
+capital budget was built using a NYMEX price deck of $7.00 per Mcf and $60.00
+per barrel. Current strip prices for oil and natural gas support our
+plans for the year. However, we are keenly aware of how volatile oil
+and natural gas prices are and how quickly they can move. The cost
+environment related to drilling and completing wells appears to have leveled out
+in the past year after several years of significant cost
+escalation. Day rates for land-based drilling rigs have held flat or
+declined throughout the year, and the increasing number of drilling rigs
+entering the market bodes well for this trend. Prices for completion
+services continue to be firm, but we note new capacity is being added by
+incumbent providers as well as new entrants to the service
+sector. Availability of drilling and completion services is not the
+potentially limiting condition that existed the last two
+years. Prices for these services are highly dynamic, vary greatly
+region to region, and are influenced greatly by commodity prices. We
+will continue to evaluate the economics of each well prior to the onset of
+drilling using the most current commodity price and cost information available
+to ensure it meets our economic and operational thresholds. 
+The
+information below provides some detail of our capital investment plans for
+2008: 
+45 
+· 
+We
+believe that we have the necessary capital, personnel, and service
+availability to execute this program. The $626 million budgeted
+for drilling activities in 2008 is allocated among our core areas as
+described below. Included in the discussion are highlights of
+the program in each region this
+year. 
+ArkLaTex - $161 million – 
+Half of our budgeted capital investment for this region in 2008 is for projects
+targeting the Cotton Valley sandstone formation. The largest
+component relates to activity planned at Elm Grove Field, where 20-acre
+increased density drilling and Hosston and Cotton Valley formation commingling
+are improving results and enhancing reserve recovery. Importantly,
+there has been a successful horizontal test well at Elm Grove Field that could
+lead to additional upside. Also in the Cotton Valley program, we plan
+to participate in twice the number of wells in Terryville Field in 2008 compared
+to 2007. Lastly, we will operate a small Cotton Valley program in
+2008 where we have plans to drill two vertical and three horizontal
+wells. The other major program in the ArkLaTex region is our operated
+horizontal James Lime program. We plan to operate two drilling rigs
+continuously and drill more than 20 wells throughout 2008. 
+Mid-Continent - $135 million
+– The largest part of our 2008 program in the Mid-Continent relates to
+the horizontal Woodford program in the Arkoma Basin. After mixed
+results in the horizontal Woodford program in the first half of 2007, we had a
+series of successful wells in the latter part of the year which we believe
+validates our understanding of the well and completion design. We
+currently plan to drill ten horizontal Woodford wells using two operated rigs in
+the first half of 2008, as well as continuing to participate with our partners
+in outside operated wells. With continued success in the play, we
+anticipate increasing our activity and our capital investment in the program in
+the latter part of 2008. In the Western Oklahoma Washes program in
+the Anadarko Basin, which we have referred to previously as the Mayfield
+development area, we plan to invest in projects in the Atoka and Granite Wash
+formations. The area is a known hydrocarbon province, and efforts in
+2008 will center around refining our assessments of geotechnical aspects of the
+program and revising drilling and completion techniques with an intent to lower
+the completion costs. We also plan to deploy approximately one
+quarter of the region’s 2008 capital budget to drill six exploratory test wells
+which focus on a geologic concept that was developed in 2007 which targets
+deeper formations in the Anadarko Basin. 
+Rocky Mountain - $130
+million – In the conventional Rockies program, six vertical
+wells and two recompletions in the Red River are planned for 2008. We
+also plan to drill a small number of horizontal Bakken wells in and around our
+historic Bakken development areas in Montana. We have planned
+workover and recompletion operations in our Wind River Basin and Big Horn Basin
+oil properties. At the outside operated Atlantic Rim coalbed methane
+play in the Green River Basin, we expect to see activity ramp up since
+regulatory and environmental delays appear to have been resolved. At
+Hanging Woman Basin, we plan to moderate our drilling activity in 2008 focusing
+on completing the in-fill program in the shallow coals, monitoring the
+intermediate depth wells and testing several horizontal completion techniques in
+the deeper coal horizontal programs. 
+Permian - $120 million – The
+vast majority of capital investment made in the Permian in 2008 will be in
+properties targeting the Wolfberry section. At Sweetie Peck, we plan
+to operate three drilling rigs continuously throughout the
+year. Included in the budget are investment dollars to test several
+40-acre pilot areas which, if successful, could add meaningful proved
+reserves. At the Halff East Wolfberry development area, we will
+invest approximately $25 million with our operating partner. We will
+also be investing a small amount of capital in several smaller programs,
+including the Delaware waterfloods. 
+Gulf Coast - $80 million – 
+Our development and exploration budget in the Gulf Coast region for 2008 is
+focused on the integration and development of the two Olmos shallow gas projects
+that we acquired in South Texas in 2007. Approximately half of the
+budgeted capital will be deployed to drill new Olmos wells, with additional
+capital being invested in a number of recompletion opportunities. We
+anticipate that the addition of this resource play will provide focus and a
+visible inventory of projects for our Gulf Coast team. We will also
+invest capital in production facilities for an intermediate deepwater discovery
+from 2005 that is expected to be brought online in early 2009. 
+46 
+A
+year-to-year overview of selected reserve, production and financial information,
+including trends: 
+As
+of and for the Years Ended 
+Percent
+Change Between 
+2007 
+2006 
+2005 
+2007/2006 
+2006/2005 
+Selected
+Operations Data (In Thousands, Except Price, Volume, and Per MCFE
+Amounts): 
+Total proved
+reserves 
+Oil
+(MMBbl) 
+78.8 
+74.2 
+62.9 
+Natural
+gas (Bcf) 
+613.5 
+482.5 
+417.1 
+BCFE 
+1,086.5 
+927.6 
+794.5 
+17% 
+17% 
+Net production
+volumes 
+Oil
+(MMBbl) 
+6.9 
+6.1 
+5.9 
+Natural
+gas (Bcf) 
+66.1 
+56.4 
+51.8 
+BCFE 
+107.5 
+92.8 
+87.4 
+16% 
+6% 
+Average daily
+production 
+Oil
+(MBbl) 
+18.9 
+16.6 
+16.2 
+Natural
+gas (MMcf) 
+181.0 
+154.7 
+141.9 
+MMCFE 
+294.5 
+254.2 
+239.4 
+16% 
+6% 
+Oil &
+gas production reve nues 
+Oil
+production, including hedging 
+$ 
+432,375 
+$ 
+342,810 
+$ 
+301,860 
+Gas
+production, including hedging 
+504,202 
+416,103 
+409,145 
+Total 
+$ 
+936,577 
+$ 
+758,913 
+$ 
+711,005 
+23% 
+7% 
+Oil & gas
+production costs 
+Lease
+operating expenses 
+$ 
+140,389 
+$ 
+115,896 
+$ 
+86,130 
+Transportation
+costs 
+15,529 
+10,999 
+8,010 
+Production
+taxes 
+62,290 
+49,695 
+48,733 
+Total 
+$ 
+218,208 
+$ 
+176,590 
+$ 
+142,873 
+24% 
+24% 
+Average net realized
+sales price (1) 
+Oil
+(per Bbl) 
+$ 
+62.60 
+$ 
+56.60 
+$ 
+50.93 
+11% 
+11% 
+Natural
+gas (per Mcf) 
+$ 
+7.63 
+$ 
+7.37 
+$ 
+7.90 
+4% 
+(7)% 
+Per MCFE
+data 
+Average
+net realized price (1) 
+$ 
+8.71 
+$ 
+8.18 
+$ 
+8.14 
+6% 
+-% 
+Lease
+operating expense 
+(1.31 
+) 
+(1.25 
+) 
+(0.99 
+) 
+5% 
+26% 
+Transportation
+costs 
+(0.14 
+) 
+(0.12 
+) 
+(0.09 
+) 
+17% 
+33% 
+Production
+taxes 
+(0.58 
+) 
+(0.54 
+) 
+(0.56 
+) 
+7% 
+(4)% 
+General
+and administrative 
+(0.56 
+) 
+(0.42 
+) 
+(0.37 
+) 
+33% 
+14% 
+Operating
+profit 
+$ 
+6.12 
+$ 
+5.85 
+$ 
+6.13 
+5% 
+(5)% 
+Depletion,
+depreciation and amortization 
+$ 
+2.12 
+$ 
+1.67 
+$ 
+1.52 
+27% 
+10% 
+Financial
+Information (In Thousands, Except Per Share Amounts): 
+Working
+capital (deficit) 
+$ 
+(92,604 
+) 
+$ 
+22,870 
+$ 
+4,937 
+(505)% 
+363% 
+Long-term
+debt 
+$ 
+572,500 
+$ 
+433,980 
+$ 
+99,885 
+32% 
+334% 
+Stockholders’
+equity 
+$ 
+863,345 
+$ 
+743,374 
+$ 
+569,320 
+16% 
+31% 
+Net
+income 
+$ 
+189,712 
+$ 
+190,015 
+$ 
+151,936 
+-% 
+25% 
+Basic
+net income per common share 
+$ 
+3.07 
+$ 
+3.38 
+$ 
+2.67 
+(9)% 
+27% 
+Diluted
+net income per common share 
+$ 
+2.94 
+$ 
+2.94 
+$ 
+2.33 
+-% 
+26% 
+Basic
+weighted-average shares outstanding 
+61,852 
+56,291 
+56,907 
+10% 
+(1)% 
+Diluted
+weighted-average shares outstanding 
+64,850 
+65,962 
+66,894 
+(2)% 
+(1)% 
+Net
+cash provided by operating activities 
+$ 
+630,792 
+$ 
+467,700 
+$ 
+409,379 
+35% 
+14% 
+Net
+cash used in investing activities 
+$ 
+(803,872 
+) 
+$ 
+(724,719 
+) 
+$ 
+(339,779 
+) 
+11% 
+113% 
+Net
+cash provided by (used in) financing 
+Activities 
+$ 
+215,126 
+$ 
+243,558 
+$ 
+(61,093 
+) 
+(12)% 
+(499)% 
+_____________________ 
+(1)
+Includes the effects of our hedging activities. 
+We
+present this table as a summary of information relating to key indicators of
+financial condition and operating performance that we believe are
+important. 
+47 
+The
+increase in our proved reserves reflects our drilling results and acquisition
+activity. Please see Note 13 of Part IV, Item 15 for additional
+details. Over time, our ability to economically replace at least
+200 percent of the total volumes produced annually has proven to be a key
+factor that determines whether we are successful in achieving our goal of
+increasing net asset value per share. We anticipate that we must
+continue our successful drilling program and average one or more relatively
+significant acquisitions per year in the current price environment to achieve
+this level of ongoing growth. The measure of our success will vary
+year-to-year due to changes in these factors. 
+Rapid
+changes in production volumes, oil and gas sales revenues, and costs reflect the
+cyclical and highly volatile prices our industry receives for production, as
+well as the impact of the timing of acquisitions. The comparison of
+changes in production from 2006 to 2007 reflects the positive results from our
+drilling programs in 2007 and the full year impact of a significant acquisition
+made in the fourth quarter of 2006. Production volumes in 2007 were
+also affected by production from oil and gas properties acquired in 2007 and
+from production from new drilling activity. 
+We
+present per MCFE information because we use this information to evaluate our
+performance relative to our peers and to identify and measure trends that we
+believe require analysis. Our year-to-year comparison of financial
+results presented later provides additional details for the analysis of changes
+between years in selected line items. Oil and gas production expenses
+increased in 2007 as a result of a higher percentage of oil production and
+ongoing upward pressure for oil and gas sector services related to the ongoing
+operation of our oil and gas properties. Depreciation, depletion, and
+amortization will continue to significantly increase due to higher costs
+associated with finding and acquiring crude oil and natural gas
+reserves. General and administrative expense increased as a result of
+$41 million in expense associated with payments under our Net Profits Plan,
+costs associated with office space and overall upward pressure on compensation
+in the exploration and production industry. 
+We have
+in-the-money stock options, unvested restricted stock units, and Senior
+Convertible Notes that are considered potentially dilutive
+securities. At times these dilutive securities can affect our
+earnings per share. Consequently, both basic and diluted earnings per
+share are presented in the table above. A detailed explanation is
+presented in Note 1 of Part IV, Item 15 of this report. Basic and
+diluted weighted-average common shares outstanding used in our 2007, 2006 and
+2005 earnings per share calculations reflect our stock repurchases, offset by an
+increase in outstanding shares related to stock option
+exercises. Basic and diluted weighted-average shares outstanding in
+2007 were affected by similar factors as 2006 and 2005, as well as an increase
+in shares that is related to the issuance of common stock upon settlement of
+RSU’s following the expiration of the restriction period. We issued
+733,650 shares of common stock in 2007, 1,489,636 shares in 2006, and
+936,403 shares in 2005 as a result of stock option exercises. These
+share issuances were offset by the repurchase of 792,216 shares of common stock
+in 2007, 3,319,300 shares in 2006, and 1,175,282 shares in 2005 through our
+stock repurchase plan. 
+The
+remaining information in the table relates to information we have provided in
+our operations update press releases and is intended to supplement the
+discussion above. 
+Overview
+of Liquidity and Capital Resources 
+We own
+depleting assets. In order to maintain our current size or to meet
+our projected growth targets, we will have to effectively invest capital into
+new projects and acquisitions. The following analysis and discussion
+includes our assessments of market risk and possible effects of inflation and
+changing prices. 
+Sources
+of cash 
+Based on
+our current forecast, we project that our 2008 cash flows from operations will
+exceed our planned capital investment budget for exploration and development
+resulting in free cash flow that will be available for additional drilling
+opportunities, acquisitions, share repurchases, or repayment of
+debt. Accordingly, we do not expect to access the capital markets in
+2008. On January 31, 2008, we closed on the sale of our previously
+announced divestiture of non-core oil and gas properties. Net
+proceeds from this transaction, before commission costs, was $131.6
+million. These proceeds were used to repay debt under our revolving
+credit facility. We do anticipate that we will continue to evaluate
+our property base for the divestiture of properties that 
+48 
+we
+consider non-core and we will likely utilize such proceeds to fund our capital
+programs. Although our working capital is a negative amount, it is
+important to note that a significant portion of this relates to hedge contracts
+that are in a liability position. We classify those expected
+settlements that are anticipated to be settled over the year of 2008 as a
+current item in our balance sheet. 
+Our
+primary sources of liquidity are the cash provided by operating activities, debt
+financing, sales of non-core properties, and access to capital
+markets. All of these sources can be impacted by the general
+condition of our industry and by significant fluctuations in oil and gas prices,
+operating costs, and volumes produced. We have no control over the
+market prices for oil and natural gas, although we are able to influence the
+amount of our net realized revenues related to oil and gas sales through the use
+of derivative contracts. A decrease in market prices would reduce
+expected cash flow from operating activities and could reduce the borrowing base
+of our credit facility as well as the value of non-strategic properties we might
+consider selling. Historically, decreases in market prices have
+limited our industry’s access to the capital markets. The public debt
+markets for energy companies continue to be available to us, although they are
+significantly less favorable than this time a year earlier. Credit
+spreads have increased materially and the volume of transactions being placed in
+the market is down dramatically. The overall credit markets have seen
+a significant contraction as a result of credit tightening caused by widely
+reported sub-prime and leveraged loan market issues. Equity and
+convertible debt financings are still an available alternative and are somewhat
+favorable to energy companies that operate in the exploration and production
+industry. This is a result of strong commodity prices and the general
+strength reflected in the balance sheets of the companies in this industry as
+well as the historically low credit defaults of energy companies. We
+do not, however, anticipate any need to raise either public debt or equity
+related capital in the foreseeable future. We intend to rely on our
+current credit facility for borrowings. However, a significant
+transaction could necessitate the need to raise additional public debt or equity
+financing. 
+Our current credit
+facility . We have a five-year, $500 million credit
+facility agreement with Wachovia Bank, Wells Fargo Bank and nine other
+participating banks. This credit facility has a borrowing base of
+$1.25 billion. We have elected a commitment amount of
+$500 million. We believe this commitment level is adequate for
+our near-term liquidity requirements. The credit agreement has a
+maturity date of April 7, 2010. We must comply with certain
+financial and non-financial covenants under our existing credit
+facility. The Company is in compliance with all covenants associated
+with the credit facility. As of February 15, 2008, we had
+$320.0 million of available borrowing capacity under this
+facility. Interest and commitment fees are accrued based on the
+borrowing base utilization percentage. Euro-dollar loans accrue interest
+at LIBOR plus the applicable margin from the utilization table located in
+Note 5 of Part IV, Item 15 of this report, and Alternate Base
+Rate loans accrue interest at Prime plus the applicable margin from the
+utilization table. This reduces the amount available under the
+commitment amount on a dollar-for-dollar basis. Borrowings under the
+new facility are secured by mortgages on the majority of our oil and gas
+properties and a pledge of the common stock of our material subsidiary
+companies. 
+Commitment
+fees are accrued on the unused portion of the aggregate commitment amount and
+are included in interest expense in the consolidated statements of
+operations. We had an outstanding loan balance of $285.0 million as
+of December 31, 2007. As of December 31, 2007, we had a cash and
+short-term investment balance of $44.7 million. 
+We
+decreased our net borrowings from the previous year by $49.0 million when
+comparing the ending balance sheet amounts. A substantial increase in
+the average outstanding credit facility balance throughout 2007, offset by a
+decrease in interest rates and an increase in the amount of capitalized interest
+of $1.9 million, resulted in a higher interest expense of $19.9 million in
+2007 compared with $8.5 million in 2006. Our weighted-average
+interest rate paid in 2007 was 5.4 percent and included fees paid on the
+unused portion of the credit facility aggregate commitment amount, amortization
+of deferred financing costs, amortization of the contingent interest embedded
+derivative associated with the 5.75% Senior Convertible Notes, and the effects
+of interest rate swaps. 
+49 
+Uses
+of cash 
+We use
+cash for the acquisition, exploration, and development of oil and gas
+properties, and for the payment of debt obligations, trade payables, income
+taxes, common stock repurchases, and stockholder dividends. During
+2007 we spent $637.7 million of cash on capital development and $182.9 million
+of cash for property acquisitions. These amounts differ from the cost
+incurred amounts based on the timing of cash payments associated with these
+activities as compared to the accrual based activity upon which the costs
+incurred amounts are presented. These cash flows were funded using
+cash inflows from operations and available borrowing capacity under our
+revolving credit facility. 
+Expenditures
+for exploration and development of oil and gas properties and acquisitions are
+the primary use of our capital resources. We anticipate spending
+approximately $626 million for capital and exploration expenditures in
+2008. The capital expenditures budget was described in more detail
+earlier in the Outlook for
+2008 section. The amount and allocation of future capital
+expenditures will depend upon a number of factors including the number and size
+of available economic acquisitions and drilling opportunities, our cash flows
+from operating and financing activities, and our ability to assimilate
+acquisitions. Also, the impact of oil and gas prices on investment
+opportunities, the availability of capital and borrowing facilities, and the
+success of our development and exploratory activities could lead to changes in
+funding requirements for future development. We regularly review our
+capital expenditure budget to assess changes in current and projected cash
+flows, acquisition opportunities, debt requirements, and other
+factors. 
+The
+current portion of our income tax expense was 16 percent of our total income tax
+expense for 2007. We make estimated payments during the calendar year
+and as of December 31, 2007, we anticipate that we have an income tax refund
+with accrued interest due the Company of $1.0 million. 
+During
+2007 we purchased 792,216 shares of our common stock in the open market at a
+weighted-average price of $32.76, including commissions, for a total of
+$26.0 million. As of this filing date we have Board
+authorization to repurchase up to an additional
+5,207,784 million shares of our common stock under our stock
+repurchase program. Shares may be repurchased from time to time in
+open market transactions or privately negotiated transactions subject to market
+conditions and other factors including certain provisions of our existing bank
+credit facility agreement, compliance with securities laws, and the terms and
+provisions of our stock repurchase program. 
+In 2007,
+we paid $6.3 million in dividends to our stockholders. Our
+intention is to continue to make these dividend payments for the foreseeable
+future subject to our future earnings, our financial condition, possible credit
+facility covenants, and other currently unexpected factors which could
+arise. 
+The
+following table presents amounts and percentage changes between years in net
+cash flows from our operating, investing, and financing
+activities. The analysis following the table should be read in
+conjunction with our consolidated statements of cash flows in Part IV, Item 15
+of this report. 
+Amount
+of Change Between 
+Percent
+of Change Between 
+2007/2006 
+2006/2005 
+2007/2006 
+2006/2005 
+Net
+Cash Provided By Operating Activities 
+$ 
+163,092 
+$ 
+58,321 
+35% 
+14% 
+Net
+Cash Used In Investing Activities 
+$ 
+(79,153 
+) 
+$ 
+(384,940 
+) 
+11% 
+113% 
+Net
+Cash Provided By (Used In) Financing Activities 
+$ 
+(28,432 
+) 
+$ 
+304,651 
+(12)% 
+499% 
+Analysis
+of cash flow changes between 2007 and 2006 
+Operating
+activities . Cash received from oil and gas production
+revenues, net of the realized effects of hedging, increased $123.0 million
+to $925.1 million for the year ended December
+31, 2007. Included in the oil and gas production revenue amount
+is $24.5 million of net realized hedging gains. The increase was
+the result of a 16 percent increase in production and a six percent
+increase in our net realized price after hedging, resulting in a 23
+50 
+percent
+increase in production revenue. Net cash payments made for income
+taxes decreased $26.7 million relative to the prior year as the Company was able
+to deduct for tax purposes a larger amount of intangible drilling costs due to
+the expanded 2007 capital program. 
+Investing
+activities . Net cash proceeds from an insurance settlement
+related to Hurricane Rita totaled $5.9 million for the period ended December 31,
+2007. Total cash outflow for 2007 capital expenditures for leasehold
+and drilling activities increased $182.7 million or 40 percent to
+$637.7 million. Total cash outflow for 2007 related to the
+acquisition of oil and gas properties decreased $87.8 million or 32 percent to
+$182.9 million. Cash received from short-term investments increased
+$1.4 million and deposits to short-term investments increased
+$1.2 million for the period ended December 31, 2007, as compared to the
+same period in 2006. Cash received from other for the period ended
+December 31, 2007 included a deposit of $10 million related to the
+divestiture of non-core oil and gas assets that was completed on January 31,
+2008. 
+Financing
+activities . Net repayments to our credit facility increased
+$383 million and payments to our short-term note payable increased
+$4.5 million for the period ended December 31, 2007, compared to
+2006. In March 2007, we received $280.7 million, net of
+$6.8 million of deferred financing costs, from the issuance of the 3.50%
+Senior Convertible Notes. Our income tax benefit attributable to the exercise of
+stock options decreased $6.2 million to $9.9 million for the year
+ended December 31, 2007. We received $7.7 million less from
+the sale of common stock related to stock option exercises and issuance under
+the employee stock purchase plan in 2007, compared to
+2006. Additionally, we invested $97.2 million less to repurchase
+shares of our common stock during 2007, compared to the same period in
+2006. 
+We had
+$43.5 million in cash and cash equivalents and had a working deficit of
+$92.6 million as of December 31, 2007, compared to
+$1.5 million in cash and cash equivalents and working capital of
+$22.9 million as of December 31, 2006. The large
+increase in the cash balance as of the end of 2007 compared to prior periods was
+a reflection of timing of maturities of the LIBOR denominated tranches on our
+credit facility. 
+Analysis
+of cash flow changes between 2006 and 2005 
+Operating
+activities . Cash received from oil and gas production revenue,
+net of the realized effects of hedging, increased $152.5 million to
+$802.1 million for the year ended December
+31, 2006. Included in the oil and gas production
+revenue amount is $28.2 million of realized hedging
+gains. This increase was the result of a six percent increase in
+production offset by lower realized prices. Net cash payments made
+for income taxes decreased $40.2 million as the Company was able to deduct a
+larger amount of intangible drilling costs due to the expanded capital
+program. 
+Investing
+activities . Total cash outflow for 2006 capital expenditures,
+as adjusted for accruals and including acquisitions of oil and gas properties,
+increased $380.9 million, or 110 percent, to
+$725.7 million. This increase reflects increased drilling
+expenditures and net cash paid for oil and gas properties acquired in the
+Sweetie Peck project area in the Permian Basin during 2006. 
+Financing
+activities . Net borrowings against our credit facility were
+$334.0 million for the year ended December 31, 2006, versus net
+payments of $37.0 million in 2005. We paid $123.1 million
+to acquire shares of our common stock under our stock repurchase program in
+2006, compared to $28.9 million paid in 2005. We also received
+$6.5 million more from the exercise of stock options in 2006 compared
+to 2005, and we had a $16.1 million increase in income tax benefit
+resulting from the exercise of stock options in 2006 compared
+to 2005. 
+We had
+$1.5 million in cash and cash equivalents and had working capital of
+$22.9 million as of December 31, 2006, compared to
+$14.9 million in cash and cash equivalents and working capital of
+$4.9 million as of December 31, 2005. 
+51 
+Capital
+Expenditures 
+The
+following table sets forth certain historical information regarding the costs
+incurred by us in our oil and gas activities. The below amounts for
+2007, 2006, and 2005 include capitalized costs associated with asset retirement
+obligations of $27.6 million, $7.8 million, and $22.8 million,
+respectively. 
+Years
+Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Development
+costs 
+$ 
+591,013 
+$ 
+367,546 
+$ 
+249,518 
+Exploration
+costs 
+111,470 
+126,220 
+69,817 
+Acquisitions: 
+Proved 
+161,665 
+238,400 
+84,981 
+Unproved 
+23,495 
+44,472 
+2,853 
+Leasing
+activity 
+38,436 
+28,816 
+14,330 
+Total 
+$ 
+926,079 
+$ 
+805,454 
+$ 
+421,499 
+The costs
+we incurred for capital and exploration activities in 2007 increased $120.6
+million or 15 percent compared to 2006. This increase was a
+result of planned increases in drilling activity offset by an $88.1 million
+decrease in acquisitions relative to the prior year. Increased
+activity in our drilling program was the primary driver of this increase,
+particularly since cost inflation moderated in 2007. 
+Commodity
+Price Risk and Interest Rate Risk 
+We are
+exposed to market risk, including the effects of changes in oil and gas
+commodity prices and changes in interest rates as discussed below under the
+caption “ Summary of Interest
+Rate Hedges in Place .” Changes in interest rates can affect
+the amount of interest we earn on our cash, cash equivalents, and short-term
+investments and the amount of interest we pay on borrowings under our revolving
+credit facility. Changes in interest rates do not affect the amount
+of interest we pay on our fixed-rate 3.50% Senior Convertible Notes, but do
+affect their fair market value. 
+Since we
+produce and sell natural gas and crude oil, our financial results are affected
+when prices for these commodities fluctuate. The following table
+reflects our estimate of the effect on net cash flows from operations of a ten
+percent change in our average realized sales price, inclusive of the impact of
+hedging, for natural gas, for oil, and in combination for the years
+presented. These amounts have been reduced by the effective income
+tax rate applicable to each period since a reduction in revenue would reduce
+cash requirements to pay income taxes. General and administrative
+expenses have not been adjusted. To fund the capital expenditures we
+incurred in those years we would have been required to utilize different amounts
+under our credit facility as a source of funds. In each of these
+years we would have had sufficient borrowing base available under our credit
+facility to meet this contingency without reducing or eliminating expenditures
+or altering our growth strategy. 
+Pro
+forma effect on net cash flow from operations of a ten percent change in
+average realized sales price: 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Oil 
+$ 
+25,248 
+$ 
+20,496 
+$ 
+18,098 
+Natural
+Gas 
+29,998 
+25,117 
+24,502 
+Total 
+$ 
+55,246 
+$ 
+45,613 
+$ 
+42,600 
+52 
+We enter
+into hedging transactions in order to reduce the impact of fluctuations in
+commodity prices. Note 10 of Part IV, Item 15 of this report
+contains important information about our oil and gas derivative contracts, and
+additional information is below under the caption Summary of Oil and Gas Production
+Hedges in Place. We do not anticipate significant changes in
+existing hedge contracts or derivative contract transactions. 
+Summary
+of Oil and Gas Production Hedges in Place 
+Our oil
+and natural gas derivative contracts include swap and costless collar
+arrangements. All contracts are entered into for other-than-trading
+purposes. Please refer to Note 10 – Derivative Financial
+Instruments in Part IV, Item 15 of this report for additional
+information regarding accounting for our derivative transactions. 
+Our net
+realized oil and gas prices are impacted by hedges we have placed on future
+forecasted production. We have historically entered into hedges of
+existing production around the time we make acquisitions of producing oil and
+gas properties. Our intent has been to lock in a significant portion
+of an equivalent amount of existing production to the prices we used to evaluate
+the risked economics of our acquisitions. We also hedge a portion of
+our forecasted production on a discretionary basis. As of year end
+our hedged positions of anticipated production through 2011 totaled
+approximately 11 million Bbls of oil, 70 million MMBtu of natural gas,
+and 1 million Bbls of natural gas liquids. 
+In a
+typical commodity swap agreement, if the agreed upon published third-party index
+price is lower than the swap fixed price, we receive the difference between the
+index price per unit of production and the agreed upon swap fixed
+price. If the index price is higher than the swap fixed price, we pay
+the difference. For collar agreements, we receive the difference
+between an agreed upon index and the floor price if the index price is below the
+floor price. We pay the difference between the agreed upon contracted
+ceiling price and the index price if the index price is above the contracted
+ceiling price. No amounts are paid or received if the index price is
+between the contracted floor and ceiling prices. 
+53 
+The
+following tables describe the volumes, average contract prices, and fair value
+of contracts we have in place as of December 31, 2007. We
+seek to minimize basis risk and index the majority of our oil contracts to NYMEX
+prices and our gas contracts to various regional index prices associated with
+pipelines in proximity to our areas of gas production. 
+Oil
+Contracts 
+Oil
+Swaps 
+Contract
+Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair
+Value at 
+December
+31, 2007 
+Asset/(Liability) 
+(Bbl) 
+(per
+Bbl) 
+(in
+thousands) 
+First
+quarter 2008 - 
+NYMEX
+WTI 
+493,000 
+$ 
+69.52 
+$ 
+(12,707 
+) 
+WCS 
+45,000 
+$ 
+51.63 
+(464 
+) 
+Second
+quarter 2008 - 
+NYMEX
+WTI 
+459,000 
+$ 
+69.10 
+(11,157 
+) 
+WCS 
+45,000 
+$ 
+53.69 
+(296 
+) 
+Third
+quarter 2008 - 
+NYMEX
+WTI 
+438,000 
+$ 
+69.22 
+(9,814 
+) 
+WCS 
+45,000 
+$ 
+54.03 
+(206 
+) 
+Fourth
+quarter 2008 - 
+NYMEX
+WTI 
+405,000 
+$ 
+68.79 
+(8,645 
+) 
+WCS 
+15,000 
+$ 
+50.42 
+(107 
+) 
+2009
+- 
+NYMEX
+WTI 
+1,363,000 
+$ 
+67.74 
+(26,439 
+) 
+2010
+- 
+NYMEX
+WTI 
+1,239,000 
+$ 
+66.47 
+(22,068 
+) 
+2011
+- 
+NYMEX
+WTI 
+1,032,000 
+$ 
+65.36 
+(18,312 
+) 
+All
+oil swap contracts 
+$ 
+(110,215 
+) 
+Oil
+Collars 
+Contract
+Period 
+NYMEX
+WTI 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+Fair
+Value at 
+December
+31, 2007 
+Asset/(Liability) 
+(Bbl) 
+(per
+Bbl) 
+(per
+Bbl) 
+(in
+thousands) 
+First
+quarter 2008 
+415,000 
+$ 
+50.00 
+$ 
+69.83 
+$ 
+(10,580 
+) 
+Second
+quarter 2008 
+415,000 
+$ 
+50.00 
+$ 
+69.83 
+(9,876 
+) 
+Third
+quarter 2008 
+419,000 
+$ 
+50.00 
+$ 
+69.82 
+(9,385 
+) 
+Fourth
+quarter 2008 
+419,000 
+$ 
+50.00 
+$ 
+69.82 
+(9,012 
+) 
+2009 
+1,526,000 
+$ 
+50.00 
+$ 
+67.31 
+(32,858 
+) 
+2010 
+1,367,500 
+$ 
+50.00 
+$ 
+64.91 
+(29,056 
+) 
+2011 
+1,236,000 
+$ 
+50.00 
+$ 
+63.70 
+(26,176 
+) 
+All
+oil collars 
+$ 
+(126,943 
+) 
+54 
+Gas
+Contracts 
+Gas
+Swaps 
+Contract
+Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair
+Value at 
+December
+31, 2007 
+Asset/(Liability) 
+(MMBtu) 
+(per
+MMBtu) 
+(in
+thousands) 
+First
+quarter 2008 - 
+IF
+CIG 
+780,000 
+$ 
+8.94 
+$ 
+2,104 
+IF
+PEPL 
+1,410,000 
+$ 
+9.28 
+3,990 
+IF
+NGPL 
+330,000 
+$ 
+7.53 
+366 
+IF
+ANR OK 
+330,000 
+$ 
+7.68 
+408 
+IF
+EL PASO 
+220,000 
+$ 
+7.94 
+284 
+IF
+HSC 
+1,120,000 
+$ 
+8.64 
+1,726 
+Second
+quarter 2008 - 
+IF
+CIG 
+780,000 
+$ 
+7.00 
+561 
+IF
+PEPL 
+1,420,000 
+$ 
+7.22 
+1,077 
+IF
+NGPL 
+240,000 
+$ 
+6.41 
+(18 
+) 
+IF
+ANR OK 
+240,000 
+$ 
+6.66 
+(17 
+) 
+IF
+EL PASO 
+260,000 
+$ 
+6.72 
+1 
+IF
+HSC 
+1,180,000 
+$ 
+7.66 
+276 
+Third
+quarter 2008 - 
+IF
+CIG 
+780,000 
+$ 
+6.70 
+148 
+IF
+PEPL 
+1,460,000 
+$ 
+7.48 
+1,046 
+IF
+NGPL 
+190,000 
+$ 
+6.69 
+(26 
+) 
+IF
+ANR OK 
+190,000 
+$ 
+6.82 
+31 
+IF
+EL PASO 
+280,000 
+$ 
+7.16 
+2 
+IF
+HSC 
+1,200,000 
+$ 
+7.95 
+241 
+Fourth
+quarter 2008 - 
+IF
+CIG 
+780,000 
+$ 
+7.30 
+400 
+IF
+PEPL 
+1,490,000 
+$ 
+8.32 
+1,849 
+IF
+NGPL 
+160,000 
+$ 
+7.10 
+2 
+IF
+ANR OK 
+160,000 
+$ 
+7.18 
+19 
+IF
+EL PASO 
+300,000 
+$ 
+7.20 
+(29 
+) 
+IF
+HSC 
+1,400,000 
+$ 
+8.44 
+562 
+2009
+- 
+IF
+CIG 
+1,710,000 
+$ 
+7.79 
+998 
+IF
+PEPL 
+3,360,000 
+$ 
+8.06 
+2,189 
+IF
+NGPL 
+440,000 
+$ 
+7.11 
+(176 
+) 
+IF
+ANR OK 
+440,000 
+$ 
+7.38 
+(59 
+) 
+IF
+EL PASO 
+1,200,000 
+$ 
+7.11 
+(646 
+) 
+IF
+HSC 
+6,320,000 
+$ 
+8.35 
+447 
+55 
+Gas Swaps
+(continued) 
+Contract
+Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair
+Value at 
+December
+31, 2007 
+Asset/(Liability) 
+(MMBtu) 
+(per
+MMBtu) 
+(in
+thousands) 
+2010
+- 
+IF
+ANR OK 
+60,000 
+$ 
+7.98 
+(18 
+) 
+IF
+NGPL 
+60,000 
+$ 
+7.60 
+(37 
+) 
+IF
+EL PASO 
+1,090,000 
+$ 
+6.79 
+(1,065 
+) 
+IF
+HSC 
+3,460,000 
+$ 
+8.25 
+(421 
+) 
+2011
+- 
+IF
+EL PASO 
+880,000 
+$ 
+6.34 
+(1,220 
+) 
+All
+gas swap contracts 
+$ 
+14,995 
+Gas
+Collars 
+Contract
+Period 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+Fair
+Value at 
+December
+31, 2007 
+Asset/(Liability) 
+(MMBtu) 
+(per
+MMBtu) 
+(per
+MMBtu) 
+(in
+thousands) 
+First
+quarter 2008 - 
+IF
+CIG 
+720,000 
+$ 
+5.60 
+$ 
+8.72 
+$ 
+35 
+IF
+PEPL 
+1,642,500 
+$ 
+6.28 
+$ 
+9.42 
+329 
+IF
+HSC 
+240,000 
+$ 
+6.57 
+$ 
+9.70 
+19 
+NYMEX
+Henry Hub 
+120,000 
+$ 
+7.00 
+$ 
+10.57 
+14 
+Second
+quarter 2008 - 
+IF
+CIG 
+720,000 
+$ 
+5.60 
+$ 
+8.72 
+115 
+IF
+PEPL 
+1,642,500 
+$ 
+6.28 
+$ 
+9.42 
+662 
+IF
+HSC 
+240,000 
+$ 
+6.57 
+$ 
+9.70 
+30 
+NYMEX
+Henry Hub 
+120,000 
+$ 
+7.00 
+$ 
+10.57 
+31 
+Third
+quarter 2008 - 
+IF
+CIG 
+720,000 
+$ 
+5.60 
+$ 
+8.72 
+71 
+IF
+PEPL 
+1,657,500 
+$ 
+6.28 
+$ 
+9.42 
+549 
+IF
+HSC 
+240,00 
+$ 
+6.57 
+$ 
+9.70 
+(1 
+) 
+NYMEX
+Henry Hub 
+120,000 
+$ 
+7.00 
+$ 
+10.57 
+25 
+Fourth
+quarter 2008 - 
+IF
+CIG 
+720,000 
+$ 
+5.60 
+$ 
+8.72 
+(35 
+) 
+IF
+PEPL 
+1,657,500 
+$ 
+6.28 
+$ 
+9.42 
+314 
+IF
+HSC 
+240,000 
+$ 
+6.57 
+$ 
+9.70 
+(47 
+) 
+NYMEX
+Henry Hub 
+120,000 
+$ 
+7.00 
+$ 
+10.57 
+(8 
+) 
+56 
+Gas Collars
+(continued) 
+Contract
+Period 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+Fair
+Value at 
+December
+31, 2007 
+Asset/(Liability) 
+(MMBtu) 
+(per
+MMBtu) 
+(per
+MMBtu) 
+(in
+thousands) 
+2009
+- 
+IF
+CIG 
+2,400,000 
+$ 
+4.75 
+$ 
+8.82 
+(1,036 
+) 
+IF
+PEPL 
+5,510,000 
+$ 
+5.30 
+$ 
+9.25 
+(2,036 
+) 
+IF
+HSC 
+840,000 
+$ 
+5.57 
+$ 
+9.49 
+(516 
+) 
+NYMEX
+Henry Hub 
+360,000 
+$ 
+6.00 
+$ 
+10.35 
+(164 
+) 
+2010
+- 
+IF
+CIG 
+2,040,000 
+$ 
+4.85 
+$ 
+7.08 
+(1,940 
+) 
+IF
+PEPL 
+4,945,000 
+$ 
+5.31 
+$ 
+7.61 
+(4,740 
+) 
+IF
+HSC 
+600,000 
+$ 
+5.57 
+$ 
+7.88 
+(712 
+) 
+NYMEX
+Henry Hub 
+240,000 
+$ 
+6.00 
+$ 
+8.38 
+(252 
+) 
+2011
+- 
+IF
+CIG 
+1,800,000 
+$ 
+5.00 
+$ 
+6.32 
+(2,350 
+) 
+IF
+PEPL 
+4,225,000 
+$ 
+5.31 
+$ 
+6.51 
+(6,066 
+) 
+IF
+HSC 
+480,000 
+$ 
+5.57 
+$ 
+6.77 
+(816 
+) 
+NYMEX
+Henry Hub 
+120,000 
+$ 
+6.00 
+$ 
+7.25 
+(181 
+) 
+All
+gas collars 
+$ 
+(18,706 
+) 
+Natural
+Gas Liquid Contracts 
+Natural Gas Liquid
+Swaps 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair
+Value at 
+December
+31, 2007 
+Asset/(Liability) 
+(Bbls) 
+(per
+Bbl) 
+(in
+thousands) 
+First
+quarter 2008 
+151,000 
+$ 
+39.54 
+$ 
+(3,581 
+) 
+Second
+quarter 2008 
+170,000 
+$ 
+39.49 
+(3,190 
+) 
+Third
+quarter 2008 
+194,000 
+$ 
+39.25 
+(3,403 
+) 
+Fourth
+quarter 2008 
+217,000 
+$ 
+38.63 
+(4,026 
+) 
+2009 
+627,000 
+$ 
+38.61 
+(9,053 
+) 
+All
+natural gas liquid swaps 
+$ 
+(23,253 
+) 
+Please
+see Note 10 – Derivative Financial Instruments in Part IV, Item 15 of
+this report for additional information regarding our oil and gas
+hedges. 
+Summary
+of Interest Rate Hedges in Place 
+Effective
+September 13, 2007, we entered into a one year floating-to-fixed interest rate
+derivative contract for a notional amount of $75 million. Under the
+agreement, we will pay a fixed rate of 4.90 percent and will be paid a variable
+rate of the one-month LIBOR rate. 
+57 
+In
+relation to our 5.75% Senior Convertible Notes we entered into fixed-to-floating
+interest rate swaps on $50 million of principal in
+October 2003. Due to an increase in interest rates, we entered
+into a floating-to-fixed interest rate swap in April 2005 through the
+redemption date of the notes on March 20, 2007, for this same notional
+amount of $50 million in order to effectively offset our fixed-to-floating
+interest rate swaps. Under the floating-to-fixed interest rate swap,
+we were paid a variable interest rate of 235 basis points above the
+six-month LIBOR rate as determined on the semi-annual settlement date and paid a
+fixed interest rate of 6.85 percent. The impact of this
+instrument, when combined with the other interest rate swaps, was that we fixed
+our net liability related to the interest rate swaps, and paid a
+1.1 percent interest factor on $50 million of notional debt through
+March 2007. The payment dates of the swap matched exactly with
+the interest payment dates of the 5.75% Senior Convertible Notes and the
+fixed-to-floating interest rate swaps. 
+Market
+risk is estimated as the potential change in fair value resulting from an
+immediate hypothetical one percentage point parallel shift in the yield
+curve. For fixed-rate debt, interest rate changes affect the fair
+market value but do not impact results of operations or cash
+flows. Conversely, interest rate changes for floating-rate debt
+generally do not affect the fair market value but do impact future results of
+operations and cash flows, assuming other factors are held constant. The
+carrying amount of our floating-rate debt typically approximates its fair
+value. We had $285.0 million of floating rate debt outstanding as of
+December 31, 2007. Our fixed rate debt outstanding at this
+same date was $287.5 million associated with the 3.50% Senior Convertible
+Notes. 
+Please
+see Note 10 of Part IV, Item 15 of this report for additional
+information regarding our interest rate swaps. 
+Schedule
+of contractual obligations 
+The
+following table summarizes our future estimated principal payments and minimum
+lease payments for the periods specified (in millions): 
+Contractual
+Obligations 
+Total 
+Less
+than 1 year 
+1-3
+years 
+3-5
+years 
+More
+than 5 years 
+Long-Term
+Debt 
+$ 
+615.3 
+$ 
+10.1 
+$ 
+315.2 
+$ 
+290.0 
+$ 
+- 
+Operating
+Leases 
+44.2 
+29.1 
+13.0 
+1.9 
+0.2 
+Other
+Long-Term Liabilities 
+511.8 
+141.8 
+238.5 
+130.6 
+0.9 
+Total 
+$ 
+1,171.3 
+$ 
+181.0 
+$ 
+566.7 
+$ 
+422.5 
+$ 
+1.1 
+This
+table includes our 2007 estimated pension liability payment of approximately
+$1.9 million expected to be paid in the second quarter of 2008. The
+table also includes the remaining unfunded portion of our estimated pension
+liability of $4.2 million even though we recognize that we cannot determine with
+accuracy the timing of future payments. We have made payments of $2.2
+million, $1.3 million, and $1.1 million in 2007, 2006, and 2005, respectively,
+towards the pension liability. We have included $216.7 million in
+other long-term liabilities, which represents six years of undiscounted
+forecasted payments for the Net Profits Plan. Payments are expected
+to be similar on an annual basis for the years beyond what is shown in this
+table. The value recorded on the balance sheet reflects the impact of
+discounting and therefore differs from the amounts disclosed in this
+table. The variability in the amount of the payments will be a direct
+reflection of commodity prices, capital expenditures, and operating costs in
+future periods. Predicting the timing of payments associated with
+this liability is contingent upon estimates of appropriate discount factors,
+adjusting for risk and time value, and upon a number of factors that we cannot
+control. 
+The
+scheduled repayment of the long-term credit facility is in
+2010. Accordingly, it has been disclosed in the table as
+such. Since this is a revolving credit facility, the actual payments
+will vary significantly. We anticipate refinancing this
+obligation. For purposes of this table, we assume that we will net
+share settle the 3.50% Senior Convertible Notes. Additionally,
+$42.8 million of interest payments related to the 3.50% Senior Convertible Notes
+are included in the table above. We have excluded asset retirement
+obligations because we are not able to 
+58 
+accurately
+predict the precise timing for these amounts. Pension liabilities and
+asset retirement obligations are discussed in Note 8 and Note 9 of Part IV,
+Item 15, respectively, and the Net Profits Plan is discussed in Note 7 of Part
+IV, Item 15 of this report. 
+This
+table also includes estimated oil and natural gas derivative payments of $282.9
+million based on futures market prices as of December 31, 2007. This
+amount represents only the cash outflows; it does not include oil and gas
+receipts of $20.6 million that would be paid based on December 31, 2007,
+market prices. The net of $262.3 million represents cash flows from
+the intrinsic value of our swap and collar arrangements and differs in amount
+from our recorded fair value, which as of December 31, 2007, was a net liability
+of $264.1 million. The fair value considers time value and volatility
+that affect the ultimate fair value. Both the intrinsic value and
+fair value will change as oil and natural gas commodity prices
+change. Please refer to the discussion above under the caption
+Summary of Oil and Gas Production Hedges in Place in Part II, Item 7,
+Management’s Discussion and Analysis of Financial Condition and Results of
+Operations and to Note 10 – Derivative Financial Instruments in Part IV, Item 15
+of this report for additional information regarding our oil and gas
+hedges. 
+We
+believe that we will continue to pay annual dividends of $0.10 per
+share. We anticipate making cash payments for income taxes, dependent
+on net income and capital spending. 
+Off-Balance
+Sheet Arrangements 
+As part
+of our ongoing business, we have not participated in transactions that generate
+relationships with unconsolidated entities or financial partnerships, such as
+entities often referred to as structured finance or special purpose entities,
+which would have been established for the purpose of facilitating off-balance
+sheet arrangements or other contractually narrow or limited purposes. As
+of and up to December 31, 2007, we have not been involved in any
+unconsolidated SPE transactions. 
+We
+evaluate our transactions to determine if any variable interest entities
+exist. If it is determined that we are the primary beneficiary of a
+variable interest entity, that entity is consolidated into our consolidated
+financial statements. 
+Critical
+Accounting Policies and Estimates 
+We are
+engaged in the exploration, exploitation, development, acquisition, and
+production of natural gas and crude oil. Our discussion of financial
+condition and results of operations is based upon the information reported in
+our consolidated financial statements. The preparation of these
+consolidated financial statements requires us to make assumptions and estimates
+that affect the reported amounts of assets, liabilities, revenues, and expenses
+as well as the disclosure of contingent assets and liabilities as of the date of
+our financial statements. We base our decisions affecting the
+estimates we use on historical experience and various other sources that are
+believed to be reasonable under the circumstances. Actual results may
+differ from the estimates we calculate due to changing business conditions or
+unexpected circumstances. Policies we believe are critical to
+understanding our business operations and results of operations are detailed
+below. For additional information on our significant accounting
+policies you should see Note 1 – Summary of Significant Accounting
+Policies, Note 9 – Asset Retirement Obligations, and
+Note 12 – Disclosures About Oil and Gas Producing Activities in
+Part IV, Item 15 of this report. 
+Oil and gas reserve
+quantities . Estimated reserve quantities and the related
+estimates of future net cash flows are the most important estimates for an
+exploration and production company because they affect the perceived value of
+our Company, are used in comparative financial analysis ratios and are used as
+the basis for the most significant accounting estimates in our financial
+statements. The significant accounting estimates include the periodic
+calculations of depletion, depreciation, and impairment for our proved oil and
+gas properties and the estimates of our liability for future payments under the
+Net Profits Plan. Proved oil and gas reserves are the estimated
+quantities of crude oil, natural gas, and natural gas liquids which geological
+and engineering data demonstrate with reasonable certainty to be recoverable in
+future periods from known reservoirs under existing economic and operating
+conditions. Future cash inflows and future production and development
+costs are determined by applying benchmark prices and costs, including
+transportation, quality, and basis differentials, in effect at the end of each
+period to the estimated quantities of oil and gas remaining to be produced as of
+the end of 
+59 
+that
+period. Expected cash flows are reduced to present value using a
+discount rate that depends upon the purpose for which the reserve estimates will
+be used. For example, the standardized measure calculation required
+by SFAS No. 69, Disclosures about Oil and Gas Producing Activities, requires a
+ten percent discount rate to be applied. Although reserve estimates
+are inherently imprecise, and estimates of new discoveries and undeveloped
+locations are more imprecise than those of established producing oil and gas
+properties, we make a considerable effort in estimating our reserves, including
+using independent reserve engineering consultants. We expect that
+periodic reserve estimates will change in the future as additional information
+becomes available or as oil and gas prices and operating and capital costs
+change. We evaluate and estimate our oil and gas reserves at December
+31 and June 30 of each year. For purposes of depletion, depreciation,
+and impairment, reserve quantities are adjusted at all interim periods for the
+estimated impact of additions and dispositions. Changes in depletion,
+depreciation, or impairment calculations caused by changes in reserve quantities
+or net cash flows are recorded in the period that the reserve estimates
+change. 
+The
+following table presents information regarding reserve changes from period to
+period that reflect changes from items we do not control, such as price, and
+from changes resulting from better information due to production history, and
+well performance. These changes do not require a capital expenditure
+on our part, but may have resulted from capital expenditures we incurred to
+develop other estimated proved reserves. 
+Years
+Ended December 31, 
+2007 
+2006 
+2005 
+BCFE 
+Percent
+of total 
+BCFE 
+Percent
+of total 
+BCFE 
+Percent 
+of
+total 
+Change 
+Additions 
+Change 
+Additions 
+Change 
+Additions 
+Revisions
+resulting 
+from
+price changes 
+34.5 
+13% 
+(52.2 
+) 
+(23)% 
+23.1 
+10% 
+Revisions
+resulting 
+from
+performance 
+6.4 
+2% 
+66.3 
+29% 
+10.8 
+5% 
+Total 
+40.9 
+15% 
+14.1 
+6% 
+33.9 
+15% 
+Over the
+three-year period, we added 720.7 BCFE of reserves. Of these, 83.5
+BCFE, or 12 percent, was a result of changes in estimates based on the
+performance of our oil and gas properties. A 5.4 BCFE increase in
+reserves was a result of price changes. As previously noted, oil and
+gas prices are volatile, and estimates of reserves are inherently
+imprecise. Consequently, we anticipate we will continue to experience
+these types of changes. 
+The
+following table reflects the estimated BCFE change and percentage change to our
+total reported reserve volumes from the described hypothetical
+changes: 
+Years
+Ended December 31, 
+2007 
+2006 
+2005 
+BCFE 
+Percent 
+BCFE 
+Percent 
+BCFE 
+Percent 
+Change 
+Change 
+Change 
+Change 
+Change 
+Change 
+A
+10% decrease in pricing 
+(16.3 
+) 
+(2)% 
+(28.2 
+) 
+(3)% 
+(28.9 
+) 
+(4)% 
+A
+10% decrease in proved 
+undeveloped
+reserves 
+(25.0 
+) 
+(2)% 
+(20.0 
+) 
+(2)% 
+(14.6 
+) 
+(2)% 
+Additional
+reserve information can be found in the reserve table and discussion included in
+Item 2 of Part I of this report. 
+Successful efforts method of
+accounting. Generally accepted accounting principles provide
+for two alternative methods for the oil and gas industry to use in accounting
+for oil and gas producing activities. These two methods are generally
+known in our industry as the full cost method and the successful efforts
+method. Both methods are widely used. The methods are
+different enough that in many circumstances the same set of facts will
+60 
+provide
+materially different financial statement results within a given
+year. We have chosen the successful efforts method of accounting for
+our oil and gas producing activities, and a detailed description is included in
+Note 1 of Part IV, Item 15 of this report. 
+Revenue
+recognition . Our revenue recognition policy is significant
+because revenue is a key component of our results of operations and our
+forward-looking statements contained in our analyses of liquidity and capital
+resources. We derive our revenue primarily from the sale of produced
+natural gas and crude oil. We report revenue as the
+gross amounts we receive before taking into account production taxes
+and transportation costs, which are reported as separate
+expenses. Revenue is recorded in the month our production is
+delivered to the purchaser, but payment is generally received between 30 and 90
+days after the date of production. No revenue is recognized unless it
+is determined that title to the product has transferred to a
+purchaser. At the end of each month we make estimates of the amount
+of production delivered to the purchaser and the price we will
+receive. We use our knowledge of our properties, their historical
+performance, NYMEX and local spot market prices, and other factors as the basis
+for these estimates. Variances between our estimates and the actual
+amounts received are recorded in the month payment is received. A ten
+percent change in our year-end revenue accrual would have impacted net income
+before tax by $11.6 million in 2007. 
+Crude oil and natural gas
+hedging . Our crude oil and natural gas hedging contracts are
+intended and usually qualify for cash flow deferral hedge accounting under SFAS
+No. 133. Under this accounting pronouncement a majority of the gain
+or loss from a contract qualifying as a cash flow hedge is deferred as to
+statement of operations recognition. The position reflected in the
+statement of operations is based on the actual settlements with the
+counterparty. If our natural gas and crude oil hedge contracts did
+not qualify for hedge accounting treatment or we chose not to use this hedge
+accounting methodology, our periodic consolidated statements of operations could
+include significant changes in the estimate of non-cash derivative gain or loss
+due to swings in the value of these contracts. Consequently, we would
+report a different amount for oil and gas hedge loss in our statements of
+operations. These fluctuations could be especially significant in a
+volatile pricing environment such as what we have encountered over the last
+three years. The amounts recorded to accumulated other comprehensive
+income (loss) of $(170.0) million, $69.0 million, and $(57.2) million, for
+2007, 2006, and 2005, respectively, would have increased or (decreased) net
+income after tax if our hedges did not qualify as cash flow deferral hedges
+under SFAS No. 133. 
+Change in Net Profits Plan
+Liability . We record the estimated liability of future
+payments for our Net Profit Plan. The estimated liability is
+calculated based on a number of assumptions, including estimates of oil and gas
+reserves, recurring and workover lease operating expense, product and ad valorem
+tax rates, present value discount factors, and pricing
+assumptions. Additional discussion is included in the analysis in the
+above section titled Overview
+of the Company , under the heading Net Profits
+Plan . 
+Asset retirement
+obligations. We are required to recognize
+an estimated liability for future costs associated with the abandonment of our
+oil and gas properties. We base our estimate of the liability on our
+historical experience in abandoning oil and gas wells projected into the future
+based on our current understanding of federal and state regulatory
+requirements. Our present value calculations require us to estimate
+the economic lives of our properties, assume what future inflation rates apply
+to external estimates, and determine what credit adjusted risk-free rate to
+use. The impact to the consolidated statement of operations from
+these estimates is reflected in our depreciation, depletion, and amortization
+calculations and occurs over the remaining life of our oil and gas
+properties. 
+Valuation of long-lived and
+intangible assets. Our property and equipment is recorded at
+cost. An impairment allowance is provided on unproved property when
+we determine that the property will not be developed or the carrying value will
+not be realized. We evaluate the realizability of our proved
+properties and other long-lived assets whenever events or changes in
+circumstances indicate that impairment may be appropriate. Our
+impairment test compares the expected undiscounted future net revenues from a
+property, using escalated pricing, with the related net capitalized costs of the
+property at the end of each period. When the net capitalized costs
+exceed the undiscounted future net revenue of a property, the cost of the
+property is written down to our estimate of fair value, which is determined by
+applying a discount rate that we believe is indicative of the current
+market. Our criteria for 
+61 
+an
+acceptable internal rate of return are subject to change over
+time. Different pricing assumptions or discount rates could result in
+a different calculated impairment. 
+Income taxes . We
+provide for deferred income taxes on the difference between the tax basis of an
+asset or liability and its carrying amount in our financial statements in
+accordance with SFAS No. 109, “Accounting for Income
+Taxes.” This difference will result in taxable income or deductions
+in future years when the reported amount of the asset or liability is recovered
+or settled, respectively. Considerable judgment is required in
+determining when these events may occur and whether recovery of an asset is more
+likely than not. Additionally, our federal and state income tax
+returns are generally not filed before the consolidated financial statements are
+prepared, therefore we estimate the tax basis of our assets and liabilities at
+the end of each period as well as the effects of tax rate changes, tax credits,
+and net operating and capital loss carryforwards and
+carrybacks. Adjustments related to differences between the estimates
+we used and actual amounts we reported are recorded in the period in which we
+file our income tax returns. These adjustments and changes in our
+estimates of asset recovery could have an impact on our results of
+operations. A one percent change in our effective tax rate would have
+affected our calculated income tax expense by $2.9 million for the year ended
+December 31, 2007. 
+Stock-based
+compensation. Prior to 2006 we accounted for stock-based
+compensation using the intrinsic value recognition and measurement principles
+detailed in APB No. 25. No stock-based employee compensation expense
+relating to stock options has been reflected in our expense as all options
+granted under our plans had an exercise price equal to the market value of the
+underlying common stock on the date of grant. We used the
+Black-Scholes option valuation model to calculate the disclosures required under
+Statement of Financial Accounting Standards No. 123. As of
+January 1, 2006, we adopted the provisions of Statement of Financial
+Accounting Standards No. 123(R). This statement required us to record
+expense associated with the fair value of stock-based
+compensation. We have recorded expense associated with the issuance
+of restricted stock units since the plan was adopted in 2004 and units were
+first issued. Going forward this expense will decrease on a relative
+per share basis for all units that have already been issued because the
+accounting standard requires cost recognition using fair value estimates of the
+restricted stock units, rather than intrinsic value. 
+Additional
+Comparative Data in Tabular Format: 
+Change
+Between Years 
+Oil and Gas Production
+Revenues: 
+2007
+and 2006 
+2006
+and 2005 
+Increase
+in oil and gas production 
+Revenues,
+net of hedging (in thousands) 
+$ 
+177,664 
+$ 
+47,908 
+Components
+of Revenue Increases (Decreases): 
+Oil 
+Realized
+price change per Bbl, net of hedging 
+$ 
+6.00 
+$ 
+5.67 
+Realized
+price percentage change 
+11% 
+11% 
+Production
+change (MBbl) 
+851 
+130 
+Production
+percentage change 
+14% 
+2% 
+Natural
+Gas 
+Realized
+price change per Mcf, net of hedging 
+$ 
+0.26 
+$ 
+(0.53 
+) 
+Realized
+price percentage change 
+4% 
+(7)% 
+Production
+change (MMcf) 
+9,613 
+4,646 
+Production
+percentage change 
+17% 
+9% 
+62 
+Our
+product mix as a percentage of total oil and gas revenue and
+production: 
+Years
+Ended December 31, 
+Revenue 
+2007 
+2006 
+2005 
+Oil 
+46% 
+45% 
+42% 
+Natural
+Gas 
+54% 
+55% 
+58% 
+Production 
+Oil 
+39% 
+39% 
+41% 
+Natural
+Gas 
+61% 
+61% 
+59% 
+Information
+regarding the effects of oil and gas hedging activity: 
+Years
+Ended December 31, 
+2007 
+2006 
+2005 
+Oil
+Hedging 
+Percentage
+of oil production hedged 
+66% 
+66% 
+24% 
+Oil
+volumes hedged (MBbl) 
+4,565 
+4,021 
+1,419 
+Decrease
+in oil revenue 
+$ 
+(34.3
+million 
+) 
+$ 
+(16.6
+million 
+) 
+$ 
+(13.3
+million 
+) 
+Average
+realized oil price per Bbl before hedging 
+$ 
+67.56 
+$ 
+59.33 
+$ 
+53.18 
+Average
+realized oil price per Bbl after hedging 
+$ 
+62.60 
+$ 
+56.60 
+$ 
+50.93 
+Natural Gas
+Hedging 
+Percentage
+of gas production hedged 
+46% 
+40% 
+25% 
+Natural
+gas volumes hedged (MMBtu) 
+$ 
+32.5
+million 
+$ 
+24.2
+million 
+$ 
+14.0
+million 
+Increase
+(decrease) in gas revenue 
+$ 
+58.7
+million 
+$ 
+44.7
+million 
+$ 
+(9.2
+million 
+) 
+Average
+realized gas price per Mcf before hedging 
+$ 
+6.74 
+$ 
+6.58 
+$ 
+8.08 
+Average
+realized gas price per Mcf after hedging 
+$ 
+7.63 
+$ 
+7.37 
+$ 
+7.90 
+Information
+regarding the components of exploration expense: 
+Years
+Ended December 31, 
+Summary of Exploration
+Expense (in millions) 
+2007 
+2006 
+2005 
+Geological
+and geophysical expenses 
+$ 
+17.0 
+$ 
+9.5 
+$ 
+7.9 
+Exploratory
+dry holes 
+14.4 
+10.2 
+8.1 
+Overhead
+and other expenses 
+27.3 
+32.2 
+28.9 
+Total 
+$ 
+58.7 
+$ 
+51.9 
+$ 
+44.9 
+63 
+Comparison
+of Financial Results and Trends between 2007 and 2006 
+Oil and gas production
+revenues . Average net daily production increased 16 percent to
+a record 294.5 MMCFE for 2007 compared with 254.2 MMCFE in 2006. The
+following table presents specific components that contributed to the increase in
+revenue between the two periods: 
+Average
+Net Daily Production 
+Added 
+Oil
+and Gas 
+Revenue
+Added 
+Production 
+Costs
+Added 
+(MMCFE) 
+(In
+millions) 
+(In
+millions) 
+Sweetie
+Peck acquisition and drilling, Permian Basin region 
+15.8 
+65.2 
+9.3 
+Rockford
+acquisition and drilling 
+1.6 
+4.6 
+1.0 
+Williston
+Basin Middle Bakken Play 
+2.2 
+11.4 
+1.9 
+Elm
+Grove Field 
+6.3 
+16.2 
+2.0 
+James
+Lime formation 
+3.4 
+8.9 
+1.0 
+Anadarko
+Basin fields 
+8.5 
+22.1 
+3.4 
+Woodford
+shale formation – horizontal wells 
+5.7 
+11.5 
+1.1 
+Other
+wells completed in 2007 and 2006 
+54.4 
+85.1 
+13.7 
+Other
+acquisitions 
+4.1 
+12.1 
+3.3 
+Total 
+102.0 
+237.1 
+36.7 
+The
+revenue increases in this table also reflect the difference in oil and gas
+prices received between the comparable periods. The production
+increases are offset by natural declines in production from older properties to
+result in the net increase in production between the years
+presented. Additional production costs reflect increases resulting
+from inflation and competition for resources. 
+Oil and gas realized hedge gain
+(loss). The 13 percent decrease in total oil and gas hedge
+gain to $24.5 million was caused by a change in the composition of our
+hedge position and changes in oil and gas commodity prices. 
+Marketed gas system revenue and
+expense. Marketed gas system revenue increased
+$24.2 million to $45.1 million for the year-ended
+December 31, 2007, compared with $20.9 million for the comparable
+period of 2006. The increase is due to the addition of a new marketed
+gas system in western Oklahoma that increased the number of wells for which we
+currently market gas, as well as increased production in the Woodford shale
+formation located in Coal County, Oklahoma. Concurrent with the
+increase in marketed gas system revenue, marketed gas system expense increased
+$24.0 million to $42.5 million for the year-ended December
+31, 2007, compared with $18.5 million for the comparable period of
+2006. 
+Other
+revenues. Other revenues increased $7.8 million to
+$8.7 million for the year ended December 31, 2007, compared with
+$942,000 for the comparable period of 2006. The increase is due
+primarily to a $5.2 million gain associated with a global insurance
+settlement attributed to Hurricane Rita. The gain calculation is net
+of approximately $12.1 million of costs associated with the plugging and
+abandonment of one offshore platform. We continue to closely monitor
+the activities associated with these properties. Any significant
+variation between actual and estimated plugging and abandonment and
+outside-operated damage repair costs will impact the final determination of the
+insurance settlement gain. We assume that all work will be completed
+and expect adjustments to the gain will be finalized during the second quarter
+of 2008. 
+Oil and gas production
+expenses. Total production costs increased $41.6 million or
+24 percent to $218.2 million for 2007, from $176.6 million in
+2006. Our current year and prior year acquisition of properties added
+$13.6 million of incremental production costs, and other wells completed in
+2006 and 2007 added 
+64 
+$13.7 million
+of incremental production costs in 2007 that were not reflected in 2006. The
+production cost increases are offset by natural declines in production costs
+from older properties to result in the net increase in production costs between
+the years presented. We experienced an increase in production taxes
+consistent with the increase in revenue from higher realized
+prices. 
+Total oil
+and gas production costs per MCFE increased $0.12 to $2.03 for 2007, compared
+with $1.91 for 2006. This increase is comprised of the
+following: 
+· 
+A
+$0.02 increase in overall transportation cost due to an increase in the
+Rocky Mountain region resulting from a change in the sale measurement
+point, as well as newly drilled wells with higher transportation
+costs 
+· 
+A
+$0.11 increase in recurring lease operating expense related to continued
+cost pressure from the oil and gas service
+sector 
+· 
+A
+$0.05 overall decrease in lease operating expense relating to workover
+expense, primarily in the Rockies 
+· 
+A
+$0.04 increase in production taxes related to increase production in the
+Permian region. 
+Depletion, Depreciation, and
+Amortization . DD&A increased $73.1 million, or 47 percent,
+to $227.6 million in 2007 compared with $154.5 million in 2006.
+DD&A expense per MCFE increased 27 percent to $2.12 in 2007
+compared to $1.67 in 2006. This increase reflects overall upward cost
+pressure in the industry and specifically our drilling in 2007 and 2006 that
+added costs at a higher per unit rate relative to the prior year’s base. 
+The DD&A per MCFE rate was further affected by upward adjustments to
+reserves due to pricing differences between December 31, 2007, and December 31,
+2006 although this had the impact of a general lowering of DD&A as compared
+to what DD&A would have been with the upward revisions of 40.9 BCFE of
+proved reserves. 
+Exploration
+expense . Exploration expense increased $6.8 million or 13
+percent to $58.7 million in 2007 compared with $51.9 million for
+2006. This increase is due to a $7.5 million increase in
+geologic and geophysical expense to support a larger overall program as well as
+a $4.2 million increase in exploratory dry hole expense related to three wells
+located in the Gulf Coast region and one in the Rockies region. These
+increases were offset by a $4.9 million decrease in exploration overhead expense
+related to a reduction in amounts recorded in exploration expense related to
+payments under the Net Profits Plan. In the current year we had a
+change in our accounting estimate to reflect the view that Net Profits Plan
+distributions should be reclassified to exploration overhead only for
+individuals who are currently employed by us and who continue to be involved in
+our exploration efforts. Therefore Net Profits Plan payments
+associated with the distributions under the Net Profits Plan for ex-employees
+were reclassified to general and administrative expense since there is no longer
+any functional link to exploration expense as there is by definition no periodic
+costs associated with geologic, geophysical and exploration related work by
+those ex-employees. 
+General and
+administrative. General and administrative expenses increased
+$21.3 million or 55 percent to $60.1 million for 2007, compared
+with $38.9 million for 2006. G&A increased $0.14 to $0.56
+per MCFE for 2007 compared to $0.42 per MCFE for the period in 2006 as G&A
+grew at a faster rate than the 16 percent increase in production. A
+23 percent increase in employee count has contributed to an increase in base
+employee compensation, including taxes and benefits, of approximately 29
+percent, or $8.5 million, between the year ended December 31, 2007,
+and the same period of 2006. 
+An
+increase in oil and gas prices in 2007 triggered additional Net Profits Plan
+payouts and has increased the amounts payable to plan
+participants. Additionally, an increased percentage amount of the
+distribution dollars under the Net Profits Plan associated with general and
+administrative expense contributed to the current period realized expense
+associated with the Net Profits Plan increasing by $5.8 million in 2007
+compared with the same period in 2006. An increase in employee count
+resulted in an increase in cash bonus expense of $2.4 million to $5.2 million
+for the year ended December 31, 2007, compared with $2.8 million for
+the year ended December 31, 2006. 
+RSU bonus
+expense remained relatively flat decreasing by $100,000 for the year ended
+December 31, 2007, compared with the same period in
+2006. Compensation expense related to stock options for the year
+ended 
+65 
+December 31, 2007,
+decreased $1.4 million to $437,000 from $1.9 million in the comparable period in
+2006 because virtually all the stock options are now vested. No stock
+options have been granted since 2004. 
+The
+amounts described above, combined with a net $5.4 million increase in other
+G&A expense (including office supplies and employee development), were
+offset by a $5.0 million decrease in the amount of G&A that was allocated to
+exploration expense due to the aforementioned change in our Net Profits Plan
+accounting estimate and a $4.3 million increase in COPAS overhead
+reimbursements. COPAS overhead reimbursements from operations
+increased due to an increase in our operated well count from our drilling
+program. 
+Change in Future Net Profits Plan
+Liability . For the year ended December 31, 2007, this
+expense increased $27.1 million to $50.8 million from
+$23.8 million for 2006. This increase reflects a decrease in the
+discount rate used to calculate the present value of future payments from a base
+rate of 15 percent to 12 percent. The decrease in the discount rate
+to the 12 percent resulted from our divestiture marketing process and our
+assessment that the overall market for proved oil and gas reserves is ever more
+competitive. This liability is a significant management
+estimate. Adjustments to the liability are subject to estimation and
+may change dramatically from period-to-period based on assumptions used for
+production rates, reserve quantities, commodity pricing, discount rates,
+production tax rates, and production costs. 
+Interest
+expense. Interest expense increased by $11.4 million to $19.9
+million for 2007 compared to $8.5 million for 2006. The increase reflects
+an increase in our average outstanding borrowings in 2007 compared with
+2006. Additionally, the increase reflects that we have $287.5 million
+of 3.50% Senior Convertible Notes outstanding at December 31, 2007, compared
+with 100.0 million of 5.75% Senior Convertible Notes outstanding as of December
+31, 2006. We also capitalized $5.4 million of interest in 2007
+compared to $3.5 million in 2006. 
+Income tax expense . 
+Income tax expense totaled $110.6 million for 2007 and $105.3 million in 2006,
+resulting in effective tax rates of 36.8 percent and 35.7 percent,
+respectively. The effective rate change from 2006 reflects changes in the
+mix of the highest marginal state tax rates as a result of enacted Texas margin
+tax legislation, the benefit of federal and state estimated percentage depletion
+expense, acquisition and drilling activity, and also reflects other permanent
+differences including differing estimated effects between years of the domestic
+production activities deduction. 
+The
+current portion of income tax expense in 2007 is $17.6 million compared to
+$30.5 million in 2006. These amounts are 16 percent and 29 percent of
+total income tax expense for the respective periods. The decrease resulted
+from significant increased drilling activity reflecting the deduction of
+intangible drilling costs in the year incurred, thereby reducing current taxable
+income. We project that the current portion of taxable income will be
+similar in 2008. 
+Comparison
+of Financial Results and Trends between 2006 and 2005 
+Oil and gas production
+revenues . Average net daily production increased six
+percent to a record 254.2 MMCFE for 2006 compared with 239.4 MMCFE in
+2005. The following table presents specific components that
+contributed to the increase in revenue between the two periods: 
+Average
+Net Daily Production 
+Added 
+Oil
+and Gas 
+Revenue
+Added 
+Production 
+Costs
+Added 
+(MMCFE) 
+(In
+millions) 
+(In
+millions) 
+Williston
+Basin Middle Bakken Play 
+6.2 
+23.5 
+2.5 
+Wold
+acquisition 
+3.1 
+9.2 
+5.2 
+Other
+wells completed in 2006 and 2005 
+47.2 
+80.8 
+15.3 
+Other
+acquisitions 
+2.9 
+9.7 
+1.4 
+Total 
+59.4 
+123.2 
+24.4 
+66 
+The
+revenue increases in this table also reflect the difference in oil and gas
+prices received between the comparable periods. The production
+increases were offset by natural declines in production from older properties to
+result in the net increase in production between the years
+presented. Additional production costs reflect increases resulting
+from inflation and competition for resources. 
+Oil and gas realized hedge gain
+(loss). The 225 percent increase in total oil and gas hedge
+gain to $28.2 million was caused by a change in the composition of our
+hedge position and changes in oil and gas commodity prices. 
+Oil and gas production
+expenses. Total production costs increased $33.7 million or
+24 percent to $176.6 million for 2006, from $142.9 million in
+2005. The acquisition of properties added $1.4 million of
+incremental production costs, prior year acquisitions of properties added $5.2
+million of incremental production costs, and other wells completed in 2005 and
+2006 added $15.3 million of incremental production costs in 2006 that were
+not reflected in 2005. We experienced an increase in production taxes
+consistent with the increase in revenue from higher realized
+prices. 
+Total oil
+and gas production costs per MCFE increased $0.27 to $1.91 for 2006, compared
+with $1.64 for 2005. This increase was comprised of the
+following: 
+· 
+A
+$0.02 decrease in production taxes, due to a $0.04 decrease in our Rocky
+Mountain region resulting from an increase in new production, which
+qualifies for incentive tax rates, that was partially offset by a minor
+increase in our Mid-Continent region resulting from higher natural gas
+revenues 
+· 
+A
+$0.03 increase in overall transportation cost, due to an increase in the
+Rocky Mountain region resulting from a change in the sale measurement
+point, as well as newly drilled wells with higher transportation
+costs 
+· 
+A
+$0.20 increase in recurring LOE related to continued increases in costs
+for oil and gas service sector
+resources 
+· 
+A
+$0.06 overall increase in LOE relating to workover charges, mainly due to
+activity in the Rockies. 
+Depletion, Depreciation, and
+Amortization . DD&A increased $21.8 million or 16
+percent to $154.5 million in 2006 compared with $132.8 million in
+2005. DD&A expense per MCFE increased 10 percent to $1.67 in 2006
+compared to $1.52 in 2005. This increase reflected overall upward cost
+pressure in the industry and specifically our acquisitions and drilling in 2006
+and 2005 that added costs at a higher per unit rate. The DD&A per MCFE
+rate was further affected by downward adjustments to reserves due to pricing
+differences between December 31, 2006 and December 31, 2005. 
+Proved Property
+Impairment. St. Mary recorded a $7.2 million impairment of
+proved oil and gas properties in 2006 compared with no impairment in 2005.
+This impairment was primarily due to declining performance and downward
+adjustments to reserves for properties located in East Texas. 
+Exploration
+expense . Exploration expense increased $7.0 million or 15
+percent to $51.9 million in 2006 compared with $44.9 million for
+2005. This increase was due to a $3.3 million increase in
+exploration overhead related to increases in payments made under the Net Profits
+Plan and increases in the size of our geologic and exploration
+staff. Additionally, the increase in exploration expense was
+partially related to an approximate $2.1 million increase in exploratory
+dry hole expense and a $1.6 million increase in geologic and geophysical
+expense to support a larger overall program. 
+General and
+administrative. General and administrative expenses increased
+$6.1 million or 19 percent to $38.9 million for 2006, compared
+with $32.8 million for 2005. G&A increased $0.05 to $0.42
+per MCFE for 2006 compared to $0.37 per MCFE for the period in 2005 as G&A
+grew at a faster rate than the six percent increase in
+production. 
+A 16
+percent increase in employee count contributed to an increase in base employee
+compensation of approximately 18 percent, or $3.5 million, between the year
+ended December 31, 2006, and the same period of 2005. Oil
+and gas price increases triggered additional Net Profits Plan payouts and
+increased the amounts payable to 
+67 
+plan
+participants. Consequently, the realized expense associated with the
+Net Profits Plan increased by $5.4 million in 2006 compared with the same
+period in 2005. A decrease in the bonus percentage resulted in a
+decrease in the accrued cash bonus expense of $5.0 million to $2.8 million for
+the year ended December 31, 2006, compared with $7.8 million for the
+year ended December 31, 2005. 
+RSU bonus
+expense was $1.5 million higher for the year ended December 31, 2006, as
+compared to the year ended December 31, 2005, which was due to the increase in
+amortization of stock-based compensation expense. In 2006, we
+recorded expense for four periods of RSU grants while there were only three
+grants recorded in 2005. Also in 2006, we included the grant made in
+2006 for 2005 performance and the additional accrual of the expense estimated
+for the 2006 plan year. This increase was partially offset by a
+decrease in RSU bonus expense for the year ended December 31, 2006, compared
+with the same period in 2005. This decrease correlated to the
+decrease in cash bonus expense and reflected an evaluation of our overall
+performance for 2006 including reserve replacement, production, and net asset
+value per share growth factors. 
+As a
+result of the implementation of SFAS No. 123(R) on January 1, 2006, we recorded
+$2.2 million of compensation expense in 2006 related to stock options and
+the ESPP. The above amounts combined with a net $5.1 million
+increase in other G&A expense, including payroll tax and 401(k) contribution
+expense, were offset by a $3.2 million increase in the amount of G&A
+that was allocated to exploration expense due to the aforementioned incentive
+plan increases as well as increases in the size of our technical exploration
+staff and a $3.4 million increase in COPAS overhead
+reimbursements. COPAS overhead reimbursements from operations
+increased due to an increase in our operated well count from our drilling
+program. 
+Change in Future Net Profits Plan
+Liability . For the year ended December 31, 2006, this
+expense decreased $82.5 million to $23.8 million from
+$106.3 million for 2005. This decrease reflects a smaller change
+in future oil and gas prices as compared to 2005 when we experienced significant
+increases in prices. Since the prices used in the calculation were
+much more comparable in the year-end 2006 calculation to that of the 2005
+calculation, the degree of increase was much less in 2006. This
+liability is a significant management estimate. Adjustments to the
+liability are subject to estimation and may change dramatically from
+period-to-period based on assumptions used for production rates, reserve
+quantities, commodity pricing, discount rates, production tax rates, and
+production costs. 
+Interest
+expense. Interest expense increased by $308,000 to $8.5
+million for 2006 compared to $8.2 million for 2005. The increase reflected
+an increase in our average outstanding borrowings and higher interest rates on
+the floating rate portion of our long-term debt. We also capitalized
+$3.5 million in 2006 compared to $1.9 million in 2005. 
+Income tax
+expense . Income tax expense totaled $105.3 million for 2006
+and $86.3 million in 2005, resulting in effective tax rates of 35.7 percent and
+36.3 percent, respectively. The effective rate change from 2005
+reflected changes in the mix of the highest marginal state tax rates as a result
+of enacted Texas margin tax legislation, the benefit of estimated percentage
+depletion for both federal and state income taxes, acquisition and drilling
+activity, and also reflected other permanent differences including differing
+estimated effects between years of the domestic production activities
+deduction. 
+The
+current portion of income tax expense in 2006 was $30.5 million compared to
+$80.8 million in 2005. These amounts comprised 29 percent and 94
+percent of total income tax expense for the respective periods. The
+decrease resulted from a significant increase in drilling activity, whereby we
+deducted intangible drilling costs in the year it was incurred and reduced our
+current taxable income. 
+Other
+Liquidity and Capital Resource Information 
+Pension
+Benefits 
+Substantially
+all of our employees who meet age and service requirements participate in a
+non-contributory defined benefit pension plan. On December 31, 2006,
+the Company adopted the recognition and disclosure provisions of Statement of
+Financial Accounting Standards No. 158, "Employers’ Accounting for 
+68 
+Defined
+Benefit Pension and Other Postretirement Plans", an amendment of Statement of
+Financial Accounting Standards No 87, 88, 106 and 132(R). Statement
+of Financial Accounting Standards No. 158 requires the Company to recognize the
+funded status (i.e., the difference between the fair value of plan assets and
+the projected benefit obligation) of its pension plan in the December 31, 2006
+consolidated balance sheet as either an asset or a liability, with a
+corresponding adjustment to accumulated other comprehensive income, net of
+tax. At December 31, 2007, and December 31, 2006, we had a recorded
+balance of $2.5 million and $2.6 million, respectively, of pre-tax loss in
+accumulated other comprehensive income as a result of this new
+pronouncement. We believe this obligation will be funded from future
+cash flow from operating activities. For purposes of calculating our
+obligation under the plan, we have used an expected return on plan assets of 7.5
+percent. We think this rate of return is appropriate over the
+long-term given the 60 percent equity and 40 percent debt securities mix of
+investment of plan assets and the historical rate of return provided by equity
+and debt securities since the 1920s. Our actual rate of return was
+6.5 percent for 2007 and was 14.1 percent for 2006. The difference in
+investment income using our projected rate of return compared to our actual
+rates of return for the past two years was not material and will not have a
+material effect on the results of operation or cash flow from operating
+activities in future years. 
+For the
+2007 plan year, a 0.20 percentage point increase in the discount rate and a 0.50
+percentage point increase in the lump sum interest rate, netted with a larger
+than expected increase in base salaries and an increase in new participants,
+caused a $161,000 increase in the projected benefit obligation of the
+plan. We do not believe this change was material and project that it
+will not have a material effect on the results of operations or on cash flow
+from operating activities in future periods. 
+We also
+have a supplemental non-contributory defined benefit pension plan that covers
+certain management employees. There are no plan assets for this
+plan. For the 2007 plan year, a 0.20 percentage point increase in the
+discount rate and a 0.50 percentage point increase in the lump sum interest rate
+caused a $62,000 decrease in the projected benefit obligation for this
+plan. This plan’s accumulated benefit obligation was $1.0 million at
+December 31, 2007, and $1.5 million at December 31, 2006. We believe
+this obligation will be funded from future cash flow from operating
+activities. 
+Accounting
+Matters 
+We refer
+you to Note 4 – Income Taxes and Note 5 – Long-term Debt in Part IV, Item 15 of
+this report for information regarding accounting matters related to FASB
+Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – An
+Interpretation of FASB Statement No. 109” and FASB Staff Position APB 14-a,
+“Accounting for Convertible Debt Instruments That May Be Settled in Cash upon
+Conversion (Including Partial Cash Settlement)”. 
+In
+September 2006 the FASB issued Statement of Financial Accounting Standards No.
+157, “Fair Value Measurements”, which defines fair value, establishes a
+framework for measuring fair value, and expands disclosures about fair value
+measurements. The provisions of SFAS No. 157 will be effective as of
+the beginning of the Company’s 2008 fiscal year. The adoption of SFAS No.
+157 has no impact on the Company’s consolidated financial statements,
+however, it will require changes in certain disclosures. 
+In
+February 2007 the FASB issued Statement of Financial Accounting Standards No.
+159, “The Fair Value Option for Financial Assets and Financial Liabilities”,
+which expands the use of fair value accounting but does not affect existing
+standards which require assets or liabilities to be carried at fair
+value. SFAS No. 159 allows entities to choose, at specified election
+dates, to measure eligible financial assets and liabilities at fair value that
+are not otherwise required to be measured at fair value. If a company elects the
+fair value option for an eligible item, changes in that item's fair value in
+subsequent reporting periods must be recognized in current
+earnings. SFAS No. 159 also establishes presentation and disclosure
+requirements designed to draw comparisons between entities that elect different
+measurement attributes for similar assets and liabilities. If
+elected, SFAS No. 159 is effective for fiscal years beginning after November 15,
+2007. SFAS No. 159 will be effective for the Company beginning with
+the 2008 fiscal year. The Company did not elect the fair value
+option. There is no impact on the Company’s consolidated financial
+statements. 
+69 
+Environmental 
+St. Mary’s
+compliance with applicable environmental regulations has not resulted in any
+significant capital expenditures or materially adverse effects to our liquidity
+or results of operations. We believe we are in substantial compliance
+with environmental regulations and do not currently foresee that material
+expenditures will be required in the future. However, we are unable
+to predict the impact that future compliance with regulations may have on future
+capital expenditures, liquidity, and results of operations. 
+ITEM
+7A. 
+QUANTITATIVE
+AND QUALITATIVE DISCLOSURES ABOUT MARKET
+RISK 
+The
+information required by this item is provided under the captions “Commodity
+Price Risk and Interest Rate Risk,” “Summary of Oil and Gas Production Hedges in
+Place,” and “Summary of Interest Rate Hedges in Place” in Item 7 above and
+is incorporated herein by reference. 
+ITEM
+8. FINANCIAL
+STATEMENTS AND SUPPLEMENTARY DATA 
+The
+Consolidated Financial Statements that constitute Item 8 follow the text of this
+report. An index to the Consolidated Financial Statements and
+Schedules appears in Item 15(a) of this report. 
+ITEM
+9. 
+CHANGES
+IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
+DISCLOSURE 
+None. 
+ITEM
+9A. 
+CONTROLS
+AND PROCEDURES 
+We
+maintain a system of disclosure controls and procedures that are designed to
+ensure that information required to be disclosed in our SEC reports is recorded,
+processed, summarized, and reported within the time periods specified in the
+SEC’s rules and forms, and to ensure that such information is accumulated and
+communicated to our management, including the Chief Executive Officer and the
+Chief Financial Officer, as appropriate, to allow timely decisions regarding
+required disclosure. 
+We
+carried out an evaluation, under the supervision and with the participation of
+our management, including the Chief Executive Officer and the Chief Financial
+Officer, of the effectiveness of the design and operation of our disclosure
+controls and procedures as of the end of the period covered by this Annual
+Report on Form 10-K. Based upon that evaluation, the Chief Executive
+Officer and the Chief Financial Officer concluded that our disclosure controls
+and procedures are effective for the purposes discussed above as of the end of
+the period covered by this Annual Report on Form 10-K. There was no
+change in our internal control over financial reporting that occurred during our
+most recent fiscal quarter that has materially affected, or is reasonably likely
+to materially affect, our internal control over financial
+reporting. 
+70 
+MANAGEMENT’S
+REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 
+To the
+Stockholders’ of St. Mary Land & Exploration Company 
+Management
+of the Company is responsible for establishing and maintaining adequate internal
+control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f)
+under the Securities Exchange Act of 1934, as amended. The Company’s
+internal control over financial reporting is designed to provide reasonable
+assurance regarding the reliability of financial reporting and the preparation
+of financial statements for external purposes in accordance with generally
+accepted accounting principles. The Company’s internal control over
+financial reporting includes those policies and procedures that: 
+(i) 
+pertain
+to the maintenance of records that, in reasonable detail, accurately and
+fairly reflect the transactions and dispositions of the assets of the
+Company; 
+(ii) 
+provide
+reasonable assurance that transactions are recorded as necessary to permit
+preparation of financial statements in accordance with generally accepted
+accounting principles, and that receipts and expenditures of the Company
+are being made only in accordance with authorizations of management and
+directors of the Company; and 
+(iii) 
+provide
+reasonable assurance regarding prevention or timely detection of
+unauthorized acquisition, use, or disposition of the Company’s assets that
+could have a material effect on the financial
+statements. 
+Because
+of the inherent limitations, internal control over financial reporting may not
+prevent or detect misstatements. Also, projections of any evaluation
+of effectiveness to future periods are subject to the risk that controls may
+become inadequate because of changes in conditions, or that the degree of
+compliance with the policies or procedures may deteriorate. 
+Management
+assessed the effectiveness of the Company’s internal control over financial
+reporting as of December 31, 2007. In making this assessment,
+management used the criteria set forth by the Committee of Sponsoring
+Organizations of the Treadway Commission in Internal Control-Integrated
+Framework . 
+Based on
+our assessment and those criteria, management believes that the Company
+maintained effective internal control over financial reporting as of December
+31, 2007. 
+The
+Company’s independent registered public accounting firm has issued an
+attestation report on the Company’s internal controls over financial
+reporting. That report immediately follows this report. 
+/s/ ANTHONY J.
+BEST 
+/s/ DAVID W.
+HONEYFIELD 
+Anthony
+J. Best 
+David
+W. Honeyfield 
+President
+and Chief Executive Officer 
+Senior
+Vice President – Chief Financial Officer and Secretary 
+February
+21, 2008 
+February
+21, 2008 
+71 
+REPORT OF
+INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the
+Board of Directors and Stockholders of 
+St. Mary
+Land & Exploration Company and Subsidiaries 
+Denver,
+Colorado 
+We have
+audited the internal control over financial reporting of St. Mary Land &
+Exploration Company and subsidiaries (the “Company”) as of December 31, 2007,
+based on criteria established in Internal Control—Integrated
+Framework issued by the Committee of Sponsoring Organizations of the
+Treadway Commission. The Company’s management is responsible for
+maintaining effective internal control over financial reporting and for its
+assessment of the effectiveness of internal control over financial
+reporting. Our responsibility is to express an opinion on the
+Company’s internal control over financial reporting based on our
+audit. 
+We
+conducted our audit in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). Those standards require
+that we plan and perform the audit to obtain reasonable assurance about whether
+effective internal control over financial reporting was maintained in all
+material respects. Our audit included obtaining an understanding of
+internal control over financial reporting, assessing the risk that a material
+weakness exists, testing and evaluating the design and operating effectiveness
+of internal control based on the assessed risk, and performing such other
+procedures as we considered necessary in the circumstances. We
+believe that our audit provides a reasonable basis for our opinion. 
+A
+company’s internal control over financial reporting is a process designed by, or
+under the supervision of, the company’s principal executive and principal
+financial officers, or persons performing similar functions, and effected by the
+company’s board of directors, management, and other personnel to provide
+reasonable assurance regarding the reliability of financial reporting and the
+preparation of financial statements for external purposes in accordance with
+generally accepted accounting principles. A company’s internal
+control over financial reporting includes those policies and procedures that (1)
+pertain to the maintenance of records that, in reasonable detail, accurately and
+fairly reflect the transactions and dispositions of the assets of the company;
+(2) provide reasonable assurance that transactions are recorded as necessary to
+permit preparation of financial statements in accordance with generally accepted
+accounting principles, and that receipts and expenditures of the company are
+being made only in accordance with authorizations of management and directors of
+the company; and (3) provide reasonable assurance regarding prevention or timely
+detection of unauthorized acquisition, use, or disposition of the company’s
+assets that could have a material effect on the financial
+statements. 
+Because
+of the inherent limitations of internal control over financial reporting,
+including the possibility of collusion or improper management override of
+controls, material misstatements due to error or fraud may not be prevented or
+detected on a timely basis. Also, projections of any evaluation of
+the effectiveness of the internal control over financial reporting to future
+periods are subject to the risk that the controls may become inadequate because
+of changes in conditions, or that the degree of compliance with the policies or
+procedures may deteriorate. 
+In our
+opinion, the Company maintained, in all material respects, effective internal
+control over financial reporting as of December 31, 2007, based on the criteria
+established in Internal
+Control—Integrated Framework issued by the Committee of Sponsoring
+Organizations of the Treadway Commission. 
+We have
+also audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), the consolidated financial statements as of and
+for the year ended December 31, 2007, of the Company, and our report dated
+February 21, 2008, expressed an unqualified opinion on those financial
+statements. 
+Denver,
+Colorado 
+February
+21, 2008 
+72 
+ITEM 9B. OTHER
+INFORMATION 
+None. 
+PART
+III 
+ITEM
+10. DIRECTORS,
+EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+The
+information required by this Item concerning St. Mary’s Directors and
+corporate governance is incorporated by reference to the information provided
+under the captions “Election of Directors,” “Nominees for Election of
+Directors,” “Corporate Governance” and “Board and Committee Meetings” in
+St. Mary’s definitive proxy statement for the 2008 annual meeting of
+stockholders to be filed within 120 days from
+December 31, 2007. The information required by this Item
+concerning St. Mary’s executive officers is incorporated by reference to
+the information provided in Part I—Item 4A—EXECUTIVE OFFICERS OF THE REGISTRANT,
+included in this Form 10-K. 
+The
+information required by this Item concerning compliance with Section 16(a) of
+the Securities Exchange Act of 1934 is incorporated by reference to the
+information provided under the caption “Section 16(a) Beneficial Ownership
+Reporting Compliance” in St. Mary’s definitive proxy statement for the 2008
+annual meeting of stockholders to be filed within 120 days from
+December 31, 2007. 
+ITEM
+11. EXECUTIVE
+COMPENSATION 
+The
+information required by this Item is incorporated by reference to the
+information provided under the captions, “Director Compensation,” “Compensation
+Discussion and Analysis,” “Executive Compensation and Summary Compensation
+Table,” “Summary Compensation Table,” “Grants of Plan-Based Awards,”
+“Outstanding Equity Awards at Fiscal Year-End,” “Nonqualified Deferred
+Compensation,” “Option Exercises and Stock Vested,” “Retirement Plans,” “Pension
+Benefits,” “Equity Compensation Plans,” “Compensation Committee Interlocks and
+Insider Participation,” “Compensation Committee Report,” “Employee Agreements
+and Termination of Employment,” and “Change-of-Control Arrangements” in
+St. Mary’s definitive proxy statement for the 2008 annual meeting of
+stockholders to be filed within 120 days from
+December 31, 2007. 
+ITEM
+12. SECURITY
+OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
+MATTER 
+The
+information required by this Item concerning security ownership of certain
+beneficial owners and management is incorporated by reference to the information
+provided under the caption “Security Ownership of Certain Beneficial Owners and
+Management” in St. Mary’s definitive proxy statement for the 2008 annual
+meeting of stockholders to be filed within 120 days from
+December 31, 2007. 
+The
+information required by this Item concerning securities authorized for issuance
+under equity compensation plans is incorporated by reference to the information
+provided under the caption “Equity Compensation Plans” in Part II, Item 5 –
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
+Purchases of Equity Securities, included in this Form 10-K. 
+ITEM
+13. 
+CERTAIN
+RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
+INDEPENDENCE 
+The
+information required by this Item is incorporated by reference to the
+information provided under the caption “Certain Relationships and Related
+Transactions,” “Election of Directors,” “Corporate Governance,” and “Board and
+Committee Meetings” in St. Mary’s definitive proxy statement for the 2008
+annual meeting of stockholders to be filed within 120 days from
+December 31, 2007. 
+73 
+ITEM
+14. PRINCIPAL
+ACCOUNTING FEES AND SERVICES 
+The
+information required by this Item is incorporated by reference to the
+information provided under the caption “Independent Accountants” and “Audit
+Committee Preapproval Policy and Procedures” in St. Mary’s definitive proxy
+statement for the 2008 annual meeting of stockholders to be filed within 120
+days from December 31, 2007. 
+PART
+IV 
+ITEM
+15. 
+EXHIBITS
+AND FINANCIAL STATEMENT SCHEDULES 
+(a)(1)
+and (a)(2) Financial Statements and Financial Statement Schedules: 
+Audit Report of Independent
+Registered Public Accounting Firm 
+F-1 
+Consolidated Balance
+Sheets 
+F-2 
+Consolidated Statements of
+Operations 
+F-3 
+Consolidated Statements of
+Stockholders' Equity and Comprehensive Income 
+F-4 
+Consolidated Statements of Cash
+Flows 
+F-5 
+Notes to Consolidated Financial
+Statements 
+F-7 
+All other
+schedules are omitted because the required information is not applicable or is
+not present in amounts sufficient to require submission of the schedule or
+because the information required is included in the Consolidated Financial
+Statements and Notes thereto. 
+(b) Exhibits. The
+following exhibits are filed or furnished with or incorporated by reference into
+this report on Form 10-K: 
+Exhibit 
+Number 
+Description 
+2.1 
+Purchase
+and Sale Agreement dated November 1, 2006, among Henry Petroleum LP, Henry
+Holding LP, Henry Group, Entre Energy Partners LP, and St. Mary Land &
+Exploration Company (filed as Exhibit 2.1 to the registrant’s Current
+Report on Form 8-K filed on December 18, 2006, and incorporated herein by
+reference) 
+2.2 
+Purchase
+and Sale Agreement dated August 2, 2007, among Rockford Energy Partners
+II, LLC and St. Mary Land & Exploration Company (filed as
+Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed on
+October 5, 2007, and incorporated herein by
+reference) 
+2.3 
+Purchase
+and Sale Agreement dated December 11, 2007, among St. Mary Land &
+Exploration Company, Ralph H. Smith Restated Revocable Trust Dated
+8/14/97, Ralph H. Smith Trustee, Kent J. Harrell, Trustee of the Kent J.
+Harrell Revocable Trust Dated January 19, 1995, and Abraxas Operating, LLC
+(filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed
+on February 1, 2008, and incorporated herein by
+reference) 
+2.4 
+Ratification
+and Joinder Agreement dated January 31, 2008, among St. Mary Land &
+Exploration Company, Ralph H. Smith, Kent J. Harrell, Abraxas Operating,
+LLC and Abraxas Petroleum Corporation (filed as Exhibit 2.2 to the
+registrant’s Current Report on Form 8-K filed on February 1, 2008, and
+incorporated herein by reference) 
+3.1 
+Restated
+Certificate of Incorporation of St. Mary Land & Exploration
+Company as amended on May 25, 2005 (filed as Exhibit 3.1 to the
+registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
+2005 and incorporated herein by reference) 
+3.2 
+Restated
+By-Laws of St. Mary Land & Exploration Company amended as of December
+18, 2007 (filed as Exhibit 3.1 to the registrant’s Current Report on Form
+8-K filed on December 21, 2007, and incorporated herein by
+reference) 
+74 
+Exhibit 
+Number 
+Description 
+4.1 
+Shareholder
+Rights Plan adopted on July 15, 1999 (filed as Exhibit 4.1 to the
+registrant’s Quarterly Report on Form 10-Q/A for the quarter ended June
+30, 1999 and incorporated herein by reference) 
+4.2 
+First
+Amendment to Shareholders Rights Plan dated March 15, 2002 as
+adopted by the Board of Directors on July 19, 2001 (filed as Exhibit 4.2
+to the registrant’s Annual Report on Form 10-K for the year ended December
+31, 2001 and incorporated herein by reference) 
+4.3 
+Second
+Amendment to Shareholder Rights Plan dated April 24, 2006 (filed as
+Exhibit 4.1 to the registrant’s Quarterly Report on Form 10-Q for the
+quarter ended March 31, 2006 and incorporated herein by
+reference) 
+4.4 
+Indenture
+related to the 3.50% Senior Convertible Notes due 2027, dated as of April
+4, 2007, between St. Mary Land & Exploration Company and Wells Fargo
+Bank, National Association, as trustee (including the form of 3.50% Senior
+Convertible Note due 2027) (filed as Exhibit 4.1 to the registrant’s
+Current Report on Form 8-K filed on April 4, 2007, and incorporated herein
+by reference) 
+4.5 
+Registration
+Rights Agreement, dated as of April 4, 2007, among St. Mary Land &
+Exploration Company and Merrill Lynch, Pierce, Fenner & Smith
+Incorporated and Wachovia Capital Markets, LLC, for themselves and as
+representatives of the Initial Purchasers (filed as Exhibit 4.2 to the
+registrant’s Current Report on Form 8-K filed on April 4, 2007, and
+incorporated herein by reference) 
+10.1† 
+Stock
+Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the
+registrant’s Registration Statement on Form S-8 (Registration No.
+333-106438) and incorporated herein by reference) 
+10.2† 
+Incentive
+Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit
+99.2 to registrant’s Registration Statement on Form S-8 (Registration No.
+333-106438) and incorporated herein by reference) 
+10.3† 
+Cash
+Bonus Plan (filed as Exhibit 10.5 to the registrant’s Registration
+Statement on Form S-1 (Registration No. 33-53512) and incorporated herein
+by reference) 
+10.4† 
+Summary
+Plan Description/Pension Plan dated December 30, 1994 (filed as Exhibit
+10.35 to the registrant’s Annual Report on Form 10-K for the year ended
+December 31, 1994 and incorporated herein by
+reference) 
+10.5† 
+Non-qualified
+Unfunded Supplemental Retirement Plan, as amended (filed as Exhibit 10.8
+to the registrant’s Registration Statement on Form S-1 (Registration No.
+33-53512) and incorporated herein by reference) 
+10.6† 
+Employee
+Stock Purchase Plan (filed as Exhibit 10.48 filed to the registrant’s
+Annual Report on Form 10-K for the year ended December 31, 1997 and
+incorporated herein by reference) 
+10.7† 
+First
+Amendment to Employee Stock Purchase Plan dated February 27, 2001 (filed
+as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the
+quarter ended June 30, 2001 and incorporated herein by
+reference) 
+10.8† 
+Second
+Amendment to the Employee Stock Purchase Plan dated February 18, 2005
+(filed as Exhibit 10.48 to the registrants Annual Report on Form 10-K for
+the year ended December 31, 2004 and incorporated herein by
+reference) 
+10.9† 
+Form
+of Change of Control Severance Agreements (filed as Exhibit 10.1 to the
+registrant’s Quarterly Report on Form 10-Q for the quarter ended September
+30, 2001 and incorporated herein by reference) 
+10.10† 
+Amendment
+to Form of Change of Control Severance Agreement (filed as Exhibit 10.9 to
+the registrant’s Quarterly Report on Form 10-Q for the quarter ended June
+30, 2005 and incorporated herein by reference) 
+10.11 
+5.75%
+Senior Convertible Notes due 2022 Indenture dated March 13, 2002
+(filed as Exhibit 10.26 to the registrant’s Annual Report on Form 10-K for
+the year ended December 31, 2001 and incorporated herein by
+reference) 
+10.12 
+Amendment
+to and Extension of Office Lease dated as of December 14, 2001 (filed as
+Exhibit 10.45 to the registrant’s Annual Report on Form 10-K for the year
+ended December 31, 2003 and incorporated herein by
+reference) 
+75 
+Exhibit 
+Number 
+Description 
+10.13† 
+Non-Employee
+Director Stock Compensation Plan as adopted on March 27, 2003 (filed as
+Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the
+quarter ended June 30, 2003 and incorporated herein by
+reference) 
+10.14† 
+Restricted
+Stock Plan as adopted on April 18, 2004 (filed as Exhibit 10.1 to the
+registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
+2004 and incorporated herein by reference) 
+10.15† 
+Amendment
+to Restricted Stock Plan, dated December 15, 2005 (filed as Exhibit 10.2
+to the registrant’s Current Report on Form 8-K filed on December 19, 2005
+and incorporated herein by reference) 
+10.16† 
+Form
+of Restricted Stock Unit Award Agreement under the Restricted Stock Plan
+(filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K
+filed on March 15, 2005 and incorporated herein by
+reference) 
+10.17 
+Amended
+and Restated Credit Agreement dated as of April 7, 2005 among St. Mary
+Land & Exploration Company, Wachovia Bank, National Association, as
+Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+March 31, 2005 and incorporated herein by reference) 
+10.18 
+2006
+Equity Incentive Compensation Plan (filed on May 17, 2006 as Exhibit 99.1
+to the registrant’s Registration Statement on Form S-8 (Registration No.
+333-134221) and incorporated herein by reference) 
+10.19 
+Form
+of Non-Employee Director Restricted Stock Award Agreement (filed as
+Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on May
+18, 2006 and incorporated herein by reference) 
+10.20 
+Guaranty
+Agreement by St. Mary Energy Company in favor of Wachovia Bank,
+National Association, as Administrative Agent, dated April 7, 2005 (filed
+as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the
+quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.21 
+Guaranty
+Agreement by Nance Petroleum Corporation in favor of Wachovia Bank,
+National Association, as Administrative Agent, dated April 7, 2005 (filed
+as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the
+quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.22 
+Guaranty
+Agreement by NPC Inc. in favor of Wachovia Bank, National Association, as
+Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.4 to the
+registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31,
+2005 and incorporated herein by reference) 
+10.23 
+Pledge
+and Security Agreement between St. Mary Land & Exploration
+Company and Wachovia Bank, National Association, as Administrative Agent,
+dated April 7, 2005 (filed as Exhibit 10.5 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended March 31, 2005 and incorporated
+herein by reference) 
+10.24 
+Pledge
+and Security Agreement between Nance Petroleum Corporation and Wachovia
+Bank, National Association, as Administrative Agent, dated April 7, 2005
+(filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q
+for the quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.25 
+First
+Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit
+Mortgage, Assignment, Security Agreement, Fixture Filing and Financing
+Statement for the benefit of Wachovia Bank, National Association, as
+Administrative Agent, dated effective as of April 7, 2005 (filed as
+Exhibit 10.7 to the registrant’s Quarterly Report on Form 10-Q for the
+quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.26 
+Deed
+of Trust – St. Mary Land & Exploration to Wachovia Bank, National
+Association, as Administrative Agent, dated effective as of April 7, 2005
+(filed as Exhibit 10.8 to the registrant’s Quarterly Report on Form 10-Q
+for the quarter ended March 31, 2005 and incorporated herein by
+reference) 
+76 
+Exhibit 
+Number 
+Description 
+10.27† 
+Net
+Profits Interest Bonus Plan, as Amended on December 15, 2005 (filed as
+Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on
+December 19, 2005 and incorporated herein by reference) 
+10.28 
+Summary
+of Charitable Contributions in Honor of Thomas E. Congdon (filed as
+Exhibit 10.4 to the registrant’s Current Report on Form 8-K filed on
+December 19, 2005 and incorporated herein by reference) 
+10.29† 
+Summary
+of 2006 Base Salaries for Named Executive Officers (filed as Exhibit 10.5
+to the registrant’s Current Report on Form 8-K filed on December 19, 2005
+and incorporated herein by reference) 
+10.30 
+Employment
+Agreement of A.J. Best dated May 1, 2006 (filed as Exhibit 10.1 to the
+registrant’s Current Report on Form 8-K filed on May 4, 2006 and
+incorporated herein by reference) 
+10.31*† 
+Summary
+of 2008 Compensation Arrangements for Non-Employee
+Directors 
+10.32 
+Purchase
+Agreement, dated March 29, 2007, among St. Mary Land & Exploration
+Company, Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner &
+Smith Incorporated, Wachovia Capital Markets, LLC, Bear, Stearns & Co.
+Inc., BNP Paribas Securities Corp., and UBS Securities LLC (filed as
+Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on April
+4, 2007, and incorporated herein by reference) 
+10.33 
+First
+Amendment to Amended and Restated Credit Agreement, dated March 19, 2007,
+among St. Mary Land & Exploration Company, the Lenders party thereto,
+Wachovia Bank, National Association, as issuing bank and administrative
+agent, Wells Fargo Bank, N.A., as syndication agent, and BNP Paribas,
+Comerica Bank-Texas and JPMorgan Chase Bank, N.A., as co-documentation
+agents (filed as Exhibit 10.2 to the registrant’s Current Report on Form
+8-K filed on April 4, 2007, and incorporated herein by
+reference) 
+10.34 
+Net
+Profits Interest Bonus Plan, As Amended and Restated by the Board of
+Directors on July 19, 2007 (filed as Exhibit 10.1 to the registrant’s
+Current Report on Form 8-K filed on July 25, 2007, and
+incorporated herein by reference) 
+12.1* 
+Computation
+of Ratio of Earnings to Fixed Charges 
+14.1 
+Code
+of Business Conduct and Ethics (filed as Exhibit 14.1 to the registrant’s
+Annual Report on Form 10-K for the year ended December 31, 2003 and
+incorporated herein by reference) 
+21.1* 
+Subsidiaries
+of Registrant 
+23.1* 
+Consent
+of Deloitte & Touche LLP 
+23.2* 
+Consent
+of Ryder Scott Company L.P. 
+23.3* 
+Consent
+of Netherland, Sewell & Associates, Inc. 
+24.1* 
+Power
+of Attorney (included in signature page hereof) 
+31.1* 
+Certification
+of Chief Executive Officer pursuant to Section 302 of the
+Sarbanes – Oxley Act of 2002 
+31.2* 
+Certification
+of Chief Financial Officer pursuant to Section 302 of the
+Sarbanes – Oxley Act of 2002 
+32.1** 
+Certification
+pursuant to U.S.C. Section 1350 as adopted pursuant to Section 906 of the
+Sarbanes – Oxley Act of
+2002 
+* 
+Filed
+with this Form 10-K. 
+** 
+Furnished
+with this Form 10-K. 
+† 
+Exhibit
+constitutes a management contract or compensatory plan or
+arrangement. 
+(c) Financial Statement
+Schedules. See Item 15(a) above. 
+77 
+REPORT OF
+INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the
+Board of Directors and Stockholders of 
+St. Mary
+Land & Exploration Company and Subsidiaries 
+Denver,
+Colorado 
+We have
+audited the accompanying consolidated balance sheets of St. Mary Land &
+Exploration Company and subsidiaries (the “Company”) as of December 31, 2007 and
+2006, and the related consolidated statements of operations, stockholders’
+equity and comprehensive income, and cash flows for each of the three years in
+the period ended December 31, 2007. These financial statements are
+the responsibility of the Company’s management. Our responsibility is
+to express an opinion on these financial statements based on our
+audits. 
+We
+conducted our audits in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). Those standards require
+that we plan and perform the audit to obtain reasonable assurance about whether
+the financial statements are free of material misstatement. An audit
+includes examining, on a test basis, evidence supporting the amounts and
+disclosures in the financial statements. An audit also includes
+assessing the accounting principles used and significant estimates made by
+management, as well as evaluating the overall financial statement
+presentation. We believe that our audits provide a reasonable basis
+for our opinion. 
+In our
+opinion, such consolidated financial statements present fairly, in all material
+respects, the financial position of St. Mary Land & Exploration Company and
+subsidiaries as of December 31, 2007 and 2006, and the results of
+their operations and their cash flows for each of the three years in the period
+ended December 31, 2007, in conformity with accounting principles generally
+accepted in the United States of America. 
+As
+discussed in Note 1 and Note 8 to the financial statements, the Company changed
+its method of accounting and disclosure for stock based compensation and its
+defined benefit plans in 2006. 
+We have
+also audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), the Company’s internal control over financial
+reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated
+Framework issued by the Committee of Sponsoring Organizations of the
+Treadway Commission, and our report dated February 21, 2008, expressed an
+unqualified opinion on the Company’s internal control over financial
+reporting. 
+Denver,
+Colorado 
+February
+21, 2008 
+F-1 
+PART
+II. FINANCIAL INFORMATION 
+ITEM
+8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+ST.
+MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+CONSOLIDATED
+BALANCE SHEETS 
+(In
+thousands, except share amounts) 
+December
+31, 
+December
+31, 
+ASSETS 
+2007 
+2006 
+Current
+assets: 
+Cash
+and cash equivalents 
+$ 
+43,510 
+$ 
+1,464 
+Short-term
+investments 
+1,173 
+1,450 
+Accounts
+receivable 
+159,149 
+142,721 
+Refundable
+income taxes 
+933 
+7,684 
+Prepaid
+expenses and other 
+14,129 
+17,485 
+Accrued
+derivative asset 
+17,836 
+56,136 
+Deferred
+income taxes 
+33,211 
+- 
+Total
+current assets 
+269,941 
+226,940 
+Property
+and equipment (successful efforts method), at cost: 
+Proved
+oil and gas properties 
+2,721,229 
+2,063,911 
+Less
+- accumulated depletion, depreciation, and amortization 
+(804,785 
+) 
+(630,051 
+) 
+Unproved
+oil and gas properties, net of impairment allowance 
+of
+$10,319 in 2007 and $9,425 in 2006 
+134,386 
+100,118 
+Wells
+in progress 
+137,417 
+97,498 
+Oil
+and gas properties held for sale less accumulated
+depletion, 
+depreciation,
+and amortization 
+76,921 
+- 
+Other
+property and equipment, net of accumulated depreciation 
+of
+$11,549 in 2007 and $9,740 in 2006 
+9,230 
+6,988 
+2,274,398 
+1,638,464 
+Noncurrent
+assets: 
+Goodwill 
+9,452 
+9,452 
+Accrued
+derivative asset 
+5,483 
+16,939 
+Other
+noncurrent assets 
+12,406 
+7,302 
+Total
+noncurrent assets 
+27,341 
+33,693 
+Total
+Assets 
+$ 
+2,571,680 
+$ 
+1,899,097 
+LIABILITIES
+AND STOCKHOLDERS' EQUITY 
+Current
+liabilities: 
+Accounts
+payable and accrued expenses 
+$ 
+254,918 
+$ 
+171,834 
+Short-term
+note payable 
+- 
+4,469 
+Accrued
+derivative liability 
+97,627 
+13,100 
+Deferred
+income taxes 
+- 
+14,667 
+Deposit
+associated with oil and gas properties held for sale 
+10,000 
+- 
+Total
+current liabilities 
+362,545 
+204,070 
+Noncurrent
+liabilities: 
+Long-term
+credit facility 
+285,000 
+334,000 
+Senior
+convertible notes 
+287,500 
+99,980 
+Asset
+retirement obligation 
+96,432 
+77,242 
+Asset
+retirement obligation associated with oil and gas properties held for
+sale 
+8,744 
+- 
+Net
+Profits Plan liability 
+211,406 
+160,583 
+Deferred
+income taxes 
+257,603 
+224,518 
+Accrued
+derivative liability 
+190,262 
+46,432 
+Other
+noncurrent liabilities 
+8,843 
+8,898 
+Total
+noncurrent liabilities 
+1,345,790 
+951,653 
+Commitments
+and contingencies 
+Stockholders'
+equity: 
+Common
+stock, $0.01 par value: authorized - 200,000,000
+shares; 
+issued: 64,010,832
+shares in 2007 and 55,251,733 shares in 2006; 
+outstanding,
+net of treasury shares: 63,001,120 shares in
+2007 
+and
+55,001,733 shares in 2006 
+640 
+553 
+Additional
+paid-in capital 
+170,070 
+38,940 
+Treasury
+stock, at cost: 1,009,712 shares in 2007 and 250,000 shares in
+2006 
+(29,049 
+) 
+(4,272 
+) 
+Retained
+earnings 
+878,652 
+695,224 
+Accumulated
+other comprehensive income (loss) 
+(156,968 
+) 
+12,929 
+Total
+stockholders' equity 
+863,345 
+743,374 
+Total
+Liabilities and Stockholders' Equity 
+$ 
+2,571,680 
+$ 
+1,899,097 
+The
+accompanying notes are an integral part of these consolidated financial
+statements. 
+F-2 
+ST.
+MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF OPERATIONS 
+(In
+thousands, except per share amounts) 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+Operating
+revenues: 
+Oil
+and gas production revenue 
+$ 
+912,093 
+$ 
+730,737 
+$ 
+733,544 
+Realized
+oil and gas hedge gain (loss) 
+24,484 
+28,176 
+(22,539 
+) 
+Marketed
+gas system revenue 
+45,149 
+20,936 
+25,269 
+Gain
+(loss) on sale of proved properties 
+(367 
+) 
+6,910 
+222 
+Other
+revenue 
+8,735 
+942 
+3,094 
+Total
+operating revenues 
+990,094 
+787,701 
+739,590 
+Operating
+expenses: 
+Oil
+and gas production expense 
+218,208 
+176,590 
+142,873 
+Depletion,
+depreciation, amortization, 
+and asset retirement obligation liability accretion 
+227,596 
+154,522 
+132,758 
+Exploration 
+58,686 
+51,889 
+44,931 
+Impairment
+of proved properties 
+- 
+7,232 
+- 
+Abandonment
+and impairment of unproved properties 
+4,756 
+4,301 
+5,780 
+General
+and administrative 
+60,149 
+38,873 
+32,756 
+Change
+in Net Profits Plan liability 
+50,823 
+23,759 
+106,263 
+Marketed
+gas system expense 
+42,485 
+18,526 
+24,164 
+Unrealized
+derivative loss 
+5,458 
+7,094 
+1,615 
+Other
+expense 
+2,522 
+2,649 
+2,456 
+Total
+operating expenses 
+670,683 
+485,435 
+493,596 
+Income
+from operations 
+319,411 
+302,266 
+245,994 
+Nonoperating
+income (expense): 
+Interest
+income 
+746 
+1,576 
+456 
+Interest
+expense 
+(19,895 
+) 
+(8,521 
+) 
+(8,213 
+) 
+Income
+before income taxes 
+300,262 
+295,321 
+238,237 
+Income
+tax expense 
+(110,550 
+) 
+(105,306 
+) 
+(86,301 
+) 
+Net
+income 
+$ 
+189,712 
+$ 
+190,015 
+$ 
+151,936 
+Basic
+weighted-average common shares outstanding 
+61,852 
+56,291 
+56,907 
+Diluted
+weighted-average common shares outstanding 
+64,850 
+65,962 
+66,894 
+Basic
+net income per common share 
+$ 
+3.07 
+$ 
+3.38 
+$ 
+2.67 
+Diluted
+net income per common share 
+$ 
+2.94 
+$ 
+2.94 
+$ 
+2.33 
+The
+accompanying notes are an integral part of these consolidated financial
+statements. 
+F-3 
+ST.
+MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE
+INCOME 
+(In
+thousands, except share amounts) 
+Accumulated 
+Additional 
+Deferred 
+Other 
+Total 
+Common
+Stock 
+Paid-in 
+Treasury
+Stock 
+Stock-Based 
+Retained 
+Comprehensive 
+Stockholders' 
+Shares 
+Amount 
+Capital 
+Shares 
+Amount 
+Compensation 
+Earnings 
+Income
+(Loss) 
+Equity 
+Balances,
+December 31, 2004 
+57,458,246 
+$ 
+574 
+$ 
+127,374 
+(500,000 
+) 
+$ 
+(5,295 
+) 
+$ 
+(5,039 
+) 
+$ 
+364,567 
+$ 
+2,274 
+$ 
+484,455 
+Comprehensive
+income, net of tax: 
+Net
+income 
+- 
+- 
+- 
+- 
+- 
+- 
+151,936 
+- 
+151,936 
+Change
+in derivative instrument fair value 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+(71,522 
+) 
+(71,522 
+) 
+Reclassification
+to earnings 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+14,366 
+14,366 
+Minimum
+pension liability adjustment 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+283 
+283 
+Total
+comprehensive income 
+95,063 
+Cash
+dividends, $ 0.10 per share 
+- 
+- 
+- 
+- 
+- 
+- 
+(5,691 
+) 
+- 
+(5,691 
+) 
+Treasury
+stock purchases 
+- 
+- 
+- 
+(1,175,282 
+) 
+(28,902 
+) 
+- 
+- 
+- 
+(28,902 
+) 
+Retirement
+of treasury stock 
+(1,411,356 
+) 
+(14 
+) 
+(28,729 
+) 
+1,411,356 
+28,743 
+- 
+- 
+- 
+- 
+Issuance
+of common stock under Employee 
+Stock
+Purchase Plan 
+28,447 
+- 
+601 
+- 
+- 
+- 
+- 
+- 
+601 
+Sale
+of common stock, including income 
+tax
+benefit of stock option exercises 
+936,403 
+10 
+16,619 
+- 
+- 
+- 
+- 
+- 
+16,629 
+Deferred
+compensation related to issued restricted 
+stock
+unit awards, net of forfeitures 
+- 
+- 
+3,404 
+- 
+(3,404 
+) 
+- 
+- 
+- 
+Directors'
+stock compensation 
+- 
+- 
+- 
+13,926 
+306 
+(306 
+) 
+- 
+- 
+- 
+Accrued
+stock-based compensation 
+- 
+- 
+4,009 
+- 
+- 
+- 
+- 
+- 
+4,009 
+Amortization
+of deferred stock-based 
+compensation 
+- 
+- 
+- 
+- 
+- 
+3,156 
+- 
+- 
+3,156 
+Balances,
+December 31, 2005 
+57,011,740 
+$ 
+570 
+$ 
+123,278 
+(250,000 
+) 
+$ 
+(5,148 
+) 
+$ 
+(5,593 
+) 
+$ 
+510,812 
+$ 
+(54,599 
+) 
+$ 
+569,320 
+Comprehensive
+income, net of tax: 
+Net
+income 
+- 
+- 
+- 
+- 
+- 
+- 
+190,015 
+- 
+190,015 
+Change
+in derivative instrument fair value 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+87,107 
+87,107 
+Reclassification
+to earnings 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+(18,129 
+) 
+(18,129 
+) 
+Minimum
+pension liability adjustment 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+(180 
+) 
+(180 
+) 
+Total
+comprehensive income 
+258,813 
+SFAS
+No. 158 transition amount 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+(1,270 
+) 
+(1,270 
+) 
+Cash
+dividends, $ 0.10 per share 
+- 
+- 
+- 
+- 
+- 
+- 
+(5,603 
+) 
+- 
+(5,603 
+) 
+Treasury
+stock purchases 
+- 
+- 
+- 
+(3,319,300 
+) 
+(123,108 
+) 
+- 
+- 
+- 
+(123,108 
+) 
+Retirement
+of treasury stock 
+(3,275,689 
+) 
+(33 
+) 
+(122,598 
+) 
+3,275,689 
+122,631 
+- 
+- 
+- 
+- 
+Issuance
+of common stock under Employee 
+Stock
+Purchase Plan 
+26,046 
+- 
+814 
+- 
+- 
+- 
+- 
+- 
+814 
+Sale
+of common stock, including income 
+tax
+benefit of stock option exercises 
+1,489,636 
+16 
+32,970 
+- 
+- 
+- 
+- 
+- 
+32,986 
+Adoption
+of Statement of Financial Accounting 
+Standards
+No. 123(R) 
+- 
+- 
+(5,593 
+) 
+- 
+- 
+5,593 
+- 
+- 
+- 
+Stock-based
+compensation expense 
+- 
+- 
+10,069 
+43,611 
+1,353 
+- 
+- 
+- 
+11,422 
+Balances,
+December 31, 2006 
+55,251,733 
+$ 
+553 
+$ 
+38,940 
+(250,000 
+) 
+$ 
+(4,272 
+) 
+$ 
+- 
+$ 
+695,224 
+$ 
+12,929 
+$ 
+743,374 
+Comprehensive
+income, net of tax: 
+Net
+income 
+- 
+- 
+- 
+- 
+- 
+- 
+189,712 
+- 
+189,712 
+Change
+in derivative instrument fair value 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+(154,497 
+) 
+(154,497 
+) 
+Reclassification
+to earnings 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+(15,470 
+) 
+(15,470 
+) 
+Pension
+liability adjustment 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+70 
+70 
+Total
+comprehensive income 
+19,815 
+Cash
+dividends, $ 0.10 per share 
+- 
+- 
+- 
+- 
+- 
+- 
+(6,284 
+) 
+- 
+(6,284 
+) 
+Treasury
+stock purchases 
+- 
+- 
+- 
+(792,216 
+) 
+(25,957 
+) 
+- 
+- 
+- 
+(25,957 
+) 
+Issuance
+of common stock under Employee 
+- 
+Stock
+Purchase Plan 
+29,534 
+- 
+919 
+- 
+- 
+- 
+- 
+- 
+919 
+Conversion
+of 5.75% Senior Convertible Notes 
+due 2022 to common stock, including income 
+tax
+benefit of conversion 
+7,692,295 
+77 
+106,854 
+- 
+- 
+- 
+- 
+- 
+106,931 
+Issuance
+of common stock upon settlement of 
+RSUs following expiration of restriction period, 
+net
+of shares used for tax withholdings 
+302,370 
+3 
+(4,569 
+) 
+- 
+- 
+- 
+- 
+- 
+(4,566 
+) 
+Sale
+of common stock, including income 
+tax
+benefit of stock option exercises 
+733,650 
+7 
+19,011 
+- 
+- 
+- 
+- 
+- 
+19,018 
+Stock-based
+compensation expense 
+1,250 
+- 
+8,915 
+32,504 
+1,180 
+- 
+- 
+- 
+10,095 
+Balances,
+December 31, 2007 
+64,010,832 
+$ 
+640 
+$ 
+170,070 
+(1,009,712 
+) 
+$ 
+(29,049 
+) 
+$ 
+- 
+$ 
+878,652 
+$ 
+(156,968 
+) 
+$ 
+863,345 
+The
+accompanying notes are an integral part of these consolidated financial
+statements. 
+F-4 
+ST.
+MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF CASH FLOWS 
+(In
+thousands) 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+Reconciliation
+of net income to net cash provided 
+by
+operating activities: 
+Net
+income 
+$ 
+189,712 
+$ 
+190,015 
+$ 
+151,936 
+Adjustments
+to reconcile net income to net cash 
+provided
+by operating activities: 
+Gain
+on insurance settlement 
+(5,243 
+) 
+- 
+- 
+(Gain)
+loss on sale of proved properties 
+367 
+(6,910 
+) 
+(222 
+) 
+Depletion,
+depreciation, amortization, 
+and
+asset retirement obligation liability accretion 
+227,596 
+154,522 
+132,758 
+Exploratory
+dry hole expense 
+14,365 
+10,191 
+8,104 
+Impairment
+of proved properties 
+- 
+7,232 
+- 
+Abandonment
+and impairment of unproved properties 
+4,756 
+4,301 
+5,780 
+Unrealized
+derivative loss 
+5,458 
+7,094 
+1,615 
+Change
+in Net Profits Plan liability 
+50,823 
+23,759 
+106,263 
+Stock-based
+compensation expense* 
+10,095 
+11,422 
+7,165 
+Deferred
+income taxes 
+92,955 
+74,832 
+5,547 
+Other 
+(10,497 
+) 
+(2,479 
+) 
+281 
+Changes
+in current assets and liabilities: 
+Accounts
+receivable 
+(6,557 
+) 
+22,476 
+(57,113 
+) 
+Refundable
+income taxes 
+6,751 
+- 
+- 
+Prepaid
+expenses and other 
+19,375 
+(17,886 
+) 
+(1,210 
+) 
+Accounts
+payable and accrued expenses 
+40,769 
+5,215 
+42,438 
+Income
+tax benefit from the exercise of stock options** 
+(9,933 
+) 
+(16,084 
+) 
+6,037 
+Net
+cash provided by operating activities 
+630,792 
+467,700 
+409,379 
+Cash
+flows from investing activities: 
+Proceeds
+from insurance settlement 
+5,948 
+- 
+- 
+Proceeds
+from sale of oil and gas properties 
+495 
+860 
+1,213 
+Capital
+expenditures 
+(637,748 
+) 
+(455,056 
+) 
+(270,881 
+) 
+Acquisition
+of oil and gas properties 
+(182,883 
+) 
+(270,639 
+) 
+(73,905 
+) 
+Deposits
+to short-term investments 
+(1,168 
+) 
+- 
+(1,502 
+) 
+Receipts
+from short-term investments 
+1,450 
+25 
+1,427 
+Other 
+10,034 
+91 
+3,869 
+Net
+cash used in investing activities 
+(803,872 
+) 
+(724,719 
+) 
+(339,779 
+) 
+Cash
+flows from financing activities: 
+Proceeds
+from credit facility 
+822,000 
+935,137 
+284,090 
+Repayment
+of credit facility 
+(871,000 
+) 
+(601,137 
+) 
+(321,090 
+) 
+Repayment
+of short-term note payable 
+(4,469 
+) 
+- 
+- 
+Proceeds
+from short-term note payable 
+- 
+4,469 
+- 
+Income
+tax benefit from the exercise of stock options** 
+9,933 
+16,084 
+- 
+Proceeds
+from issuance of senior convertible debt, net of 
+280,657 
+- 
+- 
+deferred
+financing costs 
+Proceeds
+from sale of common stock 
+10,007 
+17,716 
+11,193 
+Repurchase
+of common stock 
+(25,904 
+) 
+(123,108 
+) 
+(28,902 
+) 
+Dividends
+paid 
+(6,284 
+) 
+(5,603 
+) 
+(5,691 
+) 
+Other 
+186 
+- 
+(693 
+) 
+Net
+cash provided by (used in) financing activities 
+215,126 
+243,558 
+(61,093 
+) 
+Net
+change in cash and cash equivalents 
+42,046 
+(13,461 
+) 
+8,507 
+Cash
+and cash equivalents at beginning of period 
+1,464 
+14,925 
+6,418 
+Cash
+and cash equivalents at end of period 
+$ 
+43,510 
+$ 
+1,464 
+$ 
+14,925 
+* 
+Stock-based compensation expense is a component of Exploration expense and
+General and administrative expense on the 
+Consolidated S ta tements of
+Operations. During 2007, 2006, and 2005, respectively, approximately
+$3.2 million, $3.1 million, and 
+$3.3
+million, of stock-based compensation expense was included in Exploration
+expense. During 2007, 2006, and 2005, repectively, 
+approximately
+$6.9 million, $8.3 million, and $3.9 million of stock-based compensation
+expense was included in General and administrative 
+expense. 
+** SFAS 123(R) requires presentation of the income
+tax benefit from the exercise of stock options to be presented in
+financing 
+activities subsequent to
+adoption. The prior period classification is to remain unchanged
+under SFAS 123(R). 
+The
+accompanying notes are an integral part of these consolidated financial
+statements. 
+F-5 
+ST.
+MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF CASH FLOWS (Continued) 
+Supplemental
+schedule of additional cash flow information and noncash investing and
+financing activities: 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(in
+thousands) 
+Cash
+paid for interest, net of capitalized interest 
+$ 
+22,816 
+$ 
+9,826 
+$ 
+8,458 
+Cash
+paid (refunded) for income taxes 
+$ 
+(1,156 
+) 
+$ 
+25,505 
+$ 
+65,752 
+As
+of December 31, 2007, 2006, and 2005, $116.9 million, $73.5 million,
+and $51.0 million, respectively, are included as 
+additions
+to oil and gas properties and as increases to accounts payable and accrued
+expenses. These oil and gas 
+property
+additions are reflected in cash used in investing activities in the
+periods that the payables are settled. 
+In
+May 2007 and 2006, July 2007 and 2006 , and May 2005, the
+Company issued 26,292, 26,076, 6,212, 3,751 and 13,926 
+shares,
+respectively, of common stock from treasury to its non-employee directors
+pursuant to the Company's 
+non-employee
+director stock compensation plan. The Company recorded compensation
+expense related to the 
+issuances
+of shares to non-employee directors of $983,500, $976,000 and $178,000 for
+the years ended December 31, 2007, 
+2006
+and 2005, respectively. 
+In
+March 2007 the Company called the 5.75% Senior Convertible Notes for
+redemption. The note holders elected 
+to
+convert the 5.75% Senior Convertible Notes to common stock. As a
+result, the Company issued 7,692,295 shares 
+of
+common stock on March 16, 2007, in exchange for the $100 million of 5.75%
+Senior Convertible Notes. The conversion 
+was
+executed in accordance with the conversion provisions of the original
+indenture. Additionally, the conversion resulted 
+in
+a $7.0 million decrease in non-current deferred income taxes and a
+corresponding increase in additional paid-in 
+capital
+that is a result of the recognition of the cumulative excess tax benefit
+earned by the Company associated with the 
+contingent
+interest feature of this note. 
+In
+June 2006 the Company hired a new senior executive. In doing so, the
+Company issued 13,784 shares of stock and 
+recorded
+compensation expense of approximately $728,000. Additionally, in
+March 2007 the Company issued 1,250 shares 
+of
+stock to the senior executive as the Company reached certain performance
+levels. The Company has recognized 
+approximately
+$136,000 of expense related to this issuance as of December 31,
+2007. 
+In
+February 2007, February 2006, and March 2005, the Company issued 78,657,
+484,351, and 195,312 restricted stock 
+units,
+respectively, pursuant to the Company's restricted stock plan. The
+total value of the issuances were 
+$2.5
+million, $16.4 million, and $4.5 million, respectively. 
+In
+May 2006 the Company closed a transaction whereby it exchanged non-core
+oil and gas properties for oil and gas 
+properties
+located in Richland County, Montana. This transaction is considered a
+non-monetary exchange for accounting 
+purposes
+with a fair value assigned to this transaction of $11.5
+million. 
+The accompanying notes
+are an integral part of these consolidated financial statements. 
+F-6 
+ST. MARY
+LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER
+31, 2007 
+Note
+1 – Summary of Significant Accounting Policies 
+Description
+of Operations 
+St. Mary
+Land & Exploration Company (“St. Mary” or the "Company") is an
+independent energy company engaged in the exploration, exploitation,
+development, acquisition, and production of natural gas and crude
+oil. The Company’s operations are conducted in the continental United
+States and offshore in the Gulf of Mexico. 
+Basis
+of Presentation 
+The
+accompanying consolidated financial statements include the accounts of the
+Company and its wholly-owned subsidiaries. Subsidiaries that are not
+wholly-owned are accounted for using full consolidation with minority interest
+or by the equity or cost method as appropriate. Equity method
+investments are included in other noncurrent assets, and minority interest is
+included in other noncurrent liabilities in the accompanying consolidated
+balance sheets. All significant intercompany accounts and
+transactions have been eliminated. 
+Use
+of Estimates in the Preparation of Financial Statements 
+The
+preparation of financial statements in conformity with accounting principles
+generally accepted in the United States requires management to make estimates
+and assumptions that affect the reported amounts of oil and gas reserves, assets
+and liabilities, disclosure of contingent assets and liabilities at the date of
+the financial statements, and the reported amounts of revenues and expenses
+during the reporting period. Actual results could differ from those
+estimates. Estimates of oil and gas reserve quantities provide the
+basis for calculations of depletion, depreciation, and amortization
+(“DD&A”), impairment, goodwill, and the Net Profits Interest Bonus Plan (the
+“Net Profits Plan”) liability, each of which represents a significant component
+of the accompanying consolidated financial statements. 
+Revenue
+Recognition 
+The
+Company derives revenue primarily from the sale of produced natural gas and
+crude oil. The Company reports revenue as the gross amount received before
+taking into account production taxes and transportation costs, which are
+reported as separate expenses. Revenue is recorded in the month the
+Company’s production is delivered to the purchaser, but payment is generally
+received between 30 and 90 days after the date of production. No revenue
+is recognized unless it is determined that title to the product has transferred
+to a purchaser. At the end of each month, the Company estimates the amount
+of production delivered to the purchaser and the price the Company will
+receive. The Company uses its knowledge of its properties, their
+historical performance, the anticipated effect of weather conditions during the
+month of production, New York Mercantile Exchange (“NYMEX”) and local spot
+market prices, and other factors as the basis for these estimates. 
+Cash
+and Cash Equivalents 
+The
+Company considers all liquid investments purchased with an initial maturity of
+three months or less to be cash equivalents. The carrying value of
+cash and cash equivalents approximates fair value due to the short-term nature
+of these instruments. 
+F-7
+Short-term
+Investments 
+As of
+December 31, 2007, the Company’s short-term investments consist of a certificate
+of deposit. As of December 31, 2006, the Company’s short-term
+investments consist of investment-grade marketable debt that is classified as
+held-to-maturity or available-for-sale. Securities categorized as
+held-to-maturity are stated at amortized cost whereas available-for-sale
+securities are marked-to-market. As of December 31, 2007, and 2006,
+the Company held $1.2 million and $1.5 million, respectively, of
+short-term investments. 
+Concentration
+of Credit Risk 
+Substantially
+all of the Company's receivables are within the oil and gas industry, primarily
+from purchasers of oil and gas and from partners with interests in common
+properties operated by the Company. Although diversified among many companies,
+collectability is dependent upon the financial wherewithal of each individual
+company as well as the general economic conditions of the
+industry. The receivables are not collateralized. To date
+the Company has had minimal bad debts. 
+The
+Company has accounts with separate banks in Denver, Colorado; Shreveport,
+Louisiana; Franklin, Louisiana; Tulsa, Oklahoma; and Billings,
+Montana. At December 31, 2007, 2006, and 2005, the Company had
+$42.8 million, $1.6 million, and $36.8 million respectively,
+invested in money market funds and overnight investment sweep
+accounts. The difference between the investment amount and the cash
+and cash equivalents amount on the accompanying consolidated balance sheets
+represents uncleared disbursements and non-interest bearing checking
+accounts. The Company’s policy is to invest in highly-rated
+instruments and to limit the amount of credit exposure at each individual
+institution. 
+The
+Company currently uses nine separate counterparties for its oil and gas
+commodity and interest rate derivatives. The counterparties to the
+Company’s derivative instruments are all highly-rated entities with corporate
+credit ratings at or exceeding A- or A2 as classified by Standard & Poor’s
+and Moody’s respectively. 
+Oil
+and Gas Producing Activities 
+The
+Company follows the successful efforts method of accounting for its oil and gas
+properties. Under this method of accounting, all property acquisition
+costs and costs of exploratory and development wells are capitalized when
+incurred, pending determination of whether the well has found proved
+reserves. If an exploratory well does not find proved reserves, the
+costs of drilling the well are charged to expense. Exploratory dry
+hole costs are included in cash flows from investing activities as part of
+capital expenditures within the accompanying consolidated statements of cash
+flows. The costs of development wells are capitalized whether or not
+proved reserves are found. 
+Geological
+and geophysical costs and the costs of carrying and retaining unproved
+properties are expensed as incurred. DD&A of capitalized costs
+related to proved oil and gas properties is calculated on a field-by-field basis
+using the units-of-production method based upon proved reserves. The
+computation of DD&A takes into consideration restoration, dismantlement, and
+abandonment costs and the anticipated proceeds from salvaging
+equipment. As of December 31, 2007, the Company’s capitalized proved
+oil and gas properties included $95.9 million of estimated salvage value,
+which is excluded from the depletable property costs when calculating
+DD&A. 
+The
+Company follows Statement of Financial Accounting Standards Staff Position No.
+FAS 19-1, “Accounting for Suspended Well Costs,” (“FSP FAS
+19-1”). For additional discussion, please see Note 13 – Disclosures
+about Oil and Gas Producing Activities under the heading Suspended Well
+Costs . 
+The
+Company reviews its long-lived assets for impairments when events or changes in
+circumstances indicate that an impairment may have occurred. The
+impairment test for proved properties compares the expected undiscounted future
+net cash flows on a field-by-field basis with the related net capitalized costs,
+including costs associated with asset retirement obligations, at the end of each
+period. Expected future cash flows are calculated on all proved
+reserves using a discount rate and price forecasts selected by the Company’s
+management. The discount rate is a rate that management believes is
+representative of current market conditions. The price forecast
+F-8
+is based on NYMEX strip pricing, adjusted for basis differentials,
+for the first five years. At the end of the first five years a flat
+terminal price is used. Future operating costs are also adjusted as
+deemed appropriate for these estimates. When the net capitalized
+costs exceed the undiscounted future net revenues of a field, the cost of the
+field is reduced to fair value, which is determined using discounted future net
+revenues. An impairment write down is provided on unproved property
+when the Company determines that either the property will not be developed or
+the carrying value is not realizable. 
+Sales
+of Proved and Unproved Properties 
+The sale
+of a partial interest in a proved oil and gas property is accounted for as
+normal retirement, and no gain or loss is recognized as long as this treatment
+does not significantly affect the units-of-production depletion
+rate. A gain or loss is recognized for all other sales of producing
+properties and is included in the results of operations. 
+The sale
+of a partial interest in an unproved property is accounted for as a recovery of
+cost when substantial uncertainty exists as to recovery of the cost applicable
+to the interest retained. A gain on the sale is recognized to the
+extent the sales price exceeds the carrying amount of the unproved
+property. A gain or loss is recognized for all other sales of
+nonproducing properties and is included in the accompanying consolidated results
+of operations. 
+Assets
+Held for Sale 
+In
+accordance with Statement of Financial Accounting Standards No. 144, “Accounting
+for the Impairment or Disposal of Long-Lived Assets”, any properties held for
+sale as of the date of presentation of a balance sheet have been classified as
+assets held for sale and are separately presented on the accompanying
+consolidated balance sheets at the lower of net book value or fair value less
+the cost to sell. The asset retirement obligation liabilities related
+to such properties have been reclassified to asset retirement obligation
+associated with oil and gas properties held for sale. For additional
+discussion of assets held for sale, please see Note 3 – Acquisitions,
+Divestitures, and Assets Held for Sale. 
+Other
+Property and Equipment 
+Other
+property and equipment such as office furniture and equipment, automobiles, and
+computer hardware and software are recorded at cost. Costs of
+renewals and improvements that substantially extend the useful lives of the
+assets are capitalized. Maintenance and repair costs are expensed
+when incurred. Depreciation is calculated using the straight-line
+method over the estimated useful lives of the assets from three to eight
+years. When other property and equipment is sold or retired, the
+capitalized costs and related accumulated depreciation are removed from the
+accounts. 
+Gas
+Balancing 
+The
+Company uses the sales method of accounting for gas revenue whereby sales
+revenue is recognized on all gas sold to purchasers, regardless of whether the
+sales are proportionate to the Company’s ownership in the
+property. An asset or a liability is recognized to the extent that
+there is an imbalance in excess of the remaining gas reserves on the underlying
+properties. The Company’s gas imbalance position at December 31,
+2007, and 2006, resulted in the recording of $1.9 million and $1.4 million,
+respectively, to accounts receivable, and $1.1 million and $791,000,
+respectively, to accounts payable. 
+Derivative Financial
+Instruments 
+The
+Company seeks to protect its rate of return on acquisitions of producing
+properties and other production by hedging cash flows. The Company intends for
+derivative instruments used for this purpose to be designated as, and to qualify
+as, cash flow hedging instruments under Statement of Financial Accounting
+Standards No. 133, “Accounting for Derivative Instruments and Hedging
+Activities,” (“SFAS No. 133”) and related pronouncements. The Company
+seeks to minimize basis risk and indexes the majority of its oil hedges to NYMEX
+prices and the majority of its gas hedges to various regional index prices
+associated with pipelines in 
+F-9
+proximity to the Company's areas of gas production. For
+additional discussion of derivatives, please see Note 10 – Derivative
+Financial Instruments. 
+Fair
+Value of Financial Instruments 
+The
+Company’s financial instruments including cash and cash equivalents, accounts
+receivable, and accounts payable are carried at cost, which approximates fair
+value due to the short-term maturity of these instruments. The
+recorded value of the Company’s credit facility approximates its fair value as
+it bears interest at a floating rate. The Company had $285.0 million
+in loans outstanding under its revolving credit agreement as of
+December 31, 2007, and $334.0 million in loans outstanding under its
+revolving credit agreement as of December 31, 2006. The
+Company’s interest rate swaps are recorded at fair value as discussed in Note 10
+– Derivative Financial Instruments. The Company’s 3.50% Senior
+Convertible Notes due 2027 (the “3.50% Senior Convertible Notes”) are recorded
+at cost, and the fair value is disclosed in Note 5 – Long-Term
+Debt. The Company has other financial instruments and investments in
+available-for-sale securities that are marked-to-market for which changes in
+fair value are recorded in accumulated other comprehensive income in the
+accompanying consolidated balance sheets. Since considerable judgment
+is required to develop estimates of fair value, the estimates provided are not
+necessarily indicative of the amounts the Company could realize upon the sale or
+refinancing of such instruments. 
+Net
+Profits Plan 
+The
+Company records the estimated fair value of the liability for future payments
+under the Net Profits Plan. The estimated liability is a discounted
+calculation and has underlying assumptions including estimates of oil and gas
+reserves, recurring and workover lease operating expense, production and ad
+valorem tax rates, present value discount factors, and pricing
+assumptions. The estimates the Company uses in calculating the
+long-term liability are adjusted from period-to-period based on the most current
+information attributable to the underlying assumptions. Changes in
+the estimated liability of future payments associated with the Net Profits Plan
+are recorded as increases or decreases to expense in the current period as a
+separate line item in the accompanying consolidated statements of operations as
+these changes are considered changes in estimates. The estimated Net
+Profits Plan liability is recorded separately as a noncurrent liability in the
+accompanying consolidated balance sheets. 
+The
+distribution amounts due to participants and payable in each period under the
+Net Profits Plan as cash compensation related to periodic operations are
+recognized as compensation expense and are included within general and
+administrative expense and exploration expense in the accompanying consolidated
+statements of operations. The corresponding current liability is
+included in accounts payable and accrued expenses in the accompanying
+consolidated balance sheets. This treatment provides for a consistent
+matching of cash expense with net cash flows from the oil and gas properties in
+each respective pool of the Net Profits Plan. For additional
+discussion, please see Note 7 – Compensation Plans under the heading Net Profits
+Plan. 
+Income
+Taxes 
+The
+Company accounts for deferred income taxes utilizing Statement of Financial
+Accounting Standards No. 109, “Accounting for Income Taxes,”
+("SFAS No. 109") as amended. SFAS No. 109 prescribes an
+asset and liability method whereby deferred tax assets and liabilities are
+recognized based on the tax effects of temporary differences between the
+carrying amount on the financial statements and the tax bases of assets and
+liabilities, as measured by current enacted tax rates. These
+differences will result in taxable income or deductions in future years when the
+reported amount of the asset or liability is recovered or settled,
+respectively. When appropriate, in accordance with SFAS No. 109,
+the Company evaluates the need for a valuation allowance to reduce deferred tax
+assets. 
+F-10
+Earnings
+per Share 
+Basic net
+income per common share of stock is calculated by dividing net income available
+to common stockholders by the weighted-average basic common shares outstanding
+for the respective period. The shares represented by vested
+restricted stock units (“RSUs”) are included in the calculation of the
+weighted-average basic common shares outstanding. The basic earnings
+per share calculations reflect the impact of any repurchases of shares of common
+stock made by the Company. 
+Diluted
+net income per common share of stock is calculated by dividing adjusted net
+income by the weighted-average diluted common shares outstanding, which includes
+the effect of potentially dilutive securities. Potentially dilutive
+securities for the diluted earnings per share calculations consist of unvested
+RSUs, in-the-money outstanding stock options to purchase the Company’s common
+stock, shares into which the 5.75% Senior Convertible Notes due 2022 (the
+“5.75% Senior Convertible Notes”) were convertible for the periods those
+notes were outstanding, and shares into which the 3.50% Senior Convertible
+Notes due 2027 are convertible. 
+The
+shares underlying the unvested grants of RSUs are included in the diluted
+earnings per share calculation beginning on the grant date of the
+RSUs. Following the lapse of restriction periods, the shares
+underlying the units are issued and therefore are included in the number of
+issued and outstanding shares. 
+The
+treasury stock method is used to measure the dilutive impact of stock
+options. The following table details the weighted-average dilutive
+and anti-dilutive securities related to stock options and RSUs for the years
+presented: 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+Dilutive 
+1,441,556 
+1,978,577 
+2,293,768 
+Anti-dilutive 
+- 
+- 
+- 
+Prior to
+the conversion of the Company’s 5.75% Senior Convertible Notes on
+March 16, 2007, potentially dilutive shares associated with this
+instrument were accounted for using the if-converted method for the
+determination of diluted earnings per share. Adjusted net income used
+in the if-converted method was derived by adding interest expense paid on the
+5.75% Senior Convertible Notes back to net income and then adjusting for
+nondiscretionary items that are based on net income and would have changed had
+the 5.75% Senior Convertible Notes been converted at the beginning of the
+period. The 5.75% Senior Convertible Notes were called for
+redemption by the Company on March 16, 2007, and all of the note
+holders elected to convert the notes to shares of the Company’s common
+stock. The Company issued 7.7 million common shares in
+connection with the conversion of the 5.75% Senior Convertible
+Notes. Upon conversion, these shares were included in the calculation
+of weighted-average common shares outstanding. The diluted earnings
+per share calculation for the year ended December 31, 2007, was adjusted
+for the conversion and included a time-weighted average of approximately
+1.6 million potentially dilutive shares related to the 5.75% Senior
+Convertible Notes. A total of 7.7 million potentially dilutive shares
+related to the 5.75% Senior Convertible Notes were included in the calculation
+of diluted earnings per share for the years ended December 31, 2006,
+and 2005. 
+The
+Company’s 3.50% Senior Convertible Notes have a net-share settlement right,
+and the treasury stock method is used to measure the potentially dilutive impact
+of shares associated with that conversion feature. The
+3.50% Senior Convertible Notes issued April 4, 2007 have not been
+dilutive for the entire time they have been outstanding and therefore do not
+impact the diluted earnings per share calculation for the period ended
+December 31, 2007. 
+The
+dilutive impact of unvested RSUs and stock options is considered in the detailed
+calculations below. There were no anti-dilutive securities related to
+stock options or RSUs for the years ended December 31, 2005, 2006, and
+2007. 
+F-11
+The
+following table sets forth the calculation of basic and diluted earnings per
+share : 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands, except per share amounts) 
+Net
+income 
+$ 
+189,712 
+$ 
+190,015 
+$ 
+151,936 
+Adjustments
+to net income for dilution: 
+Add:
+Interest expense not incurred if 5.75% Senior Convertible Notes
+converted 
+1,285 
+6,337 
+6,337 
+Less:
+Other adjustments 
+(13 
+) 
+(63 
+) 
+(64 
+) 
+Less:
+Income tax effect of adjustment items 
+(469 
+) 
+(2,237 
+) 
+(2,275 
+) 
+Net
+income adjusted for the effect of dilution 
+$ 
+190,515 
+$ 
+194,052 
+$ 
+155,934 
+Basic
+weighted-average common shares outstanding 
+61,852 
+56,291 
+56,907 
+Add:
+Dilutive effect of stock options and unvested restricted stock
+units 
+1,441 
+1,979 
+2,295 
+Add:
+Dilutive effect of 5.75% Senior Convertible Notes using the
+if-converted method 
+1,557 
+7,692 
+7,692 
+Diluted
+weighted-average common shares outstanding 
+64,850 
+65,962 
+66,894 
+Basic
+earnings per common share: 
+$ 
+3.07 
+$ 
+3.38 
+$ 
+2.67 
+Diluted
+earnings per common share: 
+$ 
+2.94 
+$ 
+2.94 
+$ 
+2.33 
+Stock-Based
+Compensation 
+At
+December 31, 2007, the Company had stock-based employee compensation plans that
+included RSUs and stock options issued to employees and non-employee directors
+as more fully described in Note 7 – Compensation Plans. Stock options
+were last issued in December 2004. Prior to 2006, the Company had
+accounted for stock-based compensation using the intrinsic value recognition and
+measurement principles detailed in Accounting Principles Board Opinion No. 25,
+“Accounting for Stock Issued to Employees” ("APB Opinion No. 25") and related
+interpretations. No stock-based employee compensation expense
+relating to stock options has been reflected in the Company’s accompanying
+consolidated statements of operations for any period presented prior to 2006
+since all options granted under the plans had an exercise price equal to the
+market value of the underlying common stock on the date of grant. The
+Company used the Black-Scholes option valuation model to calculate the
+disclosures required under Statement of Financial Accounting
+Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS
+No. 123”). Beginning January 1, 2006, the Company adopted the
+provisions of Statement of Financial Accounting Standards No. 123(R),
+“Share-Based Payment” (“SFAS No. 123(R)”). This statement
+requires the Company to record expense associated with the fair value of
+stock-based compensation. The total unrecognized compensation expense
+associated with unvested stock options at the date of adoption of this standard
+totaled $2.4 million. The Company elected to use the
+modified-prospective adoption method for the standard and consequently
+recognized additional compensation expense of $1.9 million in 2006 and $437,000
+in 2007, and expects to recognize expense of $17,000 in 2008 related to the
+vesting of these stock options. The Company has recorded compensation
+expense associated with the issuance of RSUs since the plan was adopted in 2004
+and units were first granted. The Company recognizes costs associated
+with these grants based on the estimated fair value of the RSUs as determined at
+the time of the grant. 
+F-12
+The
+following table illustrates the pro forma effect on net income and earnings per
+share if the Company had applied the fair value recognition provisions of SFAS
+No. 123 to stock-based employee compensation prior to the implementation of SFAS
+No. 123(R): 
+For the Year Ended December 31,
+2005 
+(In
+thousands, except per share amounts) 
+Net
+income 
+As
+reported: 
+$ 
+151,936 
+Add: stock-based
+employee compensation expense included in reported net income, net of
+related tax effects 
+4,453 
+Less: stock-based
+employee compensation expense determined under fair value method for all
+awards, net of related income tax effects 
+(6,282 
+) 
+Pro
+forma 
+$ 
+150,107 
+Pro
+forma basic earnings per share 
+$ 
+2.64 
+Pro
+forma diluted earnings per share 
+$ 
+2.30 
+For
+purposes of pro forma disclosures, the estimated fair values of the options and
+employee stock purchase plan grants are amortized to expense over the options’
+vesting periods. The effects of applying SFAS No. 123 in the pro
+forma disclosure are not necessarily indicative of actual future
+amounts. 
+Recently
+Issued Accounting Standards 
+In
+December 2007 the FASB issued Statement of Financial Accounting Standards No.
+141(R), “Business Combinations” (“SFAS No. 141(R)”), which requires the
+acquiring entity in a business combination to recognize and measure all assets
+and liabilities assumed in the transaction and any non-controlling interest in
+the acquiree at fair value as of the acquisition date. SFAS No.
+141(R) also establishes guidance for the measurement of the acquirer shares
+issued in consideration for a business combination, the recognition of
+contingent consideration, the accounting treatment for pre-acquisition gain and
+loss contingencies, the treatment of acquisition related transaction costs, and
+the recognition of changes in the acquirer's income tax valuation allowance and
+deferred taxes. SFAS No. 141(R) is effective for fiscal years
+beginning after December 15, 2008, and is to be applied prospectively as of the
+beginning of the fiscal year in which the statement is applied. Early
+adoption is not permitted. SFAS No. 141(R) will be effective for the Company
+beginning with the 2009 fiscal year. The Company is currently
+evaluating the impact of SFAS No. 141(R) on its accompanying consolidated
+financial statements when effective, but the nature and magnitude of the
+specific effects will depend upon the nature, terms, and size of the
+acquisitions the Company consummates after the effective date. 
+In
+December 2007 the FASB issued Statement of Financial Accounting Standards No.
+160, “Noncontrolling Interests in Consolidated Financial Statements – an
+amendment of ARB 51” (“SFAS No. 160”), which establishes accounting and
+reporting standards that require noncontrolling interests to be reported as a
+component of equity. SFAS No. 160 also requires that changes in a
+parent's ownership interest while the parent retains its controlling interest be
+accounted for as equity transactions and that any retained noncontrolling equity
+investment upon the deconsolidation of a subsidiary be initially measured at
+fair value. SFAS No. 160 is effective for fiscal years beginning
+after December 15, 2008, and is to be applied prospectively as of the beginning
+of the fiscal year in which the statement is applied. The Company is
+required to adopt SFAS No. 160 beginning with the 2009 fiscal
+year. The Company is currently evaluating the potential impact, if
+any, of the adoption of SFAS No. 160 on its accompanying consolidated financial
+statements when effective. 
+F-13
+In
+February 2007 the FASB issued Statement of Financial Accounting Standards No.
+159, “The Fair Value Option for Financial Assets and Financial Liabilities”
+(“SFAS No. 159”), which expands the use of fair value accounting but does not
+affect existing standards that require assets or liabilities to be carried at
+fair value. SFAS No. 159 allows entities to choose, at specified
+election dates, to use fair value to measure eligible financial assets and
+liabilities that are not otherwise required to be measured at fair value. If a
+company elects the fair value option for an eligible item, changes in that
+item's fair value in subsequent reporting periods must be recognized in current
+earnings. SFAS No. 159 also establishes presentation and disclosure
+requirements designed to draw comparisons between entities that elect different
+measurement attributes for similar assets and liabilities. If
+elected, SFAS No. 159 is effective for fiscal years beginning after November 15,
+2007. SFAS No. 159 will be effective for the Company beginning with
+the 2008 fiscal year. The Company did not elect the fair value
+option. There is no impact on the Company’s consolidated financial
+statements. 
+In
+September 2006 the FASB issued Statement of Financial Accounting Standards No.
+157, “Fair Value Measurements” (“SFAS No. 157”), which defines fair value,
+establishes a framework for measuring fair value, and expands disclosures about
+fair value measurements. The provisions of SFAS No. 157 will be
+effective as of the beginning of the Company’s 2008 fiscal year. The
+adoption of SFAS No. 157 has no impact on the Company’s consolidated financial
+statements, however, it will require changes in certain
+disclosures. 
+Comprehensive
+Income 
+Comprehensive
+income consists of net income, the unrealized gain or loss for the effective
+portion of derivative instruments classified as cash flow hedges, and the
+accrued pension benefit obligation in excess of plan
+assets. Comprehensive income is presented net of income taxes in the
+accompanying consolidated statements of stockholders’ equity and comprehensive
+income. 
+The
+changes in the balances of components comprising other comprehensive income and
+loss are presented in the following table: 
+Pension 
+Other 
+Derivative 
+Liability 
+Comprehensive 
+Instruments 
+Adjustment 
+Income
+(Loss) 
+(In
+thousands) 
+For
+the period ending December 31, 2005 
+Before
+tax income (loss) 
+$ 
+(92,097 
+) 
+$ 
+455 
+$ 
+(91,642 
+) 
+Tax
+benefit (expense) 
+34,941 
+(172 
+) 
+34,769 
+After
+deferred tax income (loss) 
+$ 
+(57,156 
+) 
+$ 
+283 
+$ 
+(56,873 
+) 
+For
+the period ending December 31, 2006 
+Before
+tax income (loss) 
+$ 
+111,437 
+$ 
+(290 
+) 
+$ 
+111,147 
+Tax benefit
+(expense) 
+(42,459 
+) 
+110 
+(42,349 
+) 
+After
+deferred tax income (loss) 
+$ 
+68,978 
+$ 
+(180 
+) 
+$ 
+68,798 
+For
+the period ending December 31, 2007 
+Before
+tax income (loss) 
+$ 
+(272,655 
+) 
+$ 
+119 
+$ 
+(272,536 
+) 
+Tax
+benefit (expense) 
+102,688 
+(49 
+) 
+102,639 
+After
+deferred tax income (loss) 
+$ 
+(169,967 
+) 
+$ 
+70 
+$ 
+(169,897 
+) 
+F-14 
+Major
+Customers 
+During
+2007 and 2006 no customer individually accounted for more than ten percent of
+the Company’s total oil and gas production revenue. During 2005 one
+customer individually accounted for 13 percent of the Company’s total oil and
+gas production revenue. 
+Industry
+Segment and Geographic Information 
+The
+Company operates in one industry segment, which is the exploration,
+exploitation, development, acquisition, and production of natural gas and crude
+oil. All of the Company’s operations are conducted in the continental
+United States and the Gulf of Mexico. Consequently, the Company
+currently reports as a single industry segment. The Company’s gas
+marketing department provides mostly internal services, acting as a first
+purchaser of natural gas and natural gas liquids produced by the Company and as
+such the majority of the Company’s marketing activity is eliminated in
+consolidation. The small amount of third-party income these
+operations generate is not material to the Company’s financial position, and
+segmentation of such net income would not provide a better understanding of the
+Company’s performance. However, gross revenue and expense related to
+gas marketing operations are presented discreetly in the accompanying
+consolidated statements of operations. 
+Intangible
+Assets 
+As of
+December 31, 2007, and 2006, the Company’s accompanying consolidated balance
+sheets include $2.4 million and $3.4 million, respectively, of intangible
+assets. These assets arise from acquired oil and gas sale contracts
+with favorable pricing terms. They do not qualify as derivatives or
+hedges under SFAS No. 133. Intangible assets of the Company are
+amortized using the units-of-production method and are evaluated for impairment
+if such indicators arise. Intangible assets are included in other
+noncurrent assets on the Company’s accompanying consolidated balance
+sheets. 
+Goodwill 
+Goodwill
+is measured as the excess of the acquisition costs over the sum of the amounts
+assigned to the identifiable assets acquired less liabilities
+assumed. Goodwill was recorded as a result of the acquisition of
+Agate Petroleum, Inc. in January 2005. Goodwill is reviewed for
+impairment annually or more frequently if impairment indicators
+arise. The goodwill review is conducted at the reporting unit
+level. A reporting unit is defined as the oil and gas properties in a
+region. 
+Off – Balance Sheet
+Arrangements 
+As part
+of its ongoing business, the Company has not participated in transactions that
+generate relationships with unconsolidated entities or financial partnerships,
+such as entities often referred to as structured finance or special purpose
+entities ("SPEs"), which would have been established for the purpose of
+facilitating off-balance sheet arrangements or other contractually narrow or
+limited purposes. As of and up to December 31, 2007, the Company
+has not been involved in any unconsolidated SPE transactions. 
+The
+Company evaluates its transactions to determine if any variable interest
+entities exist. If it is determined that St. Mary is the primary
+beneficiary of a variable interest entity, that entity is consolidated into
+St. Mary. 
+F-15
+Note
+2 – Accounts Receivable and Accounts Payable and Accrued Expenses 
+Accounts
+receivable are comprised of the following: 
+As
+of December 31, 
+2007 
+2006 
+(In
+thousands) 
+Accrued
+oil and gas sales 
+$ 
+115,534 
+$ 
+95,036 
+Due
+from joint interest owners 
+37,860 
+33,309 
+Other 
+5,755 
+14,376 
+Total
+accounts receivable 
+$ 
+159,149 
+$ 
+142,721 
+Accounts
+payable and accrued expenses are comprised of the following: 
+As
+of December 31, 
+2007 
+2006 
+(In
+thousands) 
+Accrued
+drilling costs 
+$ 
+112,481 
+$ 
+68,326 
+Revenue
+payable 
+37,048 
+27,591 
+Accrued
+lease operating expense 
+14,604 
+11,153 
+Accrued
+taxes 
+5,042 
+2,358 
+Accrued
+interest 
+3,590 
+2,846 
+Accrued
+compensation 
+17,887 
+10,323 
+Trade
+payables 
+28,187 
+37,152 
+Accrued
+payments to hedge contract counterparties 
+9,640 
+665 
+Plug
+and abandonment liability on offshore platform related to Hurricane
+Rita 
+3,108 
+- 
+Accrued
+marketed gas system expense 
+13,520 
+6,396 
+Other 
+9,811 
+5,024 
+Total
+account payable and accrued expenses 
+$ 
+254,918 
+$ 
+171,834 
+Note
+3 – Acquisitions, Divestitures, and Assets Held for Sale 
+Rockford
+Acquisition 
+On
+October 4, 2007, the Company completed the purchase of certain oil and
+gas properties in the Gold River project area targeting the Olmos shallow
+gas formation located primarily in Webb and Dimmit Counties,
+Texas. The assets were purchased from Rockford Energy Partners II,
+LLC for $148.9 million of cash, which is net of normal purchase price
+adjustments of $2.1 million. The acquisition was funded with
+cash on hand and borrowings under the Company’s existing revolving credit
+facility. The Company allocated $127.2 million to proved oil and gas
+properties, $23.1 million to unproved oil and gas properties, and a net $292,000
+to other assets. The Company also recorded $1.7 million in asset
+retirement obligation liability associated with the acquired properties. This
+property acquisition is adjacent to the recently acquired Catarina project area
+discussed below. The Company has hedged the equivalent of the first
+three years of natural gas production and the first two years of associated
+natural gas liquids production related to this acquisition. 
+F-16
+Variable
+Interest Entity 
+The
+acquisition of the properties in the Gold River project area was structured
+to qualify as the first step of a reverse like-kind exchange under Section 1031
+of the Internal Revenue Code of 1986, as amended ("the IRC"), and I.R.S. Revenue
+Procedure 2000-37. Prior to closing on the Rockford acquisition, the
+Company assigned all of its rights and duties under the purchase and sale
+agreement to NBF Reverse Exchange, LLC, an indirect wholly-owned subsidiary of
+Comerica Incorporated, which further assigned all of its rights and duties
+under the purchase and sale agreement to St. Mary Land & Exploration
+Acquisition, LLC (“SMLEA, LLC”), a company unaffiliated with St.
+Mary. The Gold River assets were acquired by NBF Reverse
+Exchange, LLC as an exchange accommodation
+titleholder. SMLEA, LLC held the assets pursuant to a qualified
+exchange accommodation agreement until the second step of the like-kind exchange
+was completed in conjunction with the divestiture of certain non-core oil and
+gas properties discussed below under Assets Held for
+Sale . As of the date of closing on October 4, 2007,
+the assets held by SMLEA, LLC, were leased by St. Mary under a triple net
+lease whereby St. Mary enjoyed the benefits and risks of all revenues and costs
+attributed to the properties. The Gold River assets were managed
+by St. Mary under the terms of a management agreement with
+SMLEA, LLC. 
+In
+connection with the reverse like-kind exchange described above, St. Mary loaned
+an amount equal to the purchase price of the assets to
+SMLEA, LLC. Based on the provisions of FASB Interpretation
+No. 46(R), “ Consolidation
+of Variable Interest Entities ”, the Company determined that
+SMLEA, LLC is a variable interest entity for which St. Mary is the primary
+beneficiary. Accordingly, SMLEA, LLC was consolidated into St.
+Mary subsequent to the completion of the purchase of oil and gas properties on
+October 4, 2007. As a result of the consolidation, St. Mary
+recognized all oil and gas reserves and production as well as all revenues and
+expenses attributed to the Rockford acquisition beginning on
+October 4, 2007. 
+Catarina
+Acquisition 
+On
+June 1, 2007, the Company acquired oil and gas properties located
+primarily in the Catarina project area in Webb County, Texas in exchange for
+$30.0 million of cash. The Company allocated $29.9 million to
+proved oil and gas properties, $535,000 to unproved oil and gas properties, and
+a net $215,000 to other assets. The Company also recorded $623,000 in
+asset retirement obligation liability associated with the acquired
+properties. The acquisition was funded with cash on hand and
+borrowings under the Company’s existing credit facility. 
+Permian
+Basin Acquisition 
+On
+December 14, 2006, the Company acquired oil and gas properties in the
+Permian Basin in West Texas from private parties in exchange for
+$243.1 million of cash, which is net of normal purchase price adjustments
+of approximately $4.3 million. The Company recorded $199.1
+million to proved oil and gas properties, $41.5 million to unproved oil and gas
+properties, $3.0 million to intangible assets, a net $326,000 to other
+assets, and $859,000 to asset retirement obligation liability. The
+Company allocated the purchase price based on the estimated fair value of the
+assets and liabilities acquired. The acquisition was accounted for
+using the purchase method and was funded with cash on hand and borrowings under
+the Company’s credit facility. 
+Richland
+County, Montana Acquisition 
+On
+May 15, 2006, the Company closed on a transaction whereby it exchanged
+oil and gas properties located in the Uinta Basin of Utah for oil and gas
+properties located in Richland County, Montana. The transaction was
+structured to qualify as a like-kind exchange under Section 1031 of the Internal
+Revenue Code of 1986, as amended, and I.R.S. Revenue Procedure
+2000-37. For financial reporting purposes, the transaction is
+considered a non-monetary exchange and was accounted for at estimated fair
+value. The exchange of properties resulted in recognition of
+approximately $6.4 million of gain. 
+F-17
+Assets
+Held for Sale 
+In
+December 2007 St. Mary reached an agreement for the sale of its previously
+announced divestiture package, and on January 31, 2008, the Company completed
+the divestiture of certain non-strategic oil and gas properties located
+primarily in the Rocky Mountain and Mid-Continent regions to Abraxas Petroleum
+Corporation and Abraxas Operating, LLC. The cash received at closing
+before commission costs was $131.1 million. The final sale price
+is subject to normal post-closing adjustments and settlements and is expected to
+be finalized during the second quarter of 2008. The transaction has
+an effective date of December 1, 2007. The accompanying
+consolidated balance sheet as of December 31, 2007, presents the $76.9
+million assets held for sale, net of accumulated depletion, depreciation and
+amortization. The corresponding asset retirement obligation of
+$8.7 million and a $10.0 million deposit associated with oil and gas
+properties held for sale are also separately presented. Under FASB
+Emerging Issues Task Force Issue No. 03-13, the Company determined that these
+sales do not qualify for discontinued operations accounting. 
+Note
+4 – Income Taxes 
+The
+provision for income taxes consists of the following: 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Current
+taxes: 
+Federal 
+$ 
+15,136 
+$ 
+28,557 
+$ 
+75,848 
+State 
+2,459 
+1,917 
+4,906 
+Deferred
+taxes 
+92,955 
+74,832 
+5,547 
+Total
+income tax expense 
+$ 
+110,550 
+$ 
+105,306 
+$ 
+86,301 
+F-18 
+As a
+result of the exercise of stock options, the Company was able to reduce its
+income tax payable in each year presented. The tax benefit to the
+Company of stock option exercises was $9.9 million in 2007, $16.1 million in
+2006, and $6.0 million in 2005. 
+The
+components of the net deferred tax liability are as follows: 
+December
+31, 
+2007 
+2006 
+(In
+thousands) 
+Deferred
+tax liabilities: 
+Oil
+and gas properties 
+$ 
+412,669 
+$ 
+299,082 
+Unrealized
+derivative asset 
+- 
+17,184 
+Interest
+on Senior Convertible Notes 
+2,596 
+6,925 
+Other 
+1,429 
+59 
+Total
+deferred tax liabilities 
+416,694 
+323,250 
+Deferred
+tax assets: 
+Net
+Profits Plan liability 
+79,552 
+59,537 
+Unrealized
+derivative liability 
+93,829 
+8,174 
+Stock
+compensation 
+8,849 
+8,104 
+State
+tax net operating loss carryforward or carryback 
+6,808 
+4,589 
+State
+and federal income tax benefit 
+2,939 
+2,285 
+Other
+long-term liabilities 
+1,724 
+2,026 
+Employee
+benefits and other 
+1,543 
+1,391 
+Deferred
+capital loss 
+- 
+619 
+Other 
+614 
+- 
+Total
+deferred tax assets 
+195,858 
+86,725 
+Valuation
+allowance 
+(3,556 
+) 
+(2,660 
+) 
+Net
+deferred tax assets 
+192,302 
+84,065 
+Total
+net deferred tax liabilities 
+224,392 
+239,185 
+Less:
+current deferred income tax liabilities 
+(1,425 
+) 
+(17,188 
+) 
+Add:
+current deferred income tax assets 
+34,636 
+2,521 
+Non-current
+net deferred tax liabilities 
+$ 
+257,603 
+$ 
+224,518 
+Current
+federal income tax refundable 
+$ 
+933 
+$ 
+7,293 
+Current
+state income tax refundable (payable) 
+$ 
+(105 
+) 
+$ 
+391 
+At
+December 31, 2007, the Company had estimated state net operating loss
+carryforwards of approximately $162.5 million that expire between 2008 and
+2027 and state tax credits of $145,000 that expire between 2008 and
+2016. A portion of the Company’s valuation allowance relates to state
+net operating loss carryforwards, state tax credits, and state and federal
+income tax benefit amounts that the Company anticipates will expire before they
+can be utilized. The Company has concluded that permanent items
+included in the calculation of income tax for certain states may impact its
+ability to deduct net operating losses and realize federal income tax deduction
+benefits of those states and has adjusted its valuation allowances
+accordingly. The remaining portion of the valuation allowance relates
+to the Net Profits Plan liability and reflects an estimate of future executive
+compensation that may not be deductible for income tax purposes when future cash
+payments occur under the plan. 
+F-19
+Federal
+income tax expense differs from the amount that would be provided by applying
+the statutory U.S. Federal income tax rate to income before income taxes
+primarily due to the effect of state income taxes, percentage depletion, the
+estimated effect of the domestic production activities deduction, and other
+permanent differences, as follows: 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Federal
+statutory taxes 
+$ 
+105,092 
+$ 
+103,504 
+$ 
+83,307 
+Increase
+(reduction) in taxes resulting from: 
+State
+taxes (net of federal benefit) 
+5,111 
+2,081 
+4,185 
+Statutory
+depletion 
+(407 
+) 
+(315 
+) 
+(224 
+) 
+Domestic
+production activities deduction 
+(384 
+) 
+(287 
+) 
+(1,717 
+) 
+Other 
+242 
+235 
+(108 
+) 
+Change
+in valuation allowance 
+896 
+88 
+858 
+Income
+tax expense from operations 
+$ 
+110,550 
+$ 
+105,306 
+$ 
+86,301 
+Acquisitions,
+drilling, and basis differentials impacting the prices received for crude oil
+and natural gas, affect the apportionment of taxable income to the states where
+the Company owns properties. As these factors change, the Company’s
+blended state income tax rate changes. This change applied to the
+Company’s total temporary differences will impact the total income tax reported
+in the current year and is reflected in state taxes in the table
+above. Items affecting state apportionment factors are evaluated upon
+completion of the prior year income tax return and after significant
+acquisitions are closed during the current year. 
+The
+Company and its subsidiaries file income tax returns in the U.S. federal
+jurisdiction and in various states. With few exceptions, the Company
+is no longer subject to U.S. federal or state income tax examinations by these
+tax authorities for years before and including 2003. The Internal
+Revenue Service completed audits for the 2000, 2002, and 2003 tax years during
+the quarter ended March 31, 2007. There was no change to
+the provision for income tax as a result of these examinations. 
+In the
+third quarter of 2007 the Company received a refund of income tax and interest
+of $3.1 million from a carryback of net operating losses to the 2000 tax
+year. An additional $1.0 million due to the Company for income
+tax refunds and accrued interest resulting from a carry over of minimum tax
+credits to the 2003 tax year was received in January 2008. These
+amounts have been previously recognized by the Company. 
+The
+Company adopted the provisions of FASB Interpretation No. 48, "Accounting for
+Uncertainty in Income Taxes" (“FIN No. 48”), on
+January 1, 2007. There was no financial statement
+adjustment required as a result of adoption. At adoption, the Company
+had a long-term liability for unrecognized tax benefit of $1.0 million and
+accumulated interest liability of $92,000. The entire amount of
+unrecognized tax benefit would affect the Company’s effective tax rate if
+recognized. Interest expense in the 2007 accompanying consolidated
+statements of operations includes a nominal $4,000 associated with income
+tax. Penalties associated with income tax are recorded in general and
+administrative expense in the accompanying consolidated statements of
+operations. There were no penalties associated with income tax
+recorded for the year ended December 31, 2007. 
+F-20
+The total
+amount recorded for unrecognized tax benefits for the year ended
+December 31, 2007, is presented below (in thousands): 
+Balance
+at January 1, 2007 
+$ 
+1,112 
+Additions
+for tax positions of prior years 
+233 
+Reductions
+for lapse of statute of limitations 
+(388 
+) 
+Balance
+at December 31, 2007 
+$ 
+957 
+Note
+5 – Long-term Debt 
+Revolving
+Credit Facility 
+The
+Company’s revolving credit facility specifies a maximum loan amount of $500
+million and has a maturity date of
+April 7, 2010. Borrowings under the facility are secured by
+a pledge in favor of the lenders of collateral that includes the majority of the
+Company’s oil and gas properties and the common stock of the material
+subsidiaries of the Company. The borrowing base under the credit
+facility as authorized by the bank group as of the date of this filing is $1.25
+billion and is subject to regular semi-annual redeterminations. The
+borrowing base redetermination process considers the value of St. Mary’s oil and
+gas properties and other assets, as determined by the bank
+syndicate. The Company has elected an aggregate commitment amount of
+$500 million under the credit facility. The Company must comply
+with certain financial and non-financial covenants under its existing credit
+facility. The Company is in compliance with all
+covenants associated with the credit facility. The payment of
+dividends is subject to covenants under the Company’s existing credit facility,
+including the requirement that the Company maintain certain levels of
+stockholders’ equity and the limitation of the Company’s annual dividend rate to
+no more than $0.25 per share per year. Interest and commitment fees
+are accrued based on the borrowing base utilization percentage table
+below. Euro-dollar loans accrue interest at London Interbank Offered
+Rate (“LIBOR”) plus the applicable margin from the utilization table, and
+Alternative Base Rate (“ABR”) loans accrue interest at Prime plus the applicable
+margin from the utilization table. Commitment fees are accrued on the
+unused portion of the aggregate commitment amount and are included in interest
+expense in the accompanying consolidated statements of operations. 
+Borrowing
+base 
+utilization
+percentage 
+<50% 
+> 50%<75% 
+> 75%<90% 
+> 90% 
+Euro-dollar
+loans 
+1.000% 
+1.250% 
+1.500% 
+1.750% 
+ABR
+loans 
+0.000% 
+0.000% 
+0.250% 
+0.500% 
+Commitment
+fee rate 
+0.250% 
+0.300% 
+0.375% 
+0.375% 
+The
+Company had $285.0 million and $180.0 million in outstanding loans under its
+revolving credit agreement on December 31, 2007, and February 15, 2008,
+respectively. 
+5.75%
+Senior Convertible Notes Due 2022 
+The
+Company called for redemption of its 5.75% Senior Convertible Notes on
+March 16, 2007. The call for redemption resulted in the
+note holders electing to convert the notes to common stock in accordance with
+the conversion provision in the original indenture. The
+5.75% Convertible Note holders converted all $100 million of the
+5.75% Senior Convertible Notes to common shares at a conversion price of
+$13.00 per share. The Company issued 7.7 million
+common shares in connection with the conversion. 
+3.50%
+Senior Convertible Notes Due 2027 
+On
+April 4, 2007, the Company issued $287.5 million aggregate
+principal amount of 3.50% Senior Convertible Notes. The
+3.50% Senior Convertible Notes mature on April 1, 2027, unless
+earlier converted, redeemed, or purchased by the Company. The 3.50% Senior
+Convertible Notes are unsecured senior obligations 
+F-21
+and rank
+equal in right of payment with all of the Company’s existing and any future
+unsecured senior debt and senior in right of payment to any future subordinated
+debt. 
+Holders
+may convert their notes based on a conversion rate of 18.3757 shares of the
+Company’s common stock per $1,000 principal amount of the 3.50% Senior
+Convertible Notes (which is equal to an initial conversion price of
+approximately $54.42 per share), subject to adjustment, contingent upon and only
+under the following circumstances: (1) if the closing price of the
+Company's common stock reaches specified thresholds or the trading price of the
+notes falls below specified thresholds, (2) if the notes are called for
+redemption, (3) if specified distributions to holders of the Company’s
+common stock are made or specified corporate transactions occur, (4) if
+a fundamental change occurs, or (5) during the ten trading days
+prior to, but excluding, the maturity date. The notes and underlying
+shares have been registered under a shelf registration statement. If
+the Company becomes involved in a material transaction or corporate development,
+it may suspend trading of the 3.50% Senior Convertible Notes under the
+prospectus. In the event the suspension period exceeds 45 days
+within any three-month period or 90 days within any twelve-month period,
+the Company will be required to pay additional interest to all holders of the
+3.50% Senior Convertible Notes, not to exceed a rate per annum of
+0.50 percent of the issue price of the 3.50% Senior Convertible Notes;
+provided that no such additional interest shall accrue after
+April 4, 2009. 
+Upon
+conversion of the 3.50% Senior Convertible Notes, holders will receive cash
+or common stock, or any combination thereof as elected by the
+Company. At any time prior to the maturity date of the notes, the
+Company has the option to unilaterally and irrevocably elect to settle its
+obligations upon conversion of the notes in cash and, if applicable, shares of
+common stock. If the Company makes this election, then, for each
+$1,000 principal amount of notes converted, the Company will pay the following
+to holders in lieu of shares of common stock: (1) an amount in cash equal
+to the lesser of (i) $1,000 or (ii) the conversion value determined in
+the manner set forth in the indenture for the 3.50% Senior Convertible
+Notes, and (2) if the conversion value exceeds $1,000, the Company will
+also deliver, at its election, cash or common stock or a combination of cash and
+common stock with respect to the remaining value deliverable upon
+conversion. Currently, it is the Company’s intention to net share
+settle the 3.50% Senior Convertible Notes. However, the Company
+has not made this a formal legal irrevocable election and thereby reserves the
+right to settle the 3.50% Senior Convertible Notes in any manner allowed
+under the offering memorandum as business conditions warrant. 
+If a
+holder elects to convert its notes in connection with certain events that
+constitute a change of control before April 1, 2012, the Company will
+pay, to the extent described in the related indenture, a make-whole premium by
+increasing the conversion rate applicable to the 3.50% Senior Convertible
+Notes. In addition, the Company will pay contingent interest in cash,
+commencing with any six-month period beginning on or after
+April 1, 2012, if the average trading price of a note for the five
+trading days ending on the third trading day immediately preceding the first day
+of the relevant six-month period equals 120 percent or more of the
+principal amount of the 3.50% Senior Convertible Notes. 
+On or
+after April 6, 2012, the Company may redeem for cash all or a portion
+of the 3.50% Senior Convertible Notes at a redemption price equal to
+100 percent of the principal amount of the notes to be redeemed plus
+accrued and unpaid interest, if any, up to but excluding, the applicable
+redemption date. Holders of the 3.50% Senior Convertible Notes
+may require the Company to purchase all or a portion of their notes on each of
+April 1, 2012, April 1, 2017, and April 1, 2022,
+at a purchase price equal to 100 percent of the principal amount of the
+notes to be repurchased plus accrued and unpaid interest, if any, up to but
+excluding the applicable purchase date. On April 1, 2012,
+the Company may pay the purchase price in cash, in shares of common stock, or in
+any combination of cash and common stock. On April 1, 2017,
+and April 1, 2022, the Company must pay the purchase price in cash.
+Based on the market price of the 3.50% Senior Convertible Notes, the estimated
+fair value of the notes was approximately $296 million as of December 31,
+2007. 
+In
+August 2007 the FASB proposed FASB Staff Position APB 14-a, “Accounting for
+Convertible Debt Instruments That May Be Settled in Cash Upon Conversion
+(including Partial Cash Settlement)” (“FSP APB 14-a”). FSP APB 14-a
+proposes that the accounting treatment for certain convertible debt instruments
+that may be settled in cash, shares of common stock, or any portion thereof at
+the election of the issuing company be accounted for utilizing a bifurcation
+model under which the value of the debt instrument would be determined
+F-22
+without regard to the conversion feature. As of the date
+of this filing, FSP APB 14-a remains a proposed FASB staff position under
+redeliberation.
+Weighted-Average
+Interest Rate Paid and Capitalized Interest 
+The
+weighted-average interest rate paid in 2007, 2006, and 2005 was 5.4 percent, 7.6
+percent, and 7.1 percent, respectively, including commitment fees paid on
+the unused portion of the credit facility aggregate commitment, amortization of
+deferred financing costs, amortization of the contingent interest embedded
+derivative associated with the 5.75% Senior Convertible Notes, and the effect of
+interest rate swaps. The average outstanding loan balance in
+2007 grew at a faster rate than the aforementioned items resulting in a lower
+weighted-average interest rate. Capitalized interest costs for the
+Company for the years ended December 31, 2007, 2006 and 2005 were $5.4 million,
+$3.5 million, and $1.9 million, respectively. 
+Note
+6 – Commitments and Contingencies 
+The
+Company has entered into various operating leases, some of which include
+drilling rig contracts of, approximately $25.5 million, office space leases of
+approximately $14.1 million, and compressor contracts of approximately $2.0
+million. The annual minimum lease payments for the next five years
+and thereafter are presented below: 
+Years
+Ending December 31, 
+(In
+thousands) 
+2008 
+$ 
+29,119 
+2009 
+5,882 
+2010 
+3,747 
+2011 
+3,352 
+2012 
+1,335 
+Thereafter 
+814 
+Total 
+$ 
+44,249 
+The
+Company leases office space under various operating leases with terms extending
+as far as May 31, 2014. Rent expense, net of sublease
+income, was $1.9 million, $1.5 million, and $1.3 million in 2007,
+2006, and 2005, respectively. The Company also leases office
+equipment under various operating leases. The Company has a
+non-cancelable sublease through May 2012, of approximately $816,000, with
+payments of $185,000 per year through 2011 and $77,000 in 2012. 
+The
+Company is subject to litigation and claims that have arisen in the ordinary
+course of business. The Company accrues for such items when a
+liability is both probable and the amount can be reasonably
+estimated. In the opinion of management, the results of such
+litigation and claims will not have a material effect on the results of
+operations, the financial position, or cash flows of the
+Company. Management believes it has sufficiently provided for such
+items to the extent necessary in the consolidated balance sheets. 
+Note
+7 – Compensation Plans 
+Cash
+Bonus Plan 
+The
+Company has a cash bonus plan under which the Company can award participants a
+cash bonus of up to 50 percent of their aggregate base
+salary. Any awards under the cash bonus plan are based on Company and
+regional performance, and then are further refined by individual
+performance. The Company accrues cash bonus expense related to the
+current year’s performance. Included in the general and
+administrative and exploration expense line items in the accompanying
+consolidated statements of operations are $3.6 million, $1.9 million,
+and $7.4 million of cash bonus expense related to the specific performance
+year for the years ended December 31, 2007, 2006, and 2005,
+respectively. 
+F-23 
+Net
+Profits Plan 
+Under the
+Company’s Net Profits Plan, all oil and gas wells that are completed or acquired
+during a year are designated within a specific pool. Key employees
+recommended by senior management and designated as participants by the Company’s
+Compensation Committee of the Board of Directors and employed by the Company on
+the last day of that year become entitled to payments under the Net Profits Plan
+after the Company has received net cash flows returning 100 percent of all
+costs associated with that pool. Thereafter, ten percent of
+future net cash flows generated by the pool are allocated among the participants
+and distributed at least annually. The portion of net cash flows from
+the pool to be allocated among the participants increases to 20 percent
+after the Company has recovered 200 percent of the total costs for the
+pool, including payments made under the Net Profits Plan at the
+ten percent level. The Net Profits Plan has been in place
+since 1991. Pool years prior to and including 2005 are fully
+vested. The 2006 and 2007 Pool years carry a vesting period of three
+years, whereby one-third is vested at the end of the year for which
+participation is designated and one-third vests on each of the following two
+anniversary dates. The 2006 and 2007 Pool years include a cap whereby
+the maximum benefit to full participants from a particular year’s pool is
+limited to 300 percent of a participating individual’s adjusted base salary
+paid during the year to which the pool relates. In December 2007 the
+Board approved a restructuring of the Company’s incentive compensation
+programs. The change in the incentive compensation structure is
+designed to replace the current programs involving the grant of RSUs and the
+grant of participation interests in the Net Profits Plan with a single long-term
+incentive program utilizing performance shares. As a result, the 2007
+Net Profits Plan pool will be the last pool established by the Company. 
+The
+Company records the estimated fair value of the long-term liability for
+estimated future payments under the Net Profits Plan based on the discounted
+value of estimated future payments associated with each individual
+pool. The calculation of this liability is a significant management
+estimate. Historically and for a predominate number of the pools, a
+discount rate of 15 percent was used to calculate this liability and is
+intended to represent the best estimate of the present value of expected future
+payments under the Net Profits Plan. During the fourth quarter of
+2007, the Company adjusted the discount rate used to calculate the present value
+of future payments from a base rate of 15 percent to 12 percent. The
+decrease in the discount rate to 12 percent was based on experience gained
+from the divestiture marketing process, an overall sense of the valuation of oil
+and gas assets and an assessment of the current market for proved oil and gas
+reserves. 
+The
+Company’s estimate of its liability is highly dependent on the price and cost
+assumptions, as well as the discount rates used in the
+calculations. The commodity price assumptions are formulated by
+applying a price that is derived from a rolling average of actual prices
+realized over the prior 24 months together with adjusted NYMEX strip prices
+for the ensuing 12 months for a total of 36 months of
+data. This average is adjusted to include the effect of hedge prices
+for the percentage of forecasted production hedged in the relevant
+period. The forecasted non-cash expense associated with this
+significant management estimate is highly volatile from period to period due to
+fluctuations that occur in the crude oil and natural gas commodity
+markets. Higher commodity prices experienced in recent years have
+moved more pools into payout status. The Company continually
+evaluates the assumptions used in this calculation in order to include the
+current market environment for oil and gas prices, costs, discount rates, and
+overall market conditions. 
+No
+published market quotes exist on which to base the Company’s estimate of fair
+value of the Net Profits Plan. As such, it is entirely based on
+management estimates which are described within this footnote. While
+some inputs to the Company’s calculation to estimate the fair value of the Net
+Profits Plan’s future payments are from published sources, others are derived
+from the Company’s own calculations and estimates, such as the approximated
+discount rate and the expected future cash flows. 
+F-24
+The
+following table presents the changes in the estimated future liability
+attributable to the Net Profits Plan. These amounts relate to the
+realized results for the years presented from oil and gas operations for the
+properties associated with the respective pools that have achieved payout
+status. 
+As
+of December 31, 
+2007 
+2006 
+(In
+thousands) 
+Liability
+balance for Net Profits Plan as of the beginning of the
+period 
+$ 
+160,583 
+$ 
+136,824 
+Increase
+in liability 
+82,734 
+49,900 
+Reduction
+in liability for cash payments made or accrued and recognized as
+compensation expense 
+(31,911 
+) 
+(26,141 
+) 
+Liability
+balance for Net Profits Plan as of the end of the
+period 
+$ 
+211,406 
+$ 
+160,583 
+The
+calculation of the estimated liability for the Net Profits Plan is highly
+sensitive to price estimates and discount rate assumptions. For
+example, if the commodity prices used in the calculation changed by five
+percent, the liability recorded at December 31, 2007, would differ by
+approximately $19 million. A one percentage point decrease in
+the discount rate would result in an increase to the liability of approximately
+$12 million, while a one percentage point increase in the discount
+rate would result in a decrease to the liability of approximately $10
+million. Actual cash payments to be made to participants in future
+periods are dependent on realized actual production, prices, and costs
+associated with the properties in each individual pool of the Net Profits
+Plan. Consequently, actual cash payments will be inherently different
+from the amounts estimated. 
+The
+Company records changes in the present value of estimated future payments under
+the Net Profits Plan as a separate item in the accompanying consolidated
+statements of operations. The change in the estimated liability is
+recorded as a non-cash expense or benefit in the current period. The
+amount recorded as an expense or benefit associated with the change in the
+estimated liability is not allocated to general and administrative expense or
+exploration expense because it is associated with the future net cash flows from
+oil and gas properties in the respective pools rather than results realized in
+the current period. The table below presents the estimated allocation
+of the change in the liability if the Company did allocate the adjustment to
+these specific functional line items based on the current allocation of actual
+distributions being made by the Company. The change in allocation of
+costs to the functional classification relates to the current composition of
+employees as compared to those individuals that have terminated employment with
+the Company. For the years ended December 31, 2007, 2006, and 2005, 22
+percent, 54 percent, and 51 percent, respectively, of payments made under the
+Net Profits Plan were classified as exploration expense in the accompanying
+consolidated statement of operations. As time progresses, less of the
+distribution relates to prospective exploration efforts as more of the
+distributions are made to employees that have terminated employment and thereby
+do not provide any period exploration support. 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+General
+and administrative expense 
+$ 
+41,803 
+$ 
+10,342 
+$ 
+51,419 
+Exploration
+expense 
+9,020 
+13,417 
+54,844 
+Total 
+$ 
+50,823 
+$ 
+23,759 
+$ 
+106,263 
+401(k)
+Plan 
+The
+Company has a defined contribution pension plan (the "401(k) Plan") that is
+subject to the Employee Retirement Income Security Act of 1974. The
+401(k) Plan allows eligible employees to contribute up to 60 percent of
+their base salaries. The Company matches each employee's
+contributions up to six percent of the employee's base 
+F-25
+salary and may make additional contributions at its
+discretion. The Company’s contributions to the 401(k) Plan were
+$1.5 million, $1.2 million, and $966,000 for the years ended
+December 31, 2007, 2006, and 2005, respectively. No
+discretionary contributions were made by the Company to the 401(k) Plan in any
+of these years. 
+Employee
+Stock Purchase Plan 
+Under the
+St. Mary Land & Exploration Company Employee Stock Purchase Plan (“the
+ESPP”), eligible employees may purchase shares of the Company’s common stock
+through payroll deductions of up to 15 percent of eligible
+compensation. The purchase price of the stock is 85 percent of
+the lower of the fair market value of the stock on the first or last day of the
+purchase period, and shares issued under the ESPP are restricted for a period of
+18 months from the date issued. The ESPP is intended to qualify under
+Section 423 of the IRC. The Company has set aside 2,000,000 shares of
+its common stock to be available for issuance under the ESPP, of which 1,599,811
+shares are available for issuance as of December 31, 2007. Shares
+issued under the ESPP totaled 29,534 in 2007, 26,046 in 2006, and 28,447 in
+2005. Total proceeds to the Company for the issuance of these shares
+were $919,000 in 2007, $814,000 in 2006, and $601,000 in 2005. 
+The fair
+value of ESPP shares are measured at the date of grant using the Black-Scholes
+option-pricing model. The fair values of ESPP shares issued were
+estimated using the following weighted-average assumptions: 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+Risk
+free interest rate 
+4.1% 
+5.1% 
+2.5% 
+Dividend
+yield 
+0.3% 
+0.3% 
+0.4% 
+Volatility
+factor of the expected market 
+price
+of the Company's common stock 
+27.19% 
+36.7% 
+36.3% 
+Expected
+life (in years) 
+0.5 
+0.5 
+0.5 
+For the
+ESPP offering periods during 2007 and 2006, the Company expensed $260,000 and
+$243,000, respectively, based on the estimated fair values of grants on the
+respective grant dates. There was no expense related to ESPP shares
+recorded in 2005. 
+Equity
+Incentive Compensation Plan 
+There are
+several components to the equity compensation plan that are described in this
+section. Various types of equity awards have been granted by the
+Company in different periods. For example, the Company ceased issuing
+stock options and began issuing restricted stock or RSUs to employees and
+directors in 2004. These disclosures reflect the culmination of the
+disclosure requirements for all equity awards still outstanding. 
+In May
+2006 the stockholders approved the 2006 Equity Incentive Compensation Plan (the
+“2006 Equity Plan”) to authorize the issuance of restricted stock, RSUs,
+non-qualified stock options, incentive stock options, stock appreciation rights,
+and stock-based awards to key employees, consultants, and members of the Board
+of Directors of St. Mary or any affiliate of St. Mary. The 2006
+Equity Plan serves as the successor to the St. Mary Land & Exploration
+Company Stock Option Plan, the St. Mary Land & Exploration Company
+Incentive Stock Option Plan, the St. Mary Land & Exploration Company
+Restricted Stock Plan, and the St. Mary Land & Exploration Company
+Non-Employee Director Stock Compensation Plan (collectively referred to as the
+“Predecessor Plans”). All grants of equity are now made out of the
+2006 Equity Plan, and no further grants will be made under the Predecessor
+Plans. Each outstanding award under a Predecessor Plan prior to the
+effective date of the 2006 Equity Plan continues to be governed solely by the
+terms and conditions of the instruments evidencing such grants or
+issuances. 
+Effective
+January 1, 2006, the Company adopted SFAS No. 123(R) using the
+modified-prospective transition method. Under that transition method,
+compensation expense recognized in 2006 and 2007 includes: (a) compensation
+cost for all share-based payments granted prior to, but not yet vested as of
+January 1, 2006, based on the grant date fair value estimated in accordance with
+the original provisions of SFAS No. 123, and 
+F-26
+(b) compensation
+cost for all share-based payments granted subsequent to January 1, 2006, based
+on the grant date fair value estimated in accordance with the provisions of SFAS
+No. 123(R). 
+As of
+December 31, 2007, 2.6 million shares of common stock remained available for
+grant under the 2006 Equity Plan. Any issuance of a direct share
+benefit such as an outright grant of common stock, a grant of a restricted
+share, or a RSU counts as two shares for each share issued against the amount
+eligible to be granted under the 2006 Equity Plan. Each stock option
+and similar instrument granted counts as one share for each share issued against
+the eligible shares authorized to be issued under the 2006 Equity
+Plan. 
+St. Mary
+anticipates granting Performance Share Plan (“PSP”) awards in lieu of RSUs
+beginning in 2008. The performance shares are expected to be subject
+to vesting periods and pre-established performance criteria. PSP
+awards will result in tradable shares of St. Mary common stock being issued
+immediately upon final vesting at the end of the planned three-year performance
+measurement period. The Company expects that awards granted under the
+PSP will be granted under the existing stockholder approved 2006 Equity
+Plan. The Company does have outstanding stock option grants under the
+Predecessor Plans and RSU grants under the Predecessor Plans and the 2006 Equity
+Plan. The following sections describe the details of RSU grants and
+stock options outstanding as of December 31, 2007. 
+Restricted
+Stock Incentive Program Under the Equity Incentive Compensation
+Plan 
+The
+Company has a long-term incentive program whereby grants of restricted stock or
+RSUs have been awarded to eligible employees, consultants, and members of the
+Board of Directors. Restrictions and vesting periods for the awards
+are determined at the discretion of the Board of Directors and are set forth in
+the award agreements. Each RSU represents a right for one share of
+the Company’s common stock to be delivered upon settlement of the award at the
+end of a specified period. These grants are determined annually based
+on a formula consistent with the cash bonus plan. 
+St. Mary
+issued 78,657 RSUs on February 28, 2007, related to 2006 performance,
+484,351 RSUs on February 28, 2006, related to 2005 performance and 195,312
+RSUs on March 15, 2005 related to 2004 performance. The total fair
+value associated with these issuances was $2.5 million in 2007,
+$16.4 million in 2006, and $4.5 million in 2005 as measured on the
+respective grant dates. The granted RSUs vest 25 percent
+immediately upon grant and 25 percent on each of the next three anniversary
+dates of the grant. Compensation expense is recorded monthly over the
+vesting period of the award. Vested shares of common stock underlying
+the 2005 RSU grant will be issued on the third anniversary of the grant, at
+which time the shares carry no further restrictions. For all awards
+subsequent to the 2005 RSU grant, St. Mary has eliminated the restriction period
+that extends beyond the vesting period so that shares will be issued without
+restriction upon vesting, rather than on the third anniversary of the award.
+This change was effected within the safe harbor adoption provisions of the newly
+enacted U.S. Treasury regulations interpreting IRC laws governing deferred
+compensation. The mutual election of the employee and the Company
+were required to effect this change. Essentially all of the awards
+were modified for this mutual election and as such the incremental value
+associated with removing this restriction period will be amortized over the
+remaining service period for these awards. For grants made beginning
+with the 2006 grant period, the Company is using the accelerated amortization
+method as described in FASB Interpretation No. 28, “Accounting for Stock
+Appreciation Rights and Other Variable Stock Option or Award Plans – an
+interpretation of APB Opinions No. 15 and 25,” whereby approximately 48 percent
+of the total estimated compensation expense is recognized in the first year of
+the vesting period. Expense for grants made for plan years prior to
+2006 is being amortized under the straight-line method since this method was
+allowed prior to the adoption of SFAS No. 123(R). As of
+December 31, 2007, a total of 684,264 RSUs were outstanding,
+of which 394,879 were vested. Total compensation expense related to
+the RSUs recognized in the year ended December 31, 2007, was
+$8.4 million. This amount includes $2.8 million of compensation
+expense related to the 2007 equity plan year for vesting of the estimated value
+of grants expected to be issued in 2008. 
+St. Mary
+also issued 23,977 RSUs and 13,500 RSUs for various grants to specific employees
+during 2007 and 2006, respectively. No special grants were issued
+during 2005. These grants have various vesting
+schedules. The fair value of these awards will be recorded to
+compensation expense over the respective vesting periods using the same basic
+framework as described above. 
+F-27 
+In 2007, 2006, and 2005, the Company issued 32,504, 29,827, and
+13,926 shares, respectively, of common stock from treasury to its non-employee
+directors pursuant to the Company’s non-employee director stock compensation
+plan. The Company recorded compensation expense related to the
+issuances of shares to non-employee directors of $983,500, $976,000 and $178,000
+for the years ended December 31, 2007, 2006 and 2005,
+respectively. 
+On June
+30, 2007, the Company converted 427,059 RSUs, which were granted on June 30,
+2004, into common stock based on the original terms of the RSU
+award. The Company and the majority of the grant participants
+mutually agreed to net share settle the awards to cover income and payroll tax
+withholdings as provided for in the plan document and original award
+agreements. As a result, the Company issued a net 302,370 shares of
+common stock associated with this grant. The remaining 124,689 shares
+were withheld to satisfy income and payroll tax withholding obligations that
+occurred upon the delivery of the shares underlying those RSUs. 
+In
+measuring compensation expense from the grant of RSUs, SFAS No. 123(R)
+requires companies to estimate the fair value of the award on the grant
+date. The fair value of the RSUs is inherently less than the market
+value of an unrestricted security. The fair value of RSUs has been
+measured using the Black-Scholes option-pricing model. The Company’s
+computation of expected volatility was based on the historic volatility of St.
+Mary’s common stock. The Company’s computation of expected life was
+determined based on historical experience of similar awards, giving
+consideration to the contractual terms of the awards, vesting schedules, and
+expectations of future employee behavior. The interest rate for
+periods within the contractual life of the award was based on the
+U.S. Treasury constant maturity yield at the time of grant. The
+fair values of granted RSUs were estimated using the following weighted-average
+assumptions: 
+For
+the Years Ended 
+December
+31, 
+2007 
+2006 
+2005 
+Risk
+free interest rate 
+4.5% 
+4.7% 
+4.0% 
+Dividend
+yield 
+0.3% 
+0.3% 
+0.4% 
+Volatility
+factor of the expected market 
+price
+of the Company's common stock 
+32.0% 
+36.6% 
+26.7% 
+Expected
+life of the awards (in years) 
+3 
+3 
+3 
+Upon the
+adoption of SFAS No. 123(R), the deferred compensation balance of
+$5.6 million related to outstanding RSU awards was reclassified to
+additional paid-in-capital within the shareholders’ equity section of the
+balance sheet. This deferred compensation balance had been recorded
+in accordance with APB Opinion No. 25. The Company had recorded
+compensation expense in periods prior to January 1, 2006, for restricted stock
+awards based on the intrinsic value on the date of grant. The
+intrinsic value was recorded as deferred compensation in a separate component of
+shareholders’ equity and was amortized to compensation expense over the vesting
+period. SFAS No. 123(R) requires expense recognized subsequent to the
+adoption date to be based on fair value. 
+Stock
+Awards Under the Equity Incentive Compensation Plan 
+As part
+of hiring a new senior executive in the second quarter of 2006, St. Mary granted
+a special common stock award of 20,000 shares that vested immediately upon
+commencement of employment. Approximately $728,000 of compensation
+expense was recorded related to this award in 2006. In addition to
+this award, the employee may earn an additional 5,000 shares over a four-year
+period and an additional 15,000 shares contingent on the Company meeting
+certain net asset growth performance conditions over a four-year
+period. The fair value of this award will be recorded as compensation
+expense over the vesting period. For the years ended December 31,
+2007 and 2006 the Company recorded compensation expense of $136,000 and $27,000
+respectively, related to the contingent award. 
+F-28 
+A summary
+of the status and activity of non-vested stock awards and RSUs for the year
+ended December 31, 2007, is presented below: 
+Shares 
+Weighted- 
+Average 
+Grant-Date 
+Fair
+Value 
+Non-vested,
+at December 31, 2006 
+506,161 
+$ 
+28.92 
+Granted 
+102,634 
+$ 
+32.45 
+Vested 
+(268,123 
+) 
+$ 
+25.94 
+Forfeited 
+(51,287 
+) 
+$ 
+31.77 
+Non-vested,
+at December 31, 2007 
+289,385 
+$ 
+32.26 
+Stock
+Option Grants Under the Equity Incentive Compensation Plan 
+The
+Company has previously granted stock options under the St. Mary Land &
+Exploration Company Stock Option Plan and St. Mary Land & Exploration
+Company Incentive Stock Option Plan. The last issuance of stock
+options was December 31, 2004. Stock options to purchase shares of
+the Company’s common stock had been issued to eligible employees and members of
+the Board of Directors. All options granted to date under the option
+plans have been granted at exercise prices equal to the respective closing
+market price of the Company’s underlying common stock on the grant dates, which
+generally occurred on the last date of a fiscal period. All stock
+options granted under the option plans are exercisable for a period of up to ten
+years from the date of grant. 
+During
+the year ended December 31, 2007, the Company recognized stock-based
+compensation expense of approximately $437,000 related to stock options that
+were outstanding and unvested as of January 1, 2006. There was no
+cumulative effect adjustment from the adoption of SFAS No. 123(R). 
+Prior to
+adopting SFAS No. 123(R), all tax benefits resulting from the exercise of
+stock options were presented as operating cash flows in the accompanying
+consolidated statements of cash flows. SFAS No. 123(R) requires
+cash flows resulting from excess tax benefits to be classified as a part of cash
+flows from financing activities. Excess tax benefits are realized tax
+benefits from tax deductions for exercised options in excess of the deferred tax
+asset attributable to stock compensation costs for such options. The
+Company has recorded $9.9 million and $16.1 million of excess tax benefits
+for the years ended December 31, 2007, and 2006, respectively, as cash inflows
+from financing activities. Cash received from option exercises under
+all share-based payment arrangements for the years ended
+December 31, 2007, 2006, and 2005, was $9.1 million,
+$16.9 million, and $10.6 million, respectively. 
+F-29
+A summary
+of activity associated with the Company’s Stock Option Plans during the last
+three years follows: 
+Weighted- 
+Aggregate 
+Average 
+Intrinsic 
+Shares 
+Exercise
+Price 
+Value 
+For
+the period ended December 31, 2005 
+Outstanding,
+start of year 
+5,651,350 
+$ 
+12.06 
+Granted 
+- 
+- 
+Exercised 
+(936,403 
+) 
+11.31 
+Forfeited 
+(16,704 
+) 
+13.24 
+Outstanding,
+end of year 
+4,698,243 
+$ 
+12.21 
+$ 
+115,595,735 
+Vested
+or expected to vest, end 
+of
+year 
+4,698,243 
+$ 
+12.21 
+$ 
+115,595,735 
+Exercisable,
+end of year 
+4,121,424 
+$ 
+12.07 
+$ 
+101,972,732 
+For
+the period ended December 31, 2006 
+Outstanding,
+start of year 
+4,698,243 
+$ 
+12.21 
+Granted 
+- 
+- 
+Exercised 
+(1,489,636 
+) 
+11.35 
+Forfeited 
+(87,005 
+) 
+14.33 
+Outstanding,
+end of year 
+3,121,602 
+$ 
+12.56 
+$ 
+75,800,322 
+Vested
+or expected to vest, end 
+of
+year 
+3,121,602 
+$ 
+12.56 
+$ 
+75,800,322 
+Exercisable,
+end of year 
+2,966,944 
+$ 
+12.56 
+$ 
+72,049,258 
+For
+the period ended December 31, 2007 
+Outstanding,
+start of year 
+3,121,602 
+$ 
+12.56 
+Granted 
+- 
+- 
+Exercised 
+(733,650 
+) 
+12.38 
+Forfeited 
+(2,452 
+) 
+7.34 
+Outstanding,
+end of year 
+2,385,500 
+$ 
+12.62 
+$ 
+62,007,749 
+Vested
+or expected to vest, end 
+of
+year 
+2,385,500 
+$ 
+12.62 
+$ 
+62,007,749 
+Exercisable,
+end of year 
+2,378,000 
+$ 
+12.62 
+$ 
+61,814,737 
+F-30
+A summary
+of additional information related to options outstanding as of
+December 31, 2007, follows: 
+Options
+Outstanding 
+Options
+Exercisable 
+Weighted- 
+Weighted 
+Average 
+Weighted- 
+Average 
+Weighted- 
+Remaining 
+Average 
+Remaining 
+Average 
+Range
+of 
+Number 
+Contractual 
+Exercise 
+Number 
+Contractual 
+Exercise 
+Exercise
+Prices 
+Outstanding 
+Life 
+Price 
+Exercisable 
+Life 
+Price 
+$ 
+4.62 
+- 
+$ 
+10.60 
+464,747 
+2.9
+years 
+$ 
+7.77 
+464,747 
+2.9
+years 
+$ 
+7.77 
+10.86 
+- 
+12.03 
+469,156 
+4.5
+years 
+11.65 
+469,156 
+4.5
+years 
+11.65 
+12.08 
+- 
+12.53 
+388,139 
+5.1
+years 
+12.50 
+388,139 
+5.1
+years 
+12.50 
+12.66 
+- 
+13.65 
+368,847 
+5.6
+years 
+13.25 
+361,347 
+5.6
+years 
+13.25 
+14.25 
+- 
+14.25 
+239,129 
+6.0
+years 
+14.25 
+239,129 
+6.0
+years 
+14.25 
+16.66 
+- 
+16.66 
+387,078 
+3.0
+years 
+16.66 
+387,078 
+3.0
+years 
+16.66 
+20.87 
+- 
+20.87 
+68,404 
+7.0
+years 
+20.87 
+68,404 
+7.0
+years 
+20.87 
+Total 
+2,385,500 
+2,378,000 
+The fair
+value of options was measured at the date of grant using the Black-Scholes
+option-pricing model. 
+Note
+8 – Pension Benefits 
+The
+Company has a non-contributory pension plan covering substantially all employees
+who meet age and service requirements (the “Qualified Pension
+Plan”). The Company also has a supplemental non-contributory pension
+plan covering certain management employees (the “Nonqualified Pension
+Plan”). 
+On
+December 31, 2006, the Company adopted the recognition and disclosure provisions
+of Statements of Financial Accounting Standards No. 158, “Employers’ Accounting
+for Defined Benefit Pension and Other Postretirement Plans – an Amendment of
+FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS No. 158”). This
+standard requires the Company to recognize the funded status (i.e., the
+difference between the fair value of plan assets and the projected benefit
+obligation) of its pension plan in the consolidated balance sheets as either an
+asset or a liability, with a corresponding adjustment to accumulated other
+comprehensive income, net of tax. The adjustment to accumulated other
+comprehensive income at adoption represented the net unrecognized actuarial
+losses and unrecognized prior service costs, both of which were previously
+netted against the plan’s funded status in the Company’s consolidated balance
+sheets pursuant to the provisions of Statements of Financial Accounting
+Standards No. 87, “Employers’ Accounting for Pensions” (“SFAS No.
+87”). These amounts will be subsequently recognized as net
+periodic pension cost pursuant to the Company’s accounting policy for amortizing
+such amounts. Further actuarial gains and losses that arise in
+subsequent periods and are not recognized as net periodic pension cost in the
+same periods will be recognized as a component of other comprehensive
+income. Those amounts will be subsequently recognized as a component
+of net periodic pension cost on the same basis as the amounts recognized in
+accumulated other comprehensive income at adoption of SFAS No. 158. 
+F-31
+The
+incremental effects of adopting the provisions of SFAS No. 158 on the Company’s
+statement of financial position at December 31, 2006, are presented in the
+following table. The adoption of SFAS No. 158 had no effect on the
+Company’s accompanying consolidated statements of operations for the year ended
+December 31, 2006, or for any prior period presented, and it will not affect the
+Company’s operating results in future periods. The effect of
+recognizing this additional liability is included in the table below in the
+column labeled “Prior to Adopting SFAS No. 158.” 
+At
+December 31, 2006 
+Prior
+to Adopting SFAS No. 158 
+Effect
+of Adopting SFAS No. 158 
+As
+Reported 
+(In
+thousands) 
+Accrued
+pension liability 
+$ 
+3,355 
+$ 
+2,619 
+$ 
+5,974 
+Deferred
+income taxes 
+$ 
+(932 
+) 
+$ 
+(990 
+) 
+$ 
+(1,922 
+) 
+Accumulated
+other comprehensive income 
+$ 
+- 
+$ 
+2,619 
+$ 
+2,619 
+Actuarial
+gains and losses are comprised of experience changes and effects of changes in
+actuarial assumptions. Experience changes are the effects of
+differences between previous actuarial assumptions and what actually
+occurred. Included in accumulated other comprehensive income at
+December 31, 2007, are the following amounts that have not yet been
+recognized in net periodic pension cost: 
+As
+of 
+December
+31, 2007 
+(In
+thousands) 
+Unrecognized
+actuarial losses 
+$ 
+2,500 
+Unrecognized
+prior service costs 
+- 
+Accumulated
+other comprehensive income 
+$ 
+2,500 
+The
+estimated net loss for the Qualified Pension Plan and the Nonqualified Pension
+Plan (“the Pension Plans”) that will be amortized from accumulated other
+comprehensive income into net periodic benefit cost over the next fiscal year is
+$112,000. 
+F-32 
+Obligations
+and Funded Status for Both Pension Plans 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Change
+in benefit obligations: 
+Projected
+benefit obligation at beginning of year 
+$ 
+13,763 
+$ 
+11,900 
+$ 
+10,174 
+Service
+cost 
+1,911 
+1,684 
+1,385 
+Interest
+cost 
+793 
+652 
+535 
+Actuarial
+(gain) loss 
+95 
+7 
+(4 
+) 
+Benefits
+paid 
+(1,818 
+) 
+(480 
+) 
+(190 
+) 
+Projected
+benefit obligation at end of year 
+$ 
+14,744 
+$ 
+13,763 
+$ 
+11,900 
+Change
+in plan assets: 
+Fair
+value of plan assets at beginning of year 
+$ 
+7,789 
+$ 
+5,955 
+$ 
+4,675 
+Actual
+return on plan assets 
+536 
+968 
+412 
+Employer
+contribution 
+2,248 
+1,346 
+1,058 
+Benefits
+paid 
+(1,818 
+) 
+(480 
+) 
+(190 
+) 
+Fair
+value of plan assets at end of year 
+$ 
+8,755 
+$ 
+7,789 
+$ 
+5,955 
+Funded
+status: 
+$ 
+(5,989 
+) 
+$ 
+(5,974 
+) 
+$ 
+(5,945 
+) 
+Accumulated
+Benefit Obligation 
+$ 
+10,416 
+$ 
+9,922 
+$ 
+8,429 
+The
+combined underfunded status for the Pension Plans of $6.0 million at December
+31, 2007, is recognized in the accompanying statement of financial position as
+long-term accrued pension liability. No plan assets of the Qualified
+Pension Plan are expected to be returned to the Company during the fiscal year
+ended December 31, 2008. There are no plan assets in the Nonqualified
+Pension Plan. 
+Information
+for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan
+Assets for Both Plans 
+As
+of December 31, 
+2007 
+2006 
+(In
+thousands) 
+Projected
+benefit obligation 
+$ 
+14,744 
+$ 
+13,763 
+Accumulated
+benefit obligation 
+$ 
+10,416 
+$ 
+9,922 
+Fair
+value of plan assets 
+$ 
+8,755 
+$ 
+7,789 
+F-33
+Components
+of Net Periodic Benefit Cost for Both Pension Plans 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Components
+of net periodic benefit cost: 
+Service
+cost 
+$ 
+1,911 
+$ 
+1,684 
+$ 
+1,385 
+Interest
+cost 
+793 
+652 
+535 
+Expected
+return on plan assets that reduces periodic pension cost 
+(540 
+) 
+(427 
+) 
+(354 
+) 
+Amortization
+of prior service cost 
+- 
+- 
+- 
+Amortization
+of net actuarial loss 
+218 
+296 
+241 
+Net
+periodic benefit cost 
+$ 
+2,382 
+$ 
+2,205 
+$ 
+1,807 
+Prior
+service costs are amortized on a straight-line basis over the average remaining
+service period of active participants. Gains and losses in excess of
+ten percent of the greater of the benefit obligation and the market-related
+value of assets are amortized over the average remaining service period of
+active participants. 
+Assumptions 
+Weighted-average
+assumptions to measure the Company’s projected benefit obligation and net
+periodic benefit cost are as follows: 
+As
+of December 31, 
+2007 
+2006 
+Projected benefit
+obligation 
+Discount
+rate 
+6.1% 
+5.9% 
+Rate
+of compensation increase 
+6.2% 
+6.2% 
+Net periodic benefit
+cost 
+Discount
+rate 
+5.9% 
+5.5% 
+Expected
+return on plan assets 
+7.5% 
+7.5% 
+Rate
+of compensation increase 
+6.2% 
+6.2% 
+Plan
+Assets 
+The
+Company’s weighted-average asset allocation for the Qualified Pension Plan is as
+follows: 
+Target 
+As
+of December 31, 
+Asset
+Category 
+2008 
+2007 
+2006 
+Equity
+securities 
+60.0% 
+57.5% 
+64.8% 
+Debt
+securities 
+40.0% 
+42.5% 
+35.2% 
+Other 
+- 
+- 
+- 
+Total 
+100.0% 
+100.0% 
+100.0% 
+Equity
+securities do not include any shares of the Company’s common stock for any
+period presented. There is no asset allocation for the Nonqualified
+Pension Plan since that plan does not have its own assets. An
+expected return on plan assets of 7.5 percent was used to calculate the
+Company’s obligation under the Qualified Pension Plan. Factors considered
+in determining the expected return include the 60 percent equity and 40 percent
+debt securities mix of investment for plan assets and the long-term historical
+rate of return provided by the equity 
+F-34
+and debt securities markets. The estimated rate of return on
+plan assets was 7.5 percent for 2007 and 2006. The difference in
+investment income using the projected rate of return compared to the actual
+rates of return for the past two years was not material and will not have a
+material effect on the statements of operation or on cash flows from operating
+activities in future years. 
+Contributions 
+The
+Company contributed $2.2 million, $1.3 million, and $1.1 million, to the Pension
+Plans in the years ended December 31, 2007, 2006, and 2005,
+respectively. St. Mary expects to contribute approximately
+$2.9 million to the Pension Plans in 2008. 
+Benefit
+Payments 
+The
+Pension Plans made actual benefit payments of $1.8 million, $480,000, and
+$190,000 in the years ended December 31, 2007, 2006, and 2005,
+respectively. Expected benefit payments over the next ten years
+follows: 
+Years
+Ended December 31, 
+(in
+thousands) 
+2008 
+$ 
+1,612 
+2009 
+479 
+2010 
+734 
+2011 
+1,254 
+2012 
+1,529 
+2013
+through 2017 
+$ 
+13,793 
+Note
+9 – Asset Retirement Obligations 
+The
+Company recognizes an estimated liability for future costs associated with the
+abandonment of its oil and gas properties. A liability for the fair
+value of an asset retirement obligation and a corresponding increase to the
+carrying value of the related long-lived asset are recorded at the time a well
+is completed or acquired. The increase in carrying value is included
+in proved oil and gas properties in the accompanying consolidated balance
+sheets. The Company depletes the amount added to proved oil and gas
+property costs and recognizes expense in connection with the accretion of the
+discounted liability over the remaining estimated economic lives of the
+respective oil and gas properties. Cash paid to settle asset
+retirement obligations is included in the operating section of the Company’s
+accompanying consolidated statements of cash flows. 
+The
+Company’s estimated asset retirement obligation liability is based on historical
+experience in abandoning wells, estimated economic lives, estimates as to the
+cost to abandon the wells in the future, and federal and state regulatory
+requirements. The liability is discounted using a credit-adjusted
+risk-free rate estimated at the time the liability is incurred or
+revised. The credit-adjusted risk-free rates used to discount the
+Company’s abandonment liabilities range from 6.50 percent to
+7.25 percent. Revisions to the liability could occur due to
+changes in estimated abandonment costs or well economic lives, or if federal or
+state regulators enact new requirements regarding the abandonment of
+wells. 
+F-35
+A
+reconciliation of the Company's asset retirement obligation liability is as
+follows: 
+As
+of December 31, 
+2007 
+2006 
+(In
+thousands) 
+Beginning
+asset retirement obligation 
+$ 
+77,242 
+$ 
+66,078 
+Liabilities
+incurred 
+10,851 
+7,555 
+Liabilities
+settled 
+(12,276 
+) 
+(1,484 
+) 
+Accretion
+expense 
+5,458 
+4,926 
+Revision
+to estimated cash flows 
+27,009 
+167 
+Ending
+asset retirement obligation 
+$ 
+108,284 
+$ 
+77,242 
+Accounts
+payable and accrued expenses as of December 31, 2007, contain
+$3.1 million related to the Company’s asset retirement
+obligation. The amount relates to the estimated plugging and
+abandonment costs associated with one offshore platform that was destroyed
+during Hurricane Rita. Plugging and abandonment of the platform is
+expected to be completed during the second quarter of 2008. Please
+refer to Note 12 – Insurance Settlement for additional
+details. Accounts payable and accrued expenses did not contain any
+amount related to the Company’s asset retirement obligation as of
+December 31, 2006. 
+Note
+10 – Derivative Financial Instruments 
+Oil
+and Gas Commodity Hedges 
+To
+mitigate a portion of the potential exposure to adverse market changes, the
+Company has entered into various derivative contracts. The Company’s
+derivative contracts in place include swap and collar arrangements for the sale
+of oil, natural gas, and natural gas liquids. Please refer to the
+tables under Summary of Oil
+and Gas Production Hedges in Place in Part II, Item 7,
+Management’s Discussion and Analysis of Financial Condition and Results of
+Operations, for details regarding the Company’s hedged volumes and associated
+prices. As of December 31, 2007, the Company has hedge
+contracts in place through 2011 for a total of approximately
+11.4 million Bbls of anticipated crude oil production,
+70.2 million MMBtu of anticipated natural gas production, and
+1.4 million Bbls of anticipated natural gas liquids
+production. 
+The
+Company attempts to qualify its oil and natural gas derivative instruments as
+cash flow hedges for accounting purposes under SFAS No. 133 and related
+pronouncements. The Company formally documents all relationships
+between the derivative instruments and the hedged production, as well as the
+Company’s risk management objective and strategy for the particular derivative
+contracts. This process includes linking all derivatives that are
+designated as cash flow hedges to the specific forecasted sale of oil or gas at
+its physical location. The Company also formally assesses (both at
+the derivative’s inception and on an ongoing basis) whether the derivatives
+being utilized have been highly effective at offsetting changes in the cash
+flows of hedged production and whether those derivatives may be expected to
+remain highly effective in future periods. If it is determined that a
+derivative has ceased to be highly effective as a hedge, the Company will
+discontinue hedge accounting prospectively. If hedge accounting is
+discontinued and the derivative remains outstanding, the Company will recognize
+all subsequent changes in its fair value on the Company’s consolidated
+statements of operations for the period in which the change
+occurs. As of December 31, 2007, all oil and natural gas
+derivative instruments qualified as cash flow hedges for accounting
+purposes. The Company anticipates that all forecasted transactions
+will occur by the end of their originally specified periods. All
+contracts are entered into for other than trading purposes. 
+The
+Company’s oil and gas hedges are measured at fair value and are included in the
+accompanying consolidated balance sheets as assets or
+liabilities. The Company evaluates market prices in active markets to
+establish the valuation of derivative instruments. The Company compares
+valuation estimates against mark-to-market statements from counterparts for
+reasonableness. Management believes that this approach provides a
+reasonable, non-biased, verifiable, and consistent methodology for valuing
+derivative instruments. The 
+F-36
+derivative
+instruments utilized by the Company are not considered by management to be
+complex, structured,or illiquid. The oil
+and gas derivative markets are highly active. The fair value of oil
+and natural gas derivative contracts designated and qualifying as cash flow
+hedges under SFAS No. 133 was a net liability of $264.1 million
+at December 31, 2007. 
+The
+Company realized a net gain of $19.3 million, a net gain of
+$20.5 million, and a net loss of $24.4 million from its oil and gas
+derivative contracts for the years ended December 31, 2007, 2006, and
+2005, respectively. 
+After-tax
+changes in the fair value of derivative instruments designated as cash flow
+hedges, to the extent they are effective in offsetting cash flows attributable
+to the hedged risk, are recorded in other comprehensive income until the hedged
+item is recognized in earnings upon the sale of the hedged
+production. As of December 31, 2007, the amount of unrealized
+loss net of deferred income taxes to be reclassified from accumulated other
+comprehensive income to oil and gas production operating revenues in the next
+twelve months was $48.0 million. 
+Any
+change in fair value resulting from ineffectiveness is recognized currently in
+unrealized derivative loss in the accompanying consolidated statements of
+operations. Unrealized derivative loss for the years ended December
+31, 2007, 2006, and 2005, includes net losses of $4.1 million,
+$8.1 million, and $1.8 million, respectively, from ineffectiveness related
+to oil and natural gas derivative contracts. 
+Gains or
+losses from the settlement of oil and gas derivative contracts are reported in
+the total operating revenues section of the accompanying consolidated statements
+of operations. 
+The
+Company seeks to minimize ineffectiveness by entering into oil derivative
+contracts indexed to NYMEX and natural gas derivative contracts indexed to
+regional index prices associated with pipelines in proximity to the Company’s
+areas of production. As the Company’s derivative contracts contain
+the same index as the Company’s sale contracts, this results in hedges that are
+highly correlated with the underlying hedged item. 
+The
+following table summarizes derivative instrument realized gain (loss)
+activity: 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Derivative
+contract settlements included in realized oil and gas hedge gain
+(loss) 
+$ 
+24,484 
+$ 
+28,176 
+$ 
+(22,539 
+) 
+Ineffective
+portion of hedges qualifying for hedge accounting included in unrealized
+derivative loss 
+(4,123 
+) 
+(8,087 
+) 
+(1,754 
+) 
+Non-qualified
+derivative contracts included in unrealized derivative
+loss 
+(1,335 
+) 
+993 
+139 
+Interest
+rate derivative contract settlements 
+226 
+(550 
+) 
+(247 
+) 
+Total
+realized gain (loss) 
+$ 
+19,252 
+$ 
+20,532 
+$ 
+(24,401 
+) 
+Interest
+Rate Derivative Contracts 
+In
+September 2007 the Company entered into a one year floating-to-fixed interest
+rate derivative contract for a notional amount of $75 million. Under
+the agreement, the Company will pay a fixed rate of 4.90 percent and will be
+paid a variable rate based on the one-month LIBOR rate. The interest
+rate derivative contract is measured at fair value using quoted prices in active
+markets. The liability in the accompanying consolidated balance sheet at
+December 31, 2007, was $447,000. The interest rate swap is a
+straightforward, non-complex, non-structured instrument that is highly
+liquid. This derivative qualifies for cash flow hedge treatment under SFAS
+No. 133 and 
+F-37
+related pronouncements. The Company recorded a net
+derivative gain of $57,000 in the accompanying consolidated statements of
+operations for the year ended December 31, 2007, related to this interest
+rate derivative contract. 
+Convertible
+Note Derivative Instrument 
+In
+relation to the Company’s 5.75% Senior Convertible Notes converted in March
+2007, the Company entered into fixed-to-floating interest rate swaps on
+$50 million of principal in October 2003. Due to the continued
+increases in interest rates, the Company entered into a floating-to-fixed
+interest rate swap in April 2005 through March 20, 2007, for this
+same notional amount of $50 million in order to effectively offset our
+fixed-to-floating interest rate swaps. The impact of this instrument, when
+combined with the other interest rate swaps, was that the Company fixed the net
+liability related to the interest rate swaps, and paid a 1.1 percent
+interest factor on $50 million of notional debt through
+March 2007. The contingent interest provision of the 3.50% Senior
+Convertible Notes is a derivative instrument. However, the value of
+the derivative was determined to be de minimis at the inception of the
+instrument. 
+Note
+11 – Repurchase of Common Stock 
+Stock
+Repurchase Program 
+In July
+2006 the Company’s Board of Directors approved an increase of 5,473,182 shares
+to the remaining authorized number of shares that can be repurchased under the
+Company’s original authorization approved in August 1998, for a total number of
+shares to be repurchased under the plan of 6 million. As of the
+date of this filing, the Company has Board authorization to repurchase up to
+5,207,784 shares of common stock. The shares may be repurchased from
+time to time in open market transactions or in privately negotiated
+transactions, subject to market conditions and other factors, including certain
+provisions of St. Mary’s existing credit facility agreement and compliance with
+securities laws. Stock repurchases may be funded with existing cash
+balances, internal cash flow, and borrowings under the credit
+facility. During 2007 the Company repurchased 792,216 shares of
+its outstanding common stock in the open market at a weighted-average price of
+$32.76 per share, including commissions, for a total of
+$26.0 million. During 2006 the Company repurchased
+3,319,300 shares of its outstanding common stock in the open market at a
+weighted-average price of $37.09 per share, including commissions, for
+a total of $123.1 million. During 2005 the Company repurchased
+1,175,282 shares of its outstanding common stock in the open market at a
+weighted-average price of $24.59 per share, including commissions, for
+a total of $28.9 million. The Company did not retire any shares
+in 2007. The Company retired 3,275,689 shares in 2006 and 1,411,356
+shares in 2005. 
+Note
+12 – Insurance Settlement 
+In April
+of 2007 the Company reached a global insurance settlement for reimbursement of
+damages sustained during Hurricane Rita. St. Mary’s net amount of the
+final settlement was approximately $33 million. As a result of
+this settlement, the Company recorded a gain of $5.2 million in other
+revenue in the accompanying statement of operations for the year ended
+December 31, 2007. The Company experienced significant
+weather-related delays in its plug and abandonment efforts during 2007 and
+consequently accrued an additional $2.1 million of plug and abandonment
+costs for one offshore platform during the fourth quarter of 2007. The gain
+calculation takes into consideration a total of approximately $12.1 million
+of costs associated with the plugging and abandonment of the above-mentioned
+offshore platform. Any significant variation between actual and
+estimated plugging and abandonment and outside-operated damage repair costs will
+impact the final determination of the gain associated with the insurance
+settlement. The Company expects adjustments to the gain to be
+completed by the second quarter of 2008. 
+F-38
+Note
+13 – Disclosures about Oil and Gas Producing Activities 
+Costs
+Incurred in Oil and Gas Producing Activities 
+Costs
+incurred in oil and gas property acquisition, exploration and development
+activities, whether capitalized or expensed, are summarized as
+follows. The 2007, 2006, and 2005 amounts include $27.6 million,
+$7.8 million, and $22.8 million, respectively, of capitalized costs
+associated with asset retirement obligations. 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Development
+costs 
+$ 
+591,013 
+$ 
+367,546 
+$ 
+249,518 
+Exploration 
+111,470 
+126,220 
+69,817 
+Acquisitions: 
+Proved 
+161,665 
+238,400 
+84,981 
+Unproved 
+23,495 
+44,472 
+2,853 
+Leasing
+activity 
+38,436 
+28,816 
+14,330 
+Total 
+$ 
+926,079 
+$ 
+805,454 
+$ 
+421,499 
+Suspended
+Well Costs 
+The
+following table reflects the net changes in capitalized exploratory well costs
+during 2007, 2006, and 2005. The table does not include amounts that
+were capitalized and either subsequently expensed or reclassified to producing
+well costs in the same period. 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Beginning
+balance at January 1, 
+$ 
+22,799 
+$ 
+7,994 
+$ 
+189 
+Capitalized
+exploratory well costs charged to expense upon adoption of FSP FAS
+19-1 
+- 
+- 
+- 
+Additions
+to capitalized exploratory well costs pending the determination of proved
+reserves 
+29,551 
+17,693 
+7,994 
+Reclassifications
+to wells, facilities, and equipment based on the determination of proved
+reserves 
+(9,237 
+) 
+(2,888 
+) 
+(189 
+) 
+Capitalized
+exploratory well costs charged to expense 
+(183 
+) 
+- 
+- 
+Ending
+balance at December 31, 
+$ 
+42,930 
+$ 
+22,799 
+$ 
+7,994 
+The
+following table provides an aging of capitalized exploratory well costs based on
+the date the drilling was completed and the number of projects for which
+exploratory well costs have been capitalized for more than one year since the
+completion of drilling. 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Exploratory
+well costs capitalized for one year or less 
+$ 
+29,368 
+$ 
+17,958 
+$ 
+7,994 
+Exploratory
+well costs capitalized for more than one year 
+13,562 
+4,841 
+- 
+Ending
+balance at December 31, 
+$ 
+42,930 
+$ 
+22,799 
+$ 
+7,994 
+Number
+of projects with exploratory well costs that have been capitalized more
+than a year 
+3 
+1 
+- 
+F-39
+The
+exploratory well costs capitalized for more than one year includes
+$4.8 million for a well that was drilled in 2005 and 2006 and is located
+offshore in the Gulf of Mexico. A Reserve Analysis and Reservoir
+Simulation Study has been completed for this well. Construction of a
+long lead-time infrastructure began in 2007 and is expected to be completed
+during the fourth quarter of 2008. Production from this well is
+expected to commence in 2009. The operational plan is to build
+the connection and process facilities in support of the already recognized
+costs. The Company believes these costs are realizable. 
+The
+exploratory well costs capitalized for more than one year also includes
+$5.7 million and $3.1 million of costs related to two additional wells
+located offshore in the Gulf of Mexico that were drilled in
+2006. Reserve Analysis and Reservoir Simulation Studies have been
+completed for these wells to support the ongoing project
+economics. The wells were both waiting on the construction of
+production facilities, which were completed in late 2007. Production
+from both of these wells is expected to commence during the first quarter of
+2008. Based on the operational plan and project economics for these
+wells, the Company believes these costs are realizable. 
+Oil
+and Gas Reserve Quantities (Unaudited) 
+For all
+years presented, Netherland, Sewell and Associates, Inc. (“NSAI”) prepared the
+reserve information for the Company’s coalbed methane projects at Hanging Woman
+Basin in the northern Powder River Basin as well as the Company’s non-operated
+coalbed methane interests in the Green River Basin. The Company
+engaged Ryder Scott Company, L.P. to review internal engineering estimates for
+80 percent of the PV-10 value of its proven conventional oil and gas
+reserves in 2007 and 2006. In 2005, Ryder Scott Company, L.P.prepared
+the reserve estimates for at least 80 percent of the PV-10 value of the
+Company's conventional oil and gas assets. St. Mary personnel
+prepared the reserve estimates for the remainder of all
+properties. The Company emphasizes that reserve estimates are
+inherently imprecise and that estimates of new discoveries and undeveloped
+locations are more imprecise than estimates of established producing oil and gas
+properties. Accordingly, these estimates are expected to change as
+future information becomes available. 
+Proved
+oil and gas reserves are the estimated quantities of crude oil, natural gas, and
+natural gas liquids that geological and engineering data demonstrate with
+reasonable certainty to be recoverable in future years from known reservoirs
+under existing economic and operating conditions. Proved developed
+oil and gas reserves are those expected to be recovered through existing wells
+with existing equipment and operating methods. All of the Company’s
+proved reserves are located in the continental United States and offshore in the
+Gulf of Mexico. 
+F-40 
+Presented
+below is a summary of the changes in estimated reserves of the
+Company: 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+Oil
+or 
+Oil
+or 
+Oil
+or 
+Condensate 
+Gas 
+Condensate 
+Gas 
+Condensate 
+Gas 
+(MBbl) 
+(MMcf) 
+(MBbl) 
+(MMcf) 
+(MBbl) 
+(MMcf) 
+Developed
+and undeveloped: 
+Beginning
+of year 
+74,195 
+482,475 
+62,903 
+417,075 
+56,574 
+319,196 
+Revisions
+of previous estimate 
+5,238 
+9,489 
+524 
+10,946 
+1,593 
+24,354 
+Discoveries
+and extensions 
+1,166 
+28,483 
+857 
+36,723 
+2,553 
+21,998 
+Infill
+reserves in an existing proved field 
+4,592 
+69,090 
+4,131 
+49,107 
+3,286 
+83,093 
+Purchases
+of minerals in place 
+567 
+91,374 
+11,857 
+28,030 
+4,831 
+20,823 
+Sales
+of reserves 
+(4 
+) 
+(1,400 
+) 
+(20 
+) 
+(2,958 
+) 
+(7 
+) 
+(588 
+) 
+Production 
+(6,907 
+) 
+(66,061 
+) 
+(6,057 
+) 
+(56,448 
+) 
+(5,927 
+) 
+(51,801 
+) 
+End
+of year (a)
+(b) 
+78,847 
+613,450 
+74,195 
+482,475 
+62,903 
+417,075 
+Proved
+developed reserves: 
+Beginning
+of year 
+61,519 
+358,477 
+55,971 
+313,125 
+47,992 
+272,295 
+End
+of year 
+68,277 
+426,627 
+61,519 
+358,477 
+55,971 
+313,125 
+(a) At
+December 31, 2007, 2006, and 2005 amounts include approximately 316, 523,
+and 435 MMcf, repectively, representing the Company's net underproduced
+gas balancing position. 
+(b) 
+Subsequent to the year ended December 31, 2007, the Company divested of
+certain non-core properties, which included 40.4 BCFE of
+reserves that were owned by the Company as 
+of December 31, 2007. 
+Standardized
+Measure of Discounted Future Net Cash Flows (Unaudited) 
+Statement
+of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas
+Producing Activities” (“SFAS No. 69”) prescribes guidelines for computing a
+standardized measure of future net cash flows and changes therein relating to
+estimated proved reserves. The Company follows these guidelines,
+which are briefly discussed below. 
+Future
+cash inflows and future production and development costs are determined by
+applying benchmark prices and costs, including transportation, quality, and
+basis differentials, in effect at year end to the year-end estimated quantities
+of oil and gas to be produced in the future. Each property the
+Company operates is also charged with field-level overhead in the estimated
+reserve calculation. Estimated future income taxes are computed using
+current statutory income tax rates, including consideration for estimated future
+statutory depletion. The resulting future net cash flows are reduced
+to present value amounts by applying a ten percent annual discount
+factor. 
+Future
+operating costs are determined based on estimates of expenditures to be incurred
+in developing and producing the proved oil and gas reserves in place at the end
+of the period using year-end costs and assuming continuation of existing
+economic conditions, plus Company overhead incurred by the central
+administrative office attributable to operating activities. 
+F-41 
+The
+assumptions used to compute the standardized measure are those prescribed by the
+FASB and the Securities and Exchange Commission. These assumptions do
+not necessarily reflect the Company's expectations of actual revenues to be
+derived from those reserves, nor their present value. The limitations
+inherent in the reserve quantity estimation process, as discussed previously,
+are equally applicable to the standardized measure computations since these
+reserve quantity estimates are the basis for the valuation
+process. The following prices as adjusted for transportation, quality
+and basis differentials, were used in the calculation of the standardized
+measure: 
+2007 
+2006 
+2005 
+Gas
+(per Mcf) 
+$ 
+7.56 
+$ 
+5.54 
+$ 
+8.34 
+Oil
+(per Bbl) 
+$ 
+88.71 
+$ 
+53.65 
+$ 
+55.63 
+The
+following summary sets forth the Company's future net cash flows relating to
+proved oil and gas reserves based on the standardized measure prescribed in SFAS
+No. 69: 
+As
+of December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Future
+cash inflows 
+$ 
+11,629,679 
+$ 
+6,653,455 
+$ 
+6,979,279 
+Future
+production costs 
+(3,672,857 
+) 
+(2,283,452 
+) 
+(2,146,590 
+) 
+Future
+development costs 
+(611,288 
+) 
+(429,303 
+) 
+(385,379 
+) 
+Future
+income taxes 
+(2,316,637 
+) 
+(1,125,955 
+) 
+(1,448,444 
+) 
+Future
+net cash flows 
+5,028,897 
+2,814,745 
+2,998,866 
+10
+percent annual discount 
+(2,321,983 
+) 
+(1,238,308 
+) 
+(1,286,568 
+) 
+Standardized
+measure of discounted future
+net cash flows 
+$ 
+2,706,914 
+$ 
+1,576,437 
+$ 
+1,712,298 
+F-42
+The
+principle sources of change in the standardized measure of discounted future net
+cash flows are: 
+For
+the Years Ended December 31, 
+2007 
+2006 
+2005 
+(In
+thousands) 
+Standard
+measure, beginning of year 
+$ 
+1,576,436 
+$ 
+1,712,298 
+$ 
+1,033,938 
+Sales
+of oil and gas produced, net of production costs 
+(693,885 
+) 
+(554,147 
+) 
+(590,671 
+) 
+Net
+changes in prices and production costs 
+1,320,994 
+(661,074 
+) 
+725,154 
+Extensions,
+discoveries and other including infill reserves in an existing proved
+field, net of production costs 
+462,952 
+280,822 
+422,481 
+Purchase
+of minerals in place 
+265,285 
+263,762 
+132,185 
+Development
+costs incurred during the year 
+123,630 
+67,864 
+55,324 
+Changes
+in estimated future development costs 
+(32,566 
+) 
+114,007 
+(42,710 
+) 
+Revisions
+of previous quantity estimates 
+166,428 
+34,940 
+117,763 
+Accretion
+of discount 
+215,745 
+249,417 
+150,112 
+Sales
+of reserves in place 
+(1,915 
+) 
+(8,991 
+) 
+(1,000 
+) 
+Net
+change in income taxes 
+(573,259 
+) 
+200,858 
+(314,685 
+) 
+Changes
+in timing and other 
+(122,931 
+) 
+(123,319 
+) 
+24,407 
+Standardized
+measure, end of year 
+$ 
+2,706,914 
+$ 
+1,576,437 
+$ 
+1,712,298 
+F-43
+Note
+14 – Quarterly Financial Information (Unaudited) 
+The
+Company’s quarterly financial information for fiscal 2007 and 2006 is as follows
+(in thousands, except per share amounts): 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+Year Ended December
+31, 2007 
+Total
+operating revenues 
+$ 
+221,006 
+$ 
+247,154 
+$ 
+246,687 
+$ 
+275,247 
+Total
+operating expenses (1) 
+151,494 
+149,171 
+151,336 
+218,682 
+Income
+from operations 
+$ 
+69,512 
+$ 
+97,983 
+$ 
+95,351 
+$ 
+56,565 
+Income
+before income taxes 
+$ 
+63,562 
+$ 
+94,387 
+$ 
+91,624 
+$ 
+50,689 
+Net
+income 
+$ 
+39,950 
+$ 
+59,235 
+$ 
+57,653 
+$ 
+32,874 
+Basic
+net income per common share 
+$ 
+0.70 
+$ 
+0.93 
+$ 
+0.91 
+$ 
+0.52 
+Diluted
+net income per common share 
+$ 
+0.63 
+$ 
+0.91 
+$ 
+0.89 
+$ 
+0.51 
+Dividends
+declared per common share 
+$ 
+0.05 
+$ 
+- 
+$ 
+0.05 
+$ 
+- 
+Year Ended December
+31, 2006 
+Total
+operating revenues 
+$ 
+193,588 
+$ 
+193,381 
+$ 
+198,040 
+$ 
+202,692 
+Total
+operating expenses 
+112,902 
+128,296 
+110,818 
+133,419 
+Income
+from operations 
+$ 
+80,686 
+$ 
+65,085 
+$ 
+87,222 
+$ 
+69,273 
+Income
+before income taxes 
+$ 
+80,131 
+$ 
+64,076 
+$ 
+85,142 
+$ 
+65,972 
+Net
+income 
+$ 
+50,526 
+$ 
+40,080 
+$ 
+55,877 
+$ 
+43,532 
+Basic
+net income per common share 
+$ 
+0.88 
+$ 
+0.70 
+$ 
+1.01 
+$ 
+0.78 
+Diluted
+net income per common share 
+$ 
+0.76 
+$ 
+0.61 
+$ 
+0.88 
+$ 
+0.69 
+Dividends
+declared per common share 
+$ 
+0.05 
+$ 
+- 
+$ 
+0.05 
+$ 
+- 
+(1) General and administrative and
+exploration expense are components of total operating expenses. As a
+result of a change in circumstances in 2007, the Company began classifying all
+payments made under the Net Profits Plan to exploration overhead only for those
+individuals who are currently employed by St. Mary and who continue to be
+involved in the Company’s exploration efforts. Therefore, the
+quarterly financial information presented in the following table reflects a
+reconciliation from what was previously reported in the quarterly reports on
+Form 10-Q, to the reclassified balances, which reflect current distributions
+being made and accrued for under the Net Profits Plan for former employees as
+being fully allocated to general and administrative expense since there is no
+longer any functional link to geologic and geophysical or exploration related
+work by those former employees. The reclassification was determined
+in the fourth quarter, therefore, no reclassification was necessary as the
+amounts reported for the fourth quarter were accounted for consistent with the
+current presentation. The change had no impact on total operating
+expenses, income from operations, income before income taxes, net income, basic
+net income per share, or diluted net income per share as it was simply a
+reclassification between two line items within the accompanying consolidated
+statements of operations as shown below. 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+(In
+thousands) 
+General
+and administrative: 
+As
+previously reported 
+$ 
+11,141 
+$ 
+13,697 
+$ 
+13,110 
+$ 
+15,187 
+Net
+Profits Plan Adjustment 
+1,750 
+2,569 
+2,695 
+- 
+Adjusted
+general and administrative 
+$ 
+12,891 
+$ 
+16,266 
+$ 
+15,805 
+$ 
+15,187 
+Exploration: 
+As
+previously reported 
+$ 
+20,769 
+$ 
+13,643 
+$ 
+15,257 
+$ 
+16,030 
+Net
+Profits Plan Adjustment 
+(1,749 
+) 
+(2,569 
+) 
+(2,695 
+) 
+- 
+Adjusted
+exploration 
+$ 
+19,020 
+$ 
+11,074 
+$ 
+12,562 
+$ 
+16,030 
+F-44
+SIGNATURES 
+Pursuant
+to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
+1934, the registrant has duly caused this report to be signed on its behalf by
+the undersigned, thereunto duly authorized. 
+ST. MARY LAND & EXPLORATION
+COMPANY 
+(Registrant) 
+Date: February
+21, 2008 
+By: 
+/s/ ANTHONY J.
+BEST 
+Anthony
+J. Best 
+President,
+Chief Executive Officer, 
+and
+Director 
+GENERAL
+POWER OF ATTORNEY 
+KNOW ALL
+PERSONS BY THESE PRESENTS, that each person whose signature appears below
+constitutes and appoints each of Anthony J. Best and Mark T. Solomon his or her
+true and lawful attorney-in-fact and agent with full power of substitution and
+resubstitution, and each with full power to act alone, for the undersigned and
+in his or her name, place and stead, in any and all capacities, to sign any
+amendments to this Annual Report on Form 10-K for the fiscal year ended December
+31, 2007, and to file the same, with exhibits thereto and other documents in
+connection therewith, with the Securities and Exchange Commission, hereby
+ratifying and confirming all that each of said attorney-in-fact, or his
+substitute or substitutes, may do or cause to be done by virtue
+hereof. 
+Pursuant
+to the requirements of the Securities Exchange Act of 1934, this report has been
+signed below by the following persons on behalf of the registrant and in the
+capacities and on the dates indicated. 
+Signature 
+Title 
+Date 
+/ s/ ANTHONY J.
+BEST 
+President,
+Chief Executive Officer, 
+February
+21, 2008 
+Anthony
+J. Best 
+and
+Director 
+/s/ DAVID W.
+HONEYFIELD 
+Senior
+Vice President-Chief Financial 
+February
+21, 2008 
+David
+W. Honeyfield 
+Officer
+and Secretary 
+/s/ MARK T.
+SOLOMON 
+Controller 
+February
+21, 2008 
+Mark
+T. Solomon 
+/s/ MARK A.
+HELLERSTEIN 
+Chairman
+of the Board of Directors 
+February
+21, 2008 
+Mark
+A. Hellerstein 
+/s/ BARBARA M. BAUMANN 
+Director 
+February
+21, 2008 
+Barbara
+M. Baumann 
+/s/
+LARRY W. BICKLE 
+Director 
+February
+21, 2008 
+Larry
+W. Bickle 
+F-45 
+Signature 
+Title 
+Date 
+/s/ WILLIAM J.
+GARDINER 
+Director 
+February
+21, 2008 
+William
+J. Gardiner 
+/s/ JULIO M.
+QUINTANA 
+Director 
+February
+21, 2008 
+Julio
+M. Quintana 
+/s/ JOHN M.
+SEIDL 
+Director 
+February
+21, 2008 
+John
+M. Seidl 
+/s/ WILLIAM D.
+SULLIVAN 
+Director 
+February
+21, 2008 
+William
+D. Sullivan 
+F-46
\ No newline at end of file
diff --git a/raw/filings/0000893538/2007/0000893538-08-000013/filing_metadata.csv b/raw/filings/0000893538/2007/0000893538-08-000013/filing_metadata.csv
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index 0000000000000000000000000000000000000000..62b757877332ab040056594b18e38e0dcdf4a105
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+++ b/raw/filings/0000893538/2007/0000893538-08-000013/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000893538,SM,SM Energy Co,10-K,2008-02-22,2007-12-31,2008-02-22T21:33:34.000Z,0000893538-08-000013,form10k_123107.htm,FORM 10K,4103173,0,0,https://www.sec.gov/Archives/edgar/data/893538/000089353808000013/form10k_123107.htm,https://www.sec.gov/Archives/edgar/data/893538/000089353808000013/,2007,2007,1
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new file mode 100644
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diff --git a/raw/filings/0000893538/2007/0000893538-08-000013/item9a.txt b/raw/filings/0000893538/2007/0000893538-08-000013/item9a.txt
new file mode 100644
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diff --git a/raw/filings/0000893538/2007/0000893538-08-000013/rp_note.txt b/raw/filings/0000893538/2007/0000893538-08-000013/rp_note.txt
new file mode 100644
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diff --git a/raw/filings/0000893538/2007/0000893538-08-000013/rpt_disclosure.txt b/raw/filings/0000893538/2007/0000893538-08-000013/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..14e0e4c867ef819e073a53b4ff1eb49b7d463e34
--- /dev/null
+++ b/raw/filings/0000893538/2007/0000893538-08-000013/rpt_disclosure.txt
@@ -0,0 +1,35 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+Policy on Transactions with Related Persons 
+The Company has adopted a written policy and procedures for the Audit Committee's review of any transaction, arrangement, or
+relationship (including any indebtedness or guarantee of indebtedness) or series of similar transactions, arrangements, or relationships in which (i) the Company is a participant,
+(ii) the aggregate amount involved will or may be expected to exceed $120,000, and (iii) a related person has or will have a direct or indirect material interest. For purposes of this
+policy, a "related person" means (i) any of our directors, executive officers or nominees for director, (ii) any stockholder that beneficially owns more than five percent of the
+Company's outstanding shares of common stock, and (iii) any immediate family member of the foregoing. The Audit Committee approves or ratifies only those transactions that it determines in good
+faith are in, or are not inconsistent with, the best interests of the Company and its stockholders. 
+In
+determining whether to approve or ratify a transaction, the Audit Committee takes into account the factors it deems appropriate, which may include, among others, the benefits to the
+Company, the availability of other sources for comparable products or services, the impact on a director's independence in the event the related person is a director, and the extent of the related
+person's interest in the transaction. The policy also provides for the delegation of its authority to the Chairman of the Audit Committee for any related person transaction requiring
+pre-approval or ratification between meetings of the Audit Committee. The Audit Committee reviews and assesses ongoing relationships with a related person on at least an annual basis to
+see that they are in compliance with the policy and remain appropriate. 
+In
+addition, the By-Laws provide that no director, officer, or employee may pursue for his or her own account a business or investment opportunity if he or she has obtained
+knowledge of such opportunity through his or her affiliation with the Company. In addition, no officer or employee of St. Mary may pursue for his or her own account an oil and gas opportunity
+as to which his or her knowledge of the opportunity was not obtained through his or her affiliation with the Company unless (a) with respect to an officer of St. Mary, the officer's
+pursuit of the opportunity has been approved by the Board of Directors, and (b) with respect to a non-officer of St. Mary, the employee's pursuit of the opportunity has been
+approved by a senior officer of St. Mary with full knowledge of such opportunity. These restrictions do not apply to the acquisition of less than one percent of the publicly traded stock of
+another company. 
+Related Person Transactions 
+Set forth below is a description of a related transaction between St. Mary and one of its directors during the last fiscal year.
+Some of the aspects of this transaction will continue in effect and may result in conflicts of interest between St. Mary and the individual. We cannot assure you that conflicts of interest will
+always be resolved in favor of St. Mary. 
+Mr. Hellerstein,
+who currently serves as Chairman of the Board of Directors of St. Mary and is retiring from the Board of Directors effective at the annual meeting on
+May 20, 2009, is a participant in the NPP as a result of his prior service to the Company as an executive officer, including service as President from 1992 to June 2006 and Chief Executive
+Officer from 1995 to February 2007. As a result of Mr. Hellerstein's vested participation interests in the NPP arising from his prior service, the Company made NPP payments to
+Mr. Hellerstein during 2008 in the total amount of $6,172,098. The Audit Committee has reviewed this relationship and determined that it is not in conflict with the Company's Policies and
+Procedures with Respect to Related Person Transactions, since Mr. Hellerstein's NPP participation interests were awarded to him while he was an employee of St. Mary in order to provide
+for future incentive bonus compensation for his services as an executive officer. For a description of the NPP, please see the section entitled "Net Profits Interest Bonus Plan (NPP)" in the
+"Compensation Discussion and Analysis" section of this proxy statement. 
+54 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000893538/2009/0000893538-10-000011/filing.txt b/raw/filings/0000893538/2009/0000893538-10-000011/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..0c7f16f6100a0d1aac060fc828b407212116d8ea
--- /dev/null
+++ b/raw/filings/0000893538/2009/0000893538-10-000011/filing.txt
@@ -0,0 +1,15964 @@
+10-K
+1
+form10k_123109.htm
+12/31/09 FORM 10-K
+form10k_123109.htm 
+UNITED
+STATES 
+SECURITIES
+AND EXCHANGE COMMISSION 
+Washington,
+D.C. 20549 
+FORM
+10-K 
+þ Annual
+Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
+1934 
+For the
+fiscal year ended December 31, 2009 
+or 
+o Transition
+Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
+1934 
+Commission
+file number 001-31539 
+ST.
+MARY LAND & EXPLORATION COMPANY 
+(Exact
+name of registrant as specified in its charter) 
+Delaware 
+(State
+or other jurisdiction 
+of
+incorporation or organization) 
+41-0518430 
+(I.R.S.
+Employer Identification No.) 
+1776
+Lincoln Street, Suite 700, Denver, Colorado 
+(Address
+of principal executive offices) 
+80203 
+(Zip
+Code) 
+(303)
+861-8140 
+(Registrant’s
+telephone number, including area code) 
+Securities
+registered pursuant to Section 12(b) of the Act: 
+Title
+of each class 
+Name
+of each exchange on which registered 
+Common
+stock, $.01 par value 
+New
+York Stock Exchange 
+Securities
+registered pursuant to Section 12(g) of the Act: None 
+Indicate
+by check mark if the registrant is a well-known seasoned issuer, as defined in
+Rule 405 of the Securities Act. Yes þ No
+o 
+Indicate
+by check mark if the registrant is not required to file reports pursuant to
+Section 13 or Section 15(d) of the Act. Yes o No
+þ 
+Indicate
+by check mark whether the registrant (1) has filed all reports required to be
+filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
+preceding 12 months (or for such shorter period that the registrant was required
+to file such reports), and (2) has been subject to such filing requirements for
+the past 90 days. Yes þ No o 
+Indicate
+by check mark whether the registrant has submitted electronically and posted on
+its corporate Web site, if any, every Interactive Data File required to be
+submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
+chapter) during the preceding 12 months (or for such shorter period that the
+registrant was required to submit and post such files). 
+Yes o No o 
+Indicate
+by check mark if disclosure of delinquent filers pursuant to Item 405 of
+Regulation S-K is not contained herein, and will not be contained, to the best
+of registrant’s knowledge, in definitive proxy or information statements
+incorporated by reference in Part III of this Form 10-K or any amendment to this
+Form 10-K. o 
+Indicate
+by check mark whether the registrant is a large accelerated filer, an
+accelerated filer, a non-accelerated filer, or a smaller reporting
+company. See the definitions of “large accelerated filer,”
+“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
+Exchange Act. 
+Large
+accelerated filer þ 
+Accelerated
+filer o 
+Non-accelerated
+filer o (Do
+not check if a smaller reporting company) 
+Smaller
+reporting company o 
+Indicate
+by check mark whether the registrant is a shell company (as defined in Rule
+12b-2 of the Exchange Act). Yes o No þ 
+The
+aggregate market value of the 62,106,243 shares of voting stock held by
+non-affiliates of the registrant, based upon the closing sale price of the
+common stock on June 30, 2009, the last business day of the registrant’s most
+recently completed second fiscal quarter, for $20.87 per share as reported on
+the New York Stock Exchange was $1,296,157,291. Shares of common
+stock held by each director and executive officer and by each person who owns 10
+percent or more of the outstanding common stock or who is otherwise believed by
+the Company to be in a control position have been excluded. This
+determination of affiliate status is not necessarily a conclusive determination
+for other purposes. 
+As of
+February 16, 2010, the registrant had 62,777,688 shares of common stock
+outstanding, which is net of 126,893 treasury shares held by the
+Company. 
+DOCUMENTS
+INCORPORATED BY REFERENCE 
+Certain
+information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated
+by reference from portions of the registrant’s definitive proxy statement
+relating to its 2010 annual meeting of stockholders to be filed within 120 days
+after December 31, 2009. 
+TABLE OF CONTENTS 
+ITEM 
+PAGE 
+PART
+I 
+ITEMS
+1. and 2. 
+BUSINESS
+and
+PROPERTIES 
+1 
+General 
+1 
+Strategy 
+1 
+Significant Developments in
+2009 
+1 
+Outlook for
+2010 
+4 
+Assets 
+4 
+Reserves 
+9 
+Production 
+13 
+Productive
+Wells 
+14 
+Drilling
+Activity 
+14 
+Acreage 
+15 
+Delivery
+Commitments 
+15 
+Major
+Customers 
+16 
+Employees and Office
+Space 
+16 
+Title to
+Properties 
+16 
+Seasonality 
+16 
+Competition 
+16 
+Government
+Regulations 
+17 
+Cautionary Information about
+Forward-Looking Statements 
+18 
+Available
+Information 
+20 
+Glossary of Oil and Natural Gas
+Terms 
+21 
+ITEM
+1A. 
+RISK
+FACTORS 
+26 
+ITEM
+1B. 
+UNRESOLVED
+STAFF
+COMMENTS 
+39 
+ITEM
+3. 
+LEGAL
+PROCEEDINGS 
+39 
+ITEM
+4. 
+SUBMISSION
+OF MATTERS TO A VOTE OF SECURITY 
+HOLDERS 
+39 
+ITEM
+4A. 
+EXECUTIVE
+OFFICERS OF THE
+REGISTRANT 
+39 
+PART
+II 
+ITEM
+5. 
+MARKET
+FOR REGISTRANT’S COMMON EQUITY, 
+RELATED
+STOCKHOLDER MATTERS AND ISSUER 
+PURCHASES
+OF EQUITY
+SECURITIES 
+43 
+ITEM
+6. 
+SELECTED
+FINANCIAL
+DATA 
+48 
+ITEM
+7. 
+MANAGEMENT’S
+DISCUSSION AND ANALYSIS OF 
+FINANCIAL
+CONDITION AND RESULTS OF OPERATIONS 
+50 
+Overview of the
+Company 
+50 
+Financial Results of Operations
+and Additional Comparative Data 
+58 
+Comparison of Financial Results
+and Trends between 
+2009 and
+2008 
+62 
+Comparison of Financial Results
+and Trends between 
+2008 and
+2007 
+66 
+Overview of Liquidity and
+Capital
+Resources 
+68 
+Critical Accounting Policies
+and
+Estimates 
+79 
+Other Liquidity and Capital
+Resources
+Information 
+82 
+Accounting
+Matters 
+82 
+Environmental 
+82 
+Climate
+Change 
+83 
+TABLE OF CONTENTS 
+(Continued) 
+ITEM 
+PAGE 
+ITEM
+7A. 
+QUANTITATIVE
+AND QUALITATIVE DISCLOSURES ABOUT 
+MARKET
+RISK (included with the content of ITEM
+7) 
+85 
+ITEM
+8. 
+FINANCIAL
+STATEMENTS AND SUPPLEMENTARY DATA 
+85 
+ITEM
+9. 
+CHANGES
+IN AND DISAGREEMENTS WITH ACCOUNTANTS 
+ON
+ACCOUNTING AND FINANCIAL
+DISCLOSURE 
+85 
+ITEM
+9A. 
+CONTROLS
+AND
+PROCEDURES 
+85 
+ITEM
+9B. 
+OTHER
+INFORMATION 
+88 
+PART
+III 
+ITEM
+10. 
+DIRECTORS,
+EXECUTIVE OFFICERS AND CORPORATE 
+GOVERNANCE 
+88 
+ITEM
+11. 
+EXECUTIVE
+COMPENSATION 
+88 
+ITEM
+12. 
+SECURITY
+OWNERSHIP OF CERTAIN BENEFICIAL 
+OWNERS
+AND MANAGEMENT AND RELATED 
+STOCKHOLDER
+MATTERS 
+88 
+ITEM
+13. 
+CERTAIN
+RELATIONSHIPS AND RELATED TRANSACTIONS, 
+AND
+DIRECTOR
+INDEPENDENCE 
+88 
+ITEM
+14. 
+PRINCIPAL
+ACCOUNTANT FEES AND
+SERVICES 
+89 
+PART
+IV 
+ITEM
+15. 
+EXHIBITS
+AND FINANCIAL STATEMENT SCHEDULES 
+89 
+PART
+I 
+When we
+use the terms “St. Mary,” “the Company,” “we,” “us,” or “our,” we are referring
+to St. Mary Land & Exploration Company and its subsidiaries, unless the
+context otherwise requires. We have included technical terms
+important to an understanding of our business under “Glossary of Oil and Natural
+Gas Terms.” Throughout this document we make statements that are
+classified as “forward-looking.” Please refer to the “Cautionary
+Information about Forward-Looking Statements” section of this document for an
+explanation of these types of statements. 
+ITEMS
+1. and 2. BUSINESS and PROPERTIES 
+General 
+We are an
+independent oil and gas company engaged in the exploration, exploitation,
+development, acquisition, and production of natural gas and crude oil in North
+America. We were founded in 1908 and incorporated in Delaware in
+1915. Our initial public offering of common stock took place in
+December 1992. The common stock of the Company trades on the New York
+Stock Exchange under the ticker “SM.” 
+Our
+principal offices are located at 1776 Lincoln Street, Suite 700, Denver,
+Colorado 80203, and our telephone number is (303) 861-8140. 
+Strategy 
+Our
+mission is to deliver outstanding net asset value per share growth to our
+investors via attractive oil and gas investments. Historically, a key
+part of meeting the goal of building stockholder value was the successful
+execution and integration of niche acquisitions at attractive
+costs. Recently we shifted the emphasis of our efforts to focus on
+the exploration for and development of onshore resource plays in North
+America. This shift was due to the fact that, as we grew, the
+universe of potential niche acquisition targets became smaller and less
+impactful to our growth. Additionally, we believe that we will be
+able to create more long-term value for our stockholders by building an asset
+base that allows for more predictable growth in production and reserves and does
+not rely solely on acquisitions. Our strategy is based on the
+following points: 
+· 
+Acquire
+significant leasehold positions in new and emerging resource
+plays 
+· 
+Leverage
+our core competencies in drilling and completions, as well as
+acquisitions 
+· 
+Exploit
+our legacy assets and optimize our asset base through divestitures of
+non-core assets when appropriate 
+· 
+Maintain
+a strong balance sheet while funding the growth of the
+enterprise. 
+Significant
+Developments in 2009 
+· 
+Broad Economic
+Downturn. Beginning in the latter part of 2008 and
+continuing into the first half of 2009 the global economy experienced a
+significant downturn related primarily to concerns over the U.S. financial
+system. The impact of the downturn spread quickly and affected
+a wide range of industries. There were two significant
+ramifications to the exploration and production industry. The
+first was that capital markets were essentially frozen at the beginning of
+2009. Equity, debt, and credit markets were shut
+down. We were able to weather this initial shock as a result of
+our strong liquidity position and relatively limited capital
+commitments. The second impact to the industry was that fear of
+global recession and the associated negative impact on energy demand
+resulted in a significant decline in oil and gas prices. We
+significantly scaled back our operating activity in response to these
+price decreases. Our hedging program helped moderate the price
+fluctuations that we experienced, particularly in the first half of
+2009. After the first quarter of 2009, the broader economy
+began to stabilize. The public markets for debt and equity
+opened up and banks began to be 
+1 
+less
+restrictive with credit. We were able to renew our credit
+facility in April of 2009. The outlook for commodity prices
+also began to improve. The rapid decrease in activity across
+the exploration and production industry led many oilfield service
+companies to cut their prices to the benefit of ourselves and our peers as
+the year progressed. As industry conditions improved throughout
+the year, drilling activity increased in many parts of the
+country. 
+· 
+Advancement of Resource Play
+Potential. From late 2007 through 2009, we established
+meaningful positions in several new potential resource plays, principally
+the Eagle Ford shale, Haynesville shale, and the Marcellus
+shale. Over the past year we worked to advance our
+understanding of these plays and move them closer to development
+mode. The greatest progress was made in our Eagle Ford shale
+program in South Texas. We successfully tested seven wells
+across our operated acreage position during the second half of
+2009. The early results from this program suggest wells at the
+southern end of our acreage will produce drier gas while wells drilled
+further north will produce higher BTU-content gas and
+condensate. We are currently booking only the parallel offsets
+to producing wells as proved undeveloped locations. As a
+result, meaningful potential exists to grow proved reserves on our
+operated acreage because of our planned drilling activity for
+2010. On our joint venture acreage in Dimmitt County, Texas, we
+believe these wells will produce even higher amounts of condensate and oil
+compared to our operated position. In the Haynesville shale
+program in the ArkLaTex region, a number of successful wells were drilled
+around our acreage position in Shelby and San Augustine counties in East
+Texas in 2009. The 3D seismic shoot of our acreage was recently
+received, and we have begun our horizontal drilling in the
+play. In our Marcellus shale program in north central
+Pennsylvania, we drilled and completed our first two horizontal wells
+during 2009. Initial indications from the well tests were
+encouraging. We are in the process of constructing the
+gathering system that will connect these two wells, as well as future
+wells, to the sales pipeline. 
+· 
+Volatility in Commodity
+Prices. Prices in 2009 were generally more stable than
+in 2008. However the exploration and production sector still
+experienced significant volatility in the prices for crude oil and natural
+gas. Our operations and financial condition are significantly
+impacted by these prices. The spot price for NYMEX crude oil in
+2009 ranged from a high of $81.04 per barrel in October to a low of $33.98
+per barrel in February. The average spot price for oil during
+the year was $61.99 per barrel. The volatility in crude oil
+prices in early 2009 was driven by concern regarding global demand for
+oil. A volatile U.S. dollar was also a contributing factor in
+crude price volatility as the spot price of oil reacted to the relative
+weakening or strengthening of the U.S.
+dollar. 
+The spot
+price for gas at Henry Hub, a widely used industry measuring point, averaged
+$3.94 per MMBtu in 2009, with a high of $6.11 per MMBtu in January and a
+low of $1.88 per MMBtu in September. Natural gas prices came
+under pressure in 2009 as a result of lower domestic product demand caused by
+the weakening economy; and concerns over excess supply of natural gas due to the
+high productivity of several emerging shale plays in the U.S. Some of
+the regional markets where we sell gas have seen increased downward pressures on
+price as a result of high levels of activity in the regions, as well as a lack
+of pipeline takeaway capacity or local demand. This was most
+pronounced in our Mid-Continent and Rocky Mountain regions. However,
+local index differentials, in the areas where we sell gas, narrowed towards
+NYMEX Hub prices in late 2009. 
+· 
+Decrease in Year-End Proved
+Reserve Estimates. Our estimated proved reserves
+decreased 11 percent to 772.2 BCFE at December 31, 2009, from
+865.5 BCFE at December 31, 2008. We
+added 109.6 BCFE from our drilling program during the year, with our
+emerging resource play in the Eagle Ford shale in the Maverick Basin in
+South Texas contributing a significant portion of those
+additions. Our programs targeting the Woodford shale in eastern
+Oklahoma and the Bakken/Three Forks formations in the North Dakota portion
+of the Williston Basin also added meaningful additions in
+2009. We sold 44.2 BCFE of proved reserves during the year,
+with roughly 90 percent of those relating to the divestiture of our
+coalbed methane project at Hanging Woman Basin along the border of Montana
+and Wyoming. The balance of the divested properties sold in
+2009 related to non-strategic assets spread across our
+company. 
+2 
+We had a
+net downward revision of 49.6 BCFE that consisted of 61.6 BCFE in downward
+engineering revisions and an upward pricing revision of 12.0
+BCFE. The largest portion of the performance revision relates to
+producing properties in our Wolfberry tight oil program in the Permian Basin in
+West Texas. Well performance data collected during 2009 at our
+Sweetie Peck and Halff East programs that target the Wolfberry interval indicate
+that these assets are underperforming our year-end 2008 decline
+forecasts. Accordingly, we removed 37 BCFE from proved reserves in
+the Permian region, primarily related to the Wolfberry tight oil
+program. We believe a significant portion of these reserves, while
+not meeting the criteria to be booked as proved reserves at year-end, are likely
+to eventually be produced. We also had a downward performance
+revision of approximately 12 BCFE related to certain Cotton Valley assets in our
+ArkLaTex region. The pricing methodology used to determine proved
+reserves changed in 2009 in accordance with new rules promulgated by the
+SEC. Rather than using year-end pricing, companies are now required
+to use the 12-month average of the first of month prices for oil and gas to
+estimate proved reserves. This change in methodology from 2008
+resulted in a higher oil price and a lower gas price in effect for determining
+year-end proved reserves for 2009. As a result, we recognized
+positive pricing revisions in our oil-weighted Rocky Mountain and Permian
+regions that offset the negative price revisions we recognized in the natural
+gas weighted Mid-Continent, ArkLaTex, and South Texas & Gulf Coast
+regions. Under the previous methodology of using year-end pricing for
+the determination of proved reserves, we would have had a four percent increase
+in proved reserves to approximately 897 BCFE. 
+Prior to
+and subsequent to year-end, we entered into several transactions to divest
+non-strategic properties across our company. Proved reserves
+associated with these properties are estimated to be approximately 71 BCFE and
+primarily relate to the previously announced Rocky Mountain oil property
+divestiture. Part of this divestiture package closed in mid-February
+2010 and we expect the balance to close by the end of the first quarter of
+2010. 
+· 
+Impairment of Proved
+Properties. We recognized pre-tax non-cash impairments
+of proved properties in the amount of $174.8 million in 2009 compared with
+$302.2 million of proved property impairments in 2008. A
+significant decrease in commodity prices, including differentials, during
+the first quarter of 2009 caused the majority of the non-cash
+impairment. The largest portion of the impairment in 2009 was
+$97.3 million related to assets located in the Mid-Continent region which
+were significantly impacted by both low natural gas prices and wider than
+normal differentials at the end of the first quarter. The
+ArkLaTex region was impacted by a $20.4 million impairment related to
+downward pricing and engineering revisions. We incurred a $14.0
+million impairment of proved properties related to the write-down of
+certain assets located in the Gulf of Mexico for which we are
+relinquishing our ownership interests to satisfy our abandonment
+obligations. 
+· 
+Abandonment and Impairment of
+Unproved Properties. During the year, we abandoned or
+impaired $45.4 million related to unproved properties. The
+largest specific components of the 2009 impairment and abandonment related
+to the Floyd Shale acreage located in Mississippi and acreage in
+Oklahoma. The remaining write-offs were related to acreage
+we
+believe we will not keep based on our current capital allocation plans or
+related to acreage that we do not believe will be
+prospective. 
+· 
+Divestiture of Non-Strategic
+Properties. In 2009 we undertook an effort to sell a
+number of non-strategic properties in order to optimize our
+portfolio. The objective of these divestitures is to dispose of
+properties with limited future drilling potential while generating cash
+that can be used in the testing and development of our resource
+plays. During 2009 we sold roughly 44.2 BCFE of reserves, the
+vast majority of which related to our coalbed methane program in Hanging
+Woman Basin. We received $39.9 million in proceeds from
+the sales we closed in 2009. Subsequent to year end, we closed
+on a portion of our previously disclosed sale of non-strategic oil and gas
+properties in the Rocky Mountain region. The Wyoming
+sub-package was sold to Legacy Reserves Operating LP. The cash
+received at closing was $118.7 million before commission costs. The
+final sales price is subject to normal post-closing adjustments and is
+expected to be finalized by the end of second quarter of
+2010. Additionally, subsequent to year-end, we also entered
+into agreements to sell the 
+3 
+remaining
+non-core properties from our Rocky Mountain divestiture package in North
+Dakota for $137 million to Sequel Energy Partners LP, as well as some
+other minor properties for approximately $6 million. We expect
+these divestitures to close by the end of the first quarter of
+2010. In total, these divestitures represent 71 BCFE of proved
+reserves. 
+Outlook
+for 2010 
+The
+general economic outlook for the country has improved compared to this time a
+year ago. We successfully weathered a rough 2009, and in the process
+advanced a number of potential resource plays and improved our financial
+condition. 
+As we
+enter 2010, our company is well positioned both financially and
+operationally. Early in 2009, we extended the maturity of our
+revolving credit facility and subsequently reduced outstanding borrowings on
+that facility during the year. As of February 16, 2010, we had $467
+million available to us under the revolving credit facility. We have
+no debt maturities until 2012. Additionally, we believe that access
+to the capital markets has improved significantly since last year and that we
+could access capital through the public markets, if necessary. From
+an operational standpoint, we believe 2010 has the potential to be very
+promising for our company. We will be building upon our successful
+testing programs from 2009. We have moved the Eagle Ford shale
+program closer to development mode, and it will receive the largest portion of
+our capital budget this year. We will also be allocating more capital
+toward oil and rich natural gas projects, given their higher returns in the
+current environment. Specifically, we will be drilling more Wolfberry
+tight oil and Bakken/Three Forks wells in the Permian and Rocky Mountain
+regions, respectively. In the Haynesville shale, we have begun our
+horizontal drilling program. We continue to monitor service
+costs as the recent uptick in industry activity may pressure rates for the
+drilling and completion of wells higher than the levels we saw in
+2009. We intend to fund these projects with our current year
+operating cash flows and proceeds from our previously announced non-core
+divestitures. 
+Assets 
+As of
+December 31, 2009, we had estimated proved reserves of 53.8 MMBbl of oil and
+449.5 Bcf of natural gas. The 12-month average prices in effect on
+December 31, 2009, used to estimate proved reserves were $61.18 per barrel of
+oil and $3.87 per MMBtu of gas, which represent a 37 percent increase and 32
+percent decrease, respectively, from prices used to estimate proved reserves as
+of December 31, 2008. On an equivalent basis, our proved reserves
+were 772.2 BCFE as of December 31, 2009, a decrease of 11 percent from
+865.5 BCFE at the end of the prior year. On an equivalent basis, 82
+percent of our proved reserves were classified as proved developed as of
+year-end. Total proved oil and gas reserves had a PV-10 value of $1.3
+billion and a standardized measure value of $1.0 billion including the effect of
+income taxes. A reconciliation between these two amounts is shown
+under the Reserves section in Part I, Items 1 and 2 of this
+report. During 2009 our average daily production was 194.8 MMcf of
+gas and 17.3 MBbl of oil, for an
+average equivalent production rate of 298.8 MMCFE per day, which was down
+slightly compared with 313.1 MMCFE per day for 2008. Adjusting for
+production from properties sold as part of our active divestiture efforts over
+the last two years, production from retained properties has remained essentially
+flat from 285.6 MMCFE per day in 2008 to 284.7 MMCFE per day in
+2009. 
+In 2009 we incurred costs of $419.0 million for drilling and
+exploration activities and acquisitions. This was 51 percent lower
+than the $857.7 million incurred in 2008. During 2009 we incurred
+exploration costs of $154.1 million compared to $92.2 million in
+2008. We incurred development costs of $223.1 million in 2009, which
+was 62 percent lower than the $587.6 million in 2008. The decrease in
+development dollars and increase in exploration dollars reflects our decision to
+not invest capital in development projects in a low commodity price environment,
+particularly while service costs were declining. Moreover we ramped
+up our exploration efforts to accelerate our understanding of our emerging
+resource plays, particularly in the Eagle Ford shale, in order to put ourselves
+in a positive position once industry conditions improved. In 2009 we
+invested a total of $41.7 million on undeveloped leasehold compared to
+$83.1 million in 2008. The majority of our 2009 leasing activity
+targeted emerging resource plays in our South Texas & Gulf Coast and
+Mid-Continent regions. We spent approximately $126.4 million in 2008
+on undeveloped leasehold, including leasehold acquired as part of producing
+property 
+4 
+acquisitions,
+targeting the Cotton Valley and Bakken formations in the ArkLaTex and Rocky
+Mountain regions, respectively. In 2009, we did not make any
+meaningful acquisitions. 
+Our
+operations are currently concentrated in five core operating areas in the United
+States. The following table summarizes the production, proved
+reserves, and PV-10 value of our core operating areas as of
+December 31, 2009. 
+ArkLaTex 
+Mid- 
+Continent 
+South
+Texas & Gulf Coast 
+Permian 
+Rocky 
+Mountain 
+Total (1)
+(2) 
+2009
+Proved Reserves 
+Oil
+(MMBbl) 
+0.4 
+1.1 
+1.4 
+14.2 
+36.7 
+53.8 
+Gas
+(Bcf) 
+117.8 
+216.7 
+44.9 
+30.1 
+40.0 
+449.5 
+Equivalents
+(BCFE) 
+120.0 
+223.5 
+53.2 
+115.2 
+260.3 
+772.2 
+Relative
+percentage 
+15% 
+29% 
+7% 
+15% 
+34% 
+100% 
+Proved
+Developed % 
+65% 
+83% 
+53% 
+83% 
+93% 
+82% 
+PV-10
+Values (in millions) 
+Proved
+Developed 
+$ 
+92.1 
+$ 
+266.3 
+$ 
+50.5 
+$ 
+295.5 
+$ 
+548.7 
+$ 
+1,253.1 
+Proved
+Undeveloped (3) 
+0.1 
+(7.4 
+) 
+(2.0 
+) 
+34.9 
+5.4 
+31.0 
+Total
+Proved 
+$ 
+92.2 
+$ 
+258.9 
+$ 
+48.5 
+$ 
+330.4 
+$ 
+554.1 
+$ 
+1,284.1 
+Relative
+percentage 
+7% 
+20% 
+4% 
+26% 
+43% 
+100% 
+2009
+Production 
+Oil
+(MMBbl) 
+0.1 
+0.3 
+0.4 
+1.8 
+3.7 
+6.3 
+Gas
+(Bcf) 
+14.2 
+34.4 
+7.2 
+4.1 
+11.2 
+71.1 
+Equivalent
+(BCFE) 
+14.9 
+36.0 
+9.7 
+15.2 
+33.3 
+109.1 
+Avg.
+Daily Equivalents 
+(MMCFE/d) 
+40.8 
+98.7 
+26.6 
+41.5 
+91.2 
+298.8 
+Relative
+percentage 
+14% 
+33% 
+9% 
+14% 
+30% 
+100% 
+(1) 
+Totals
+may not add due to rounding. 
+(2) 
+Included
+in the total are approximately 71 BCFE related to non-core properties that
+we have either divested or entered into agreements to divest subsequent to
+December 31, 2009. 
+(3) 
+St.
+Mary will record proved undeveloped locations with a negative PV-10 value
+if we have intent to drill the well provided it generates positive net
+undiscounted cash flow and meets our economic criteria based on our
+corporate price call. 
+ArkLaTex
+Region. St. Mary’s operations in the ArkLaTex region are
+managed from our office in Shreveport, Louisiana. The ArkLaTex region
+was our first operating office, originating from an acquisition in
+1992. For years the activities of this region focused on the Cotton
+Valley, James Lime, and Travis Peak formations in the region. In 2008
+the Haynesville shale emerged as the leading potential resource play in East
+Texas and North Louisiana. 
+The
+ArkLaTex region incurred costs of $65.7 million in 2009 for exploration,
+development, and acquisition activities. This amount is 70 percent
+lower than the $218.4 million spent in 2008, which included $60.3 million in
+acquisitions targeting the Cotton Valley formation in East
+Texas. Significantly less money was spent on development and
+exploration activity in 2009 compared to 2008. With the emergence of
+the Haynesville shale late in 2008 and into 2009, our operating partner activity
+targeting the Cotton Valley and James Lime formations declined significantly as
+they focused on testing and developing their Haynesville shale
+properties. We participated in a number of partner-operated wells
+that focused on the Haynesville shale. Additionally, we elected to
+defer most of our operated horizontal Haynesville drilling until we could
+acquire seismic data that would help mitigate risk for larger parts of our
+acreage. Our 2009 operated activity in the ArkLaTex region was
+primarily focused on drilling wells that preserve acreage. The
+region’s 2009 production decreased 19 percent to 14.9 BCFE as a result of the
+lower levels of activity described above. Our 2009 year-end proved
+reserves were 120.0 BCFE, which is 29 percent lower than the 2008 year-end
+proved reserves of 170.0 BCFE. The decrease in 
+5 
+proved
+reserves is primarily the result of 14.9 BCFE of production and 48.0 BCFE
+of negative pricing and engineering revisions. At year-end 2009 we
+have no proved reserves booked for our Haynesville potential related to our
+acreage in Shelby and San Augustine Counties in East Texas. 
+The Elm
+Grove Field is the highest value field in the ArkLaTex region at year-end
+2009. We own interests in approximately 500 producing wells in the
+field and believe many of those wells have future uphole recompletion
+potential. Our working interest in the field is as high as 36
+percent, although it varies greatly across the field. Generally, our
+working interest increases as one moves south in the field. The
+primary zones of interest in this field have historically been the Cotton Valley
+and Hosston. The vast majority of the value and proved reserves in
+this field relate to those zones. Over the past year, our operating
+partner has focused its drilling efforts almost exclusively in the Haynesville
+shale on acreage in the field where we have no working interest. As a
+result, we have very little PV-10 value or proved reserve volumes attributable
+to the Haynesville shale at the end of 2009 at Elm Grove field. 
+Our plans
+for 2010 in the ArkLaTex region are based almost entirely on testing and
+developing the Haynesville shale on our operated acreage. We have
+approximately 41,000 net acres across the region with potential for the
+Haynesville shale, of which 31,000 is located in Shelby and San Augustine
+Counties in East Texas. Roughly 70 percent of our Haynesville
+spending will be operated by us and will be focused on our acreage in these
+counties. We plan to drill seven horizontal wells targeting the
+Haynesville shale in 2010. We will also participate in a number of
+wells with operating partners in both northern Louisiana and East Texas that
+target the Haynesville interval. We expect that we will invest a
+minimal amount of capital this year on the drilling of James Lime and Cotton
+Valley wells, although we will have some leasehold and seismic expenditures
+related to those programs in 2010. In recent months, the industry has
+begun to test the Bossier shale, which is above the Haynesville
+shale. As information emerges about this interval, we could choose to
+test this formation in 2010. We believe a large portion of our
+acreage position in East Texas is also prospective for the Bossier
+shale. 
+Mid-Continent
+Region. St. Mary has been active in the Mid-Continent region
+since 1973. Operations for the region are managed by our office in
+Tulsa, Oklahoma. We have been active in the Anadarko Basin of western
+Oklahoma since our entry into the region. In recent years we have
+begun operating in the Arkoma Basin in eastern Oklahoma where the current focus
+is on horizontal development of the Woodford shale. The Mid-Continent
+region also oversees our Marcellus shale activity in north central
+Pennsylvania. 
+In 2009
+we incurred costs of $106.8 million in the Mid-Continent region for exploration,
+development, and acquisition activity, which is 34 percent less than the $162.0
+million deployed in 2008. Approximately
+$97 million was deployed in exploration and development activities in 2009,
+with the remainder being spent on leasing activities. The 2009
+activity for the region focused on the continued development of our horizontal
+Woodford shale program in the Arkoma Basin and included the successful
+completion of two pilot programs to test the effect of near simultaneous
+fracture stimulation on increased density drilling. In the Anadarko
+Basin, we maintained a consistent level of operated activity targeting the Deep
+Springer formation throughout the year. We also participated in a
+largely non-operated program targeting the stacked washes in western
+Oklahoma. Lastly, we drilled and completed our first initial tests in
+our Marcellus shale program during the second half of
+2009. Mid-Continent production in 2009 was 36.0 BCFE, an increase of
+9 percent from the 33.0 BCFE produced in 2008. Proved reserves at the
+end of 2009 were 223.5 BCFE, a decrease of five percent from the 234.4 BCFE
+report for the prior year. The decrease in proved reserves was due in
+large part to the low gas price in effect at year end which resulted in downward
+pricing revisions of roughly 17 BCFE for some previously booked proved
+reserves. The low gas price also resulted in no new proved
+undeveloped reserves being added in the region at December 31,
+2009. 
+The
+Centrahoma Field in the Arkoma Basin is the highest value field in the
+Mid-Continent region. At year-end, we have nearly 160 producing wells
+in the field. Over half of those wells were completed in the Woodford
+shale and the majority of those were drilled horizontally. The
+Woodford shale is the primary contributor to proved reserve volumes and PV-10
+value at the Centrahoma Field. We believe there is additional
+drilling potential in the Woodford shale as well as uphole development in the
+Cromwell and Wapanucka formations. 
+6 
+The
+largest operated portion of the Mid-Continent region’s budget for 2010 relates
+to our emerging program targeting the Marcellus shale in north central
+Pennsylvania. We currently have roughly 42,000 net acres leased or
+optioned in the Marcellus shale. Four operated horizontal wells are
+planned for the year and we expect to begin drilling late in the second quarter
+of 2010. Additionally, we are currently in the process of
+constructing a gathering system through a large portion of our acreage position
+that will connect the first two wells we drilled in 2009 to sales as well as
+service future development. Our Marcellus program for 2010 also
+includes amounts for leasehold, facilities, and seismic costs. In the
+horizontal Woodford, our program for 2010 is primarily designed to preserve core
+acreage. Six operated horizontal wells are currently planned, and we
+will participate in a handful of wells that will be operated by
+others. In the Anadarko Basin, we have four wells planned in the
+successful Deep Springer program our regional team has run for the past several
+years. Four operated horizontal wells are planned for the horizontal
+Granite Wash play that is emerging in western Oklahoma. Our first
+horizontal Granite Wash well in this part of the play commenced drilling in
+December of 2009 and is still drilling as of the date of this
+report. 
+South Texas &
+Gulf Coast Region. St. Mary’s presence in south Louisiana
+dates to the early 1900s when our founders acquired our namesake property in St.
+Mary Parish, Louisiana abutting the Gulf of Mexico. These 24,914
+acres of fee land yielded $3.6 million of oil and gas royalty revenue in
+2009. Our presence expanded along the Gulf Coast as a result of the
+acquisition of King Ranch Energy, Inc. in 1999. In 2007, we made two
+acquisitions in the Maverick Basin in South Texas that targeted Olmos shallow
+gas assets in South Texas and provided an entry into this multi-pay
+basin. During 2009, one of the other zones of interest, the Eagle
+Ford shale, was successfully tested by St. Mary and a
+competitor. Today, the Eagle Ford shale is one of the most promising
+shale plays in North America. The focus of our Houston office has
+steadily shifted over the last couple of years away from projects along the Gulf
+Coast and in the Gulf of Mexico toward programs onshore that allow for multiple
+years of drilling inventory. 
+Our
+capital expenditures for exploration, development, and acquisition activity in
+the South Texas & Gulf Coast region decreased slightly from $120.9 million
+in 2008 to $115.1 million in 2009. Nearly all of the capital deployed
+in the South Texas & Gulf Coast region in 2009 targeted formations in south
+western Texas, namely the Eagle Ford and Pearsall shales. We worked
+early in the year to increase our leasehold position in the
+area. Additionally, we continued to participate in a joint venture
+that allowed us to earn acreage by carrying a partner through completion in a
+series of wells. In mid-2009, we began operating on acreage where we
+had very high working interests, in many cases a 100 percent. The
+encouraging
+results from our earlier tests led to an increase in the number of
+wells drilled for 2009. To date, the results on our operated acreage
+have been very encouraging. On large parts of our acreage, we have
+seen rich-gas and condensate in the production stream which enhances the
+economics of these gas wells. We did not make any meaningful
+investments in properties along the Gulf Coast or in the Gulf of Mexico during
+the year. Our last operated platform in the Gulf of Mexico was
+largely remediated and abandoned in 2009 after being damaged by Hurricane Ike in
+2008. 
+Production
+for the South Texas & Gulf Coast region in 2009 was 9.7 BCFE, a decrease of
+32 percent from the 14.3 BCFE produced in 2008. The largest
+contributor to the decline year over year was the result of our sale of our
+interest in the Judge Digby Field in southern Louisiana at the end of
+2008. Excluding the impact of this divestiture, production declined
+approximately one percent year over year. Proved reserves at the end
+of 2009 were 53.2 BCFE, an increase of 21 percent from the 43.8 BCFE reported in
+the prior year. The increase in proved reserves reflects drilling
+additions of 39.0 BCFE related entirely to our program in the Eagle Ford shale
+and were offset by downward price revisions related to our Olmos gas
+program. On our operated acreage targeting the Eagle Ford shale, we
+had seven proved developed wells which were producing at
+year-end. This program is at an early stage of its development and
+accordingly at December 31, 2009, we are booking only parallel offset locations
+to our producing wells as proved undeveloped locations. The result is
+a total of 14 proved undeveloped locations being booked as of year-end at a
+total of 24.6 BCFE. Our operated Eagle Ford program is the most
+significant asset in the South Texas & Gulf Coast region. 
+Our plans
+for 2010 in the South Texas & Gulf Coast region are focused exclusively on
+the Eagle Ford shale. As of year-end, we have 250,000 net acres
+leased or optioned, which is an increase from our previously reported total of
+225,000 net acres. We operate roughly 168,000 of those net acres,
+most of which is at 100 percent working interest, with the balance of the
+acreage being located on joint venture acreage with an industry
+7 
+partner. We
+plan to drill 34 horizontal wells on our operated acreage in
+2010. Part of our drilling program will be aimed at further
+delineating the play in order to make infrastructure commitments later this
+year. We currently are able to market all of our production and
+expect to do so in the future by working with midstream partners to ensure we
+have adequate takeaway and processing capacity to meet our needs. We
+will also be conducting a series of tests to help determine the ultimate spacing
+for the reservoir. Our operating partner plans to operate two to
+three rigs during 2010 on our joint venture acreage where we have a net working
+interest of 25 percent. 
+Permian Basin
+Region. The Permian Basin area covers a significant portion of
+western Texas and eastern New Mexico and is one of the major producing basins in
+the United States. Our holdings in the Permian Basin began with a
+series of property acquisitions in 1996. In December 2006 we made a
+major acquisition of oil properties that targeted the Wolfberry tight oil
+play. To manage the significant increase in operated properties
+associated with the Sweetie Peck acquisition, we opened a regional office in
+Midland, Texas in February 2007. 
+We
+incurred costs of $76.5 million in the region in 2009 compared to $163.2 million
+in 2008. This decrease in capital investment reflects the significant
+slowdown in our drilling activity during the first half of the year in response
+to the low oil prices being realized late in 2008 and early in
+2009. The majority of this capital was deployed to develop projects
+in the Wolfberry tight oil play, which targets the stacked carbonate Wolfcamp
+and Spraberry formations found in the basin. We also tested other
+exploration concepts in the Permian during the year. Production in
+the region increased 9 percent over the prior year, from 13.8 BCFE in 2008 to
+15.2 BCFE in 2009. Proved reserves as of the end of 2009 were
+115.2 BCFE, which is a decrease of 26 percent from 2008 year-end reserves of
+155.9 BCFE. The decrease in our estimate of proved reserves relate to
+engineering revisions on proved producing properties in our Wolfberry tight oil
+program. Well performance data collected during 2009 from our Sweetie
+Peck and Halff East assets which target the Wolfberry indicate that these assets
+are underperforming our year-end 2008 decline forecasts. Accordingly,
+we have removed 37 BCFE from proved reserves in the Permian region, primarily
+related to the Wolfberry tight oil program. We believe that a
+significant portion of these reserves, while not meeting the criteria to be
+booked as proved reserves at year-end, are likely to eventually be produced.
+As of the
+end of December 2009, the Sweetie Peck assets in the Permian Basin collectively
+were the highest value entity in the region. Sweetie Peck field had
+182 producing wells at year-end. We have slightly over 20 proved
+undeveloped locations booked at Sweetie Peck at year-end. We also
+believe there are a meaningful number of unbooked future drilling locations that
+we will be able to pursue in future years. 
+The
+largest drilling program planned for the Permian region in 2010 is in our
+Sweetie Peck tight oil assets where we plan to drill 32 operated wells this
+year. Most of the development will take place on 80- and 40-acre
+spaced locations. Despite the downward Wolfberry engineering
+revisions in our proved reserve estimates referred to above, these projects
+continue to meet our economic standards for drilling, albeit at lower proved
+reserve volumes. We will also continue to work on an exploratory
+program that began in 2009 and we plan to conduct a modest drilling program in
+2010, primarily using vertical wells. 
+Rocky Mountain
+Region. St. Mary has conducted operations in the Williston
+Basin in eastern Montana and western North Dakota since 1991. The
+region is managed by our office in Billings, Montana. In recent
+years, we have expanded our operations into the Greater Green River, Powder
+River, Big Horn, and Wind River basins of Wyoming through a series of
+acquisitions. The largest growth in the region came in late 2001 and
+early 2003 with significant property acquisitions from Choctaw, Burlington
+Resources, and Flying J. In recent years, we have been divesting of
+non-core properties in the Rocky Mountain region in an effort to focus our human
+and investment capital on the most impactful plays in that region. 
+We
+incurred costs of $51.2 million in 2009 for exploration, development, and
+acquisitions in the Rocky Mountain region, compared to $190.3 million in
+2008. Our 2009 budget in the Rocky Mountain region reflected the low
+oil prices and the wide price differentials we experienced at the end of
+2008. For much of 2009, we did not have any operated rigs running in
+the region. Our capital investments were primarily focused on the
+Bakken and Three Forks formations and were heavily weighted toward the back half
+of the year. Proved reserves for the Rocky Mountain region were
+260.3 BCFE at year-end compared with 261.4 BCFE as of the end of
+2008. The slight decrease in proved reserves is the result of selling
+40.3 BCFE of proved reserves in the region during the 
+8 
+year,
+most of which related to the sale of non-strategic coalbed methane project at
+Hanging Woman Basin, offset by net positive price and engineering revisions of
+50.0 BCFE. Production in the Rocky Mountain region for 2009 was 33.3
+BCFE. Total regional production was down five percent from 34.9
+BCFE in 2008. Adjusting for the effect of the divestitures,
+production in the region would have declined 1.3 BCFE, or four percent, year
+over year. 
+The Elm
+Coulee Field is the highest value field in the region at year-end
+2009. The reserves in this field are predominately oil, and the
+Bakken is the formation of primary interest. The field is largely
+developed with only a handful of remaining drilling locations identified as
+proved undeveloped. 
+The
+Bakken and Three Forks formations in the Williston Basin will be our primary
+focus in 2010. We plan to drill 17 horizontal wells targeting these
+formations in 2010. The majority will be located in our Bear Den
+asset program in McKenzie and Williams counties in North Dakota where we have
+roughly 16,000 net acres. Additionally, we have built a 70,000 net
+acre position with potential for the Bakken and Three Forks in McKenzie,
+Williams, and Divide counties that we will test during 2010. We are
+currently drilling a test well in Wyoming targeting the Niobrara formation as
+part of our ongoing exploration effort. We plan to evaluate our
+results, as well as those of nearby competitors, during 2010. 
+Reserves 
+In
+December 2008, the SEC announced that it had approved revisions designed to
+modernize oil and gas reporting requirements. A key revision to the
+rules pertains to commodity prices. The economic producibility of
+reserves and discounted cash flows are now based on a 12-month average commodity
+price as opposed to a year-end price in estimating reserves. The
+prices used in the calculation of proved reserve estimates as of
+December 31, 2009, were $61.18 per Bbl and $3.87 per MMBTU for oil and
+natural gas, respectively. These prices were 37 percent higher and 32
+percent lower, respectively, than the
+year-end prices used to estimate 2008 proved reserves, and 23 percent and 33
+percent lower, respectively, than prices that would have been used the SEC’s
+previous methodology. If the SEC’s prior methodology had been used
+for year-end 2009 proved reserves, the prices used would have been $79.36 per
+Bbl and $5.79 per MMBTU. 
+Additional
+revisions to the SEC rules provide for the use of new technology to estimate
+proved reserves. Additionally, the definition of proved oil and gas
+reserves has been expanded to include non-traditional resources, which focuses
+on the marketable product rather than the method of extraction. In
+addition to these regulatory changes, in 2009 we began recording estimates of
+proved reserve volumes for properties that we believe are reasonably certain to
+generate positive net cash flows on an undiscounted basis, that we have the
+intent to drill, and which meet our internal economic criteria for
+drilling. Previously, we booked proved reserve volumes if the
+properties showed a positive PV-10 value, we had the intent to drill, and the
+wells met our economic criteria. 
+The table
+below presents summary information with respect to the estimates of our proved
+oil and gas reserves for each of the years in the three-year period ended
+December 31, 2009. We engaged Ryder Scott Company, L.P. (“Ryder
+Scott”) to review internal engineering estimates for at least 80 percent of the
+PV-10 value of our proved reserves in 2009, 2008, and 2007, excluding our
+coalbed methane properties. For 2008 and 2007, Netherland, Sewell and
+Associates, Inc. (“NSAI”) prepared the reserve information for our coalbed
+methane projects at Hanging Woman Basin in the northern Powder River Basin and
+St. Mary’s non-operated coalbed methane interest in the Green River
+Basin. We divested of all Hanging Woman Basin properties in the
+fourth quarter of 2009. 
+We
+emphasize that reserve estimates are inherently imprecise and that estimates of
+all new discoveries and undeveloped locations are more imprecise than estimates
+of established producing oil and gas properties. Accordingly, these
+estimates are expected to change as new information becomes available in the
+future. The PV-10 values shown in the following table are not
+intended to represent the current market value of the estimated proved oil and
+gas reserves owned by St. Mary. Neither prices nor costs have been
+escalated. The following table should be read along with the section
+entitled “Risk Factors – Risks Related to Our Business – The actual quantities
+and present values of our proved oil and natural gas reserves may be less than
+we have estimated.” No estimates of our proved reserves have been
+filed with or included in reports to any federal authority or agency, other than
+the SEC, since the beginning of the last fiscal year. 
+9 
+The
+ability to replace produced reserves is important to the sustainability of all
+exploration and production companies. Our 2009 corporate ratio of
+reserves replaced through drilling activity was 100 percent. There
+were no material acquisitions made in 2009. Four out of our five
+regions did not replace their respective regional production for the
+year. The one exception, our South Texas & Gulf Coast region,
+replaced 400 percent of its production for 2009 due to the strong results in the
+Eagle Ford shale. This metric is calculated using information from
+the Oil and Gas Reserve Quantities section of Note 16 – Disclosures about Oil
+and Gas Producing Activities of Part IV, Item 15 of this report. The
+numerator consists of the sum of discoveries and extensions and infill reserves
+in an existing proved field, which is then divided by production. We
+believe the concept of reserve replacement as described above, as well as
+permutations which may include other captions of the Oil and Gas Reserve
+Quantities section of Note 16 – Disclosures about Oil and Gas Producing
+Activities of Part IV, Item 15 of this report, are widely understood by those
+who make investment decisions related to the oil and gas exploration
+business. For additional information about reserve replacement
+metrics, see the reserve replacement terms in the Glossary section of this
+report. 
+As
+of December 31, 
+Reserves
+data: 
+2009 
+2008 
+2007 
+Proved
+developed 
+Oil
+(MMBbl) 
+48.1 
+47.1 
+68.3 
+Gas
+(Bcf) 
+342.0 
+433.2 
+426.6 
+BCFE 
+630.3 
+715.8 
+836.3 
+Proved
+undeveloped 
+Oil
+(MMBbl) 
+5.7 
+4.3 
+10.5 
+Gas
+(Bcf) 
+107.5 
+124.2 
+186.9 
+BCFE 
+141.9 
+149.7 
+250.2 
+Total
+Proved 
+Oil
+(MMBbl) 
+53.8 
+51.4 
+78.8 
+Gas
+(Bcf) 
+449.5 
+557.4 
+613.5 
+BCFE 
+772.2 
+865.5 
+1,086.5 
+Proved
+developed reserves % 
+82% 
+83% 
+77% 
+Proved
+undeveloped reserves % 
+18% 
+17% 
+23% 
+Reserve
+Value info (in thousands) 
+Proved
+developed PV-10 
+$ 
+1,253,056 
+$ 
+1,214,380 
+$ 
+3,300,213 
+Proved
+undeveloped PV-10 
+31,029 
+51,005 
+560,974 
+Total
+proved PV-10 value 
+$ 
+1,284,085 
+$ 
+1,265,385 
+$ 
+3,861,187 
+Standardized
+measure of discounted future cash flows 
+1,015,967 
+1,059,069 
+2,706,914 
+Reserve
+replacement – drilling and acquisitions, excluding
+revisions 
+100% 
+174% 
+211% 
+All
+in – including sales of reserves 
+14% 
+(93)% 
+248% 
+All
+in – excluding sales of reserves 
+55% 
+(39)% 
+249% 
+Reserve
+life (years) (1) 
+7.1 
+7.6 
+10.1 
+(1) 
+Reserve
+life represents the estimated proved reserves at the dates indicated
+divided by actual production for the preceding 12-month
+period 
+10 
+The
+following table reconciles the standardized measure of discounted future net
+cash flows (GAAP) to the PV-10 value (Non-GAAP). The difference has
+to do with the PV-10 value measure excluding the impact of income
+taxes. Please see the definitions of standardized measure of
+discounted future net cash flows and PV-10 value in the Glossary. 
+As
+of December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Standardized
+measure of discounted future net cash flows 
+$ 
+1,015,967 
+$ 
+1,059,069 
+$ 
+2,706,914 
+Add:
+10 percent annual discount, net of income taxes 
+732,997 
+724,840 
+2,321,983 
+Add:
+future income taxes 
+515,953 
+419,544 
+2,316,637 
+Undiscounted
+future net cash flows 
+$ 
+2,264,917 
+$ 
+2,203,453 
+$ 
+7,345,534 
+Less:
+10 percent annual discount without tax effect 
+(980,832 
+) 
+(938,068 
+) 
+(3,484,347 
+) 
+PV-10
+value 
+$ 
+1,284,085 
+$ 
+1,265,385 
+$ 
+3,861,187 
+Proved
+Undeveloped Reserves 
+As of
+December 31, 2009, we had 141.9 BCFE of proved undeveloped reserves, which is a
+decrease of 7.8 BCFE or five percent compared with 149.7 of proved undeveloped
+reserves at December 31, 2008. A negative revision of 19.1
+BCFE was due to lower pricing in the gas weighted regions, particularly in the
+ArkLaTex region where 16.4 BCFE of mostly Cotton Valley proved undeveloped
+reserves became uneconomic using the new 12-month average pricing. We
+added 43.6 BCFE of proved undeveloped reserves through our drilling
+program, 34.3 BCFE of which were extensions and discoveries, primarily in the
+Eagle Ford shale, as well as an additional 9.3 BCFE of infill proved undeveloped
+reserves that were mostly concentrated in the Cotton Valley and
+Bakken. During the year, 7.0 BCFE were sold in divestitures,
+primarily in our Rocky Mountain region. We invested approximately $57
+million to convert 18.6 BCFE of proved undeveloped reserves in 2009,
+which amounted to approximately $57 million in capital expenditures, mainly in
+the Wolfberry properties in the Permian region and the Woodford shale in the
+Mid-Continent region. We had a negative revision of 6.7 BCFE due to
+downward performance revisions in our Wolfberry properties in the Permian region
+and 3.6 BCFE of proved undeveloped reserves were removed as a result of the
+five year limitation on the number of years that a proved undeveloped reserve
+may remain on the books without being developed. As of
+December 31, 2009, we have no material proved undeveloped reserves
+that have been on the books in excess of five years. As of
+December 31, 2009, estimated future development costs relating to
+proved undeveloped reserves are projected to be approximately $49 million, $129
+million, and $56 million in 2010, 2011, and 2012, respectively. 
+11 
+Alternate
+Pricing Scenario 
+The
+following table presents our December 31, 2009, reserves data and PV-10 value
+based on prices that would have been used under the SEC’s previous methodology
+of estimating reserves using year-end pricing. If the SEC’s prior
+methodology had been used for year-end 2009 proved reserves, the prices used
+would have been $79.36 per barrel and $5.79 per MMBTU. All cost assumptions
+remain the same. 
+As
+of December 31, 2009 
+Reserves
+data: 
+Proved
+developed 
+Oil
+(MMBbl) 
+53.0 
+Gas
+(Bcf) 
+382.9 
+BCFE 
+700.8 
+Proved
+undeveloped 
+Oil
+(MMBbl) 
+8.8 
+Gas
+(Bcf) 
+143.9 
+BCFE 
+196.4 
+Total
+Proved 
+Oil
+(MMBbl) 
+61.8 
+Gas
+(Bcf) 
+526.8 
+BCFE 
+897.2 
+Proved
+developed reserves 
+78% 
+Proved
+undeveloped reserves 
+22% 
+Reserve
+Value info (in thousands) 
+Proved
+developed PV-10 
+$ 
+2,207,906 
+Proved
+undeveloped PV-10 
+235,805 
+Total
+proved PV-10 value 
+$ 
+2,443,711 
+Internal
+Controls Over Reserves Estimate 
+St.
+Mary’s policies regarding internal controls over the recording of reserves is
+structured to objectively and accurately estimate our oil and gas reserves
+quantities and values in compliance with the SEC’s
+regulations. Responsibility for compliance in reserves bookings is
+delegated to our reservoir engineering group, which is led by our Vice President
+of Engineering and Evaluation. 
+Technical
+reviews are performed throughout the year by regional engineering and geologic
+staff who evaluate all available geological and engineering
+data. This data in conjunction with economic data and ownership
+information is used in making a determination of proved reserve
+quantities. The reserve process is overseen by Dennis A. Zubieta,
+Vice President - Engineering and Evaluation for St.
+Mary. Mr. Zubieta joined St. Mary in June 2000 as a
+Corporate Acquisition & Divestiture Engineer, assumed the role of Reservoir
+Engineer in February 2003, and was appointed Reservoir Engineering Manager in
+August 2005. Mr. Zubieta was employed by Burlington Resources Oil and
+Gas Company (formerly known as Meridian Oil, Inc) from June 1988 to May 2000 in
+various operations and reservoir engineering capacities. Mr. Zubieta
+received a Bachelor of Science degree in Petroleum Engineering from Montana Tech
+in May 1988. The regional technical staff does not report directly to
+Mr. Zubieta; they report to either regional technical managers or directly to
+the regional manager in their respective region. This is intended to
+promote objective and independent analysis within the reserves
+process. 
+12 
+Third-party
+Reserves Audit 
+An
+independent audit is performed by Ryder Scott using their own engineering
+assumptions and economic data provided by St. Mary. A minimum of 80
+percent of the total calculated proved reserve PV-10 value is audited by Ryder
+Scott. In aggregate, the reserve values of the audited properties are
+required to be within 10 percent of St. Mary’s valuations on both a
+corporate and regional level. Ryder Scott is an independent petroleum
+engineering consulting firm that has been providing petroleum consulting
+services throughout the world for over seventy years. The technical
+person at Ryder Scott primarily responsible for overseeing the reserves audit is
+a Senior Vice President and holds a Bachelor of Science degree in Petroleum
+Engineering from the University of Missouri at Rolla in 1970 and is a registered
+Professional Engineer in the States of Colorado and Utah. He is also
+a member of the Society of Petroleum Engineers. The Ryder
+Scott report is included as Exhibit 99.1. 
+In
+addition to a third party audit, our reserves are reviewed by senior management
+and the Audit Committee of St. Mary’s Board of Directors. Senior
+management, which includes the President and Chief Executive Officer, the
+Executive Vice President and Chief Operating Officer, and the Executive Vice
+President and Chief Financial Officer, is responsible for reviewing and
+verifying that the estimate of proved reserves is reasonable, complete, and
+accurate. The Audit Committee reviews the final reserves estimate in
+conjunction with Ryder Scott’s audit letter. They may also meet with
+the key representative from Ryder Scott to discuss their process and
+findings. 
+Production 
+The
+following table summarizes the average volumes and realized prices, including
+and excluding the effects of hedging, of oil and gas produced from properties in
+which St. Mary held an interest during the periods indicated. Also
+presented is a production cost per MCFE summary for the Company. 
+Years
+Ended December 31, 
+2009 
+2008 
+2007 
+Net
+production 
+Oil
+(MMBbl) 
+6.3 
+6.6 
+6.9 
+Gas
+(Bcf) 
+71.1 
+74.9 
+66.1 
+BCFE 
+109.1 
+114.6 
+107.5 
+Average
+net daily production 
+Oil
+(MBbl) 
+17.3 
+18.1 
+18.9 
+Gas
+(MMcf) 
+194.8 
+204.7 
+181.0 
+MMCFE 
+298.8 
+313.1 
+294.5 
+Average
+realized sales price, excluding the effects of hedging 
+Oil
+(per Bbl) 
+$ 
+54.40 
+$ 
+92.99 
+$ 
+67.56 
+Gas
+(per Mcf) 
+$ 
+3.82 
+$ 
+8.60 
+$ 
+6.74 
+Per
+MCFE 
+$ 
+5.65 
+$ 
+10.99 
+$ 
+8.48 
+Average
+realized sales price, including the effects of hedging 
+Oil
+(per Bbl) 
+$ 
+56.74 
+$ 
+75.59 
+$ 
+62.60 
+Gas
+(per Mcf) 
+$ 
+5.59 
+$ 
+8.79 
+$ 
+7.63 
+Per
+MCFE 
+$ 
+6.94 
+$ 
+10.11 
+$ 
+8.71 
+Production
+costs per MCFE 
+Lease
+operating expense 
+$ 
+1.33 
+$ 
+1.46 
+$ 
+1.31 
+Transportation
+expense 
+$ 
+0.19 
+$ 
+0.19 
+$ 
+0.14 
+Production
+taxes 
+$ 
+0.37 
+$ 
+0.71 
+$ 
+0.58 
+13 
+Productive
+Wells 
+As of
+December 31, 2009, St. Mary had working interests in 2,046 gross (1,000 net)
+productive oil wells and 3,154 gross (1,042 net) productive gas
+wells. Productive wells are either producing wells or wells capable
+of commercial production although currently shut-in. Multiple
+completions in the same wellbore are counted as one well. A well is
+categorized under state reporting regulations as an oil well or a gas well based
+on the ratio of gas to oil produced when it first commenced production, and such
+designation may not be indicative of current production. 
+Subsequent
+to year end, we have closed or plan to close on several divestitures of non-core
+properties, primarily in the Rocky Mountain region. Upon closing of
+these transactions, we will have divested 425 gross (302 net) productive oil
+wells and 305 gross (93 net) productive gas wells. 
+Drilling
+Activity 
+All of
+our drilling activities are conducted on a contract basis with independent
+drilling contractors. We do not own any drilling
+equipment. The following table sets forth the wells drilled and
+recompleted in which St. Mary participated during each of the three years
+indicated: 
+Years
+Ended December 31, 
+2009 
+2008 
+2007 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development: 
+Oil 
+103 
+29.64 
+221 
+81.46 
+164 
+77.91 
+Gas 
+74 
+18.15 
+559 
+205.18 
+518 
+204.62 
+Non-productive 
+3 
+1.29 
+25 
+13.70 
+30 
+13.18 
+180 
+49.08 
+805 
+300.34 
+712 
+295.71 
+Exploratory: 
+Oil 
+2 
+0.42 
+2 
+0.40 
+3 
+1.92 
+Gas 
+18 
+9.05 
+10 
+2.75 
+9 
+4.01 
+Non-productive 
+5 
+2.88 
+1 
+0.76 
+5 
+2.58 
+25 
+12.35 
+13 
+3.91 
+17 
+8.51 
+Farmout
+or non-consent 
+3 
+- 
+7 
+- 
+1 
+- 
+Total (1) 
+208 
+61.43 
+825 
+304.25 
+730 
+304.22 
+(1) 
+Does
+not include one and two gross wells completed on St. Mary’s fee lands
+during 2009 and 2008, respectively, in which we only have royalty
+interests. 
+A
+productive well is an exploratory, development or extension well that is not a
+dry well. A dry well (hole) is an exploratory, development, or
+extension well that proves to be incapable of producing either oil or gas in
+sufficient quantities to justify completion as an oil or gas well. 
+As
+defined in the rules and regulations of the SEC, an exploratory well is a well
+drilled to find a new field or to find a new reservoir in a field previously
+found to be productive of oil or gas in another reservoir. A
+development well is part of a development project, which is defined as the means
+by which petroleum resources are brought to the status of economically
+producible. The number of wells drilled refers to the number of wells
+completed at any time during the respective year, regardless of when drilling
+was initiated. Completion refers to the installation of permanent
+equipment for production of oil or gas, or, in the case of a dry well, to
+reporting to the appropriate authority that the well has been
+abandoned. 
+In
+addition to the wells drilled and completed in 2009 included in the table above,
+as of February 16, 2010, St. Mary is currently participating in the
+drilling of 25 gross wells, all of which are located in the continental United
+States. We operate nine of these wells with the remaining 16 wells being
+operated by our partners. On a net basis, we are drilling 7.6 net operated
+wells and are participating in 2.0 net non-operated 
+14 
+wells. 
+With respect to completion activity, there are currently 19 wells in which we
+have an interest that are being completed. We operate 13 of those on a
+gross basis (10.2 net) and is participating with industry partners in 6 gross
+(0.3 net) completion activities. The vast majority, if not all, of these
+operations relate to the drilling of wells for primary production. 
+Acreage 
+The
+following table sets forth the gross and net acres of developed and undeveloped
+oil and gas leases, fee properties, mineral servitudes, and lease options held
+by St. Mary as of December 31, 2009. Undeveloped acreage includes
+leasehold interests that may already have been classified as containing proved
+undeveloped reserves. 
+Developed
+Acres (1) 
+Undeveloped
+Acres (2) 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Arkansas 
+1,394 
+163 
+147 
+60 
+1,541 
+223 
+Colorado 
+- 
+- 
+940 
+614 
+940 
+614 
+Kansas 
+- 
+- 
+2,240 
+560 
+2,240 
+560 
+Louisiana 
+101,516 
+37,483 
+25,120 
+4,905 
+126,636 
+42,388 
+Mississippi 
+2,360 
+429 
+100,963 
+42,265 
+103,323 
+42,694 
+Montana 
+59,806 
+40,389 
+343,612 
+236,463 
+403,418 
+276,852 
+Nevada 
+- 
+- 
+197,945 
+197,945 
+197,945 
+197,945 
+New
+Mexico 
+2,507 
+1,815 
+1,240 
+1,022 
+3,747 
+2,837 
+North
+Dakota 
+127,497 
+87,654 
+216,779 
+121,214 
+344,276 
+208,868 
+Oklahoma 
+256,577 
+81,184 
+70,483 
+32,917 
+327,060 
+114,101 
+Pennsylvania 
+- 
+- 
+30,462 
+27,440 
+30,462 
+27,440 
+Texas 
+221,795 
+106,072 
+544,683 
+260,955 
+766,478 
+367,027 
+Utah 
+- 
+- 
+2,568 
+561 
+2,568 
+561 
+Wyoming 
+88,761 
+52,814 
+285,700 
+143,183 
+374,461 
+195,997 
+862,213 
+408,003 
+1,822,882 
+1,070,104 
+2,685,095 
+1,478,107 
+Louisiana
+Fee Properties 
+10,499 
+10,499 
+14,415 
+14,415 
+24,914 
+24,914 
+Louisiana
+Mineral Servitudes 
+7,426 
+4,217 
+4,769 
+4,407 
+12,195 
+8,624 
+17,925 
+14,716 
+19,184 
+18,822 
+37,109 
+33,538 
+Total
+(3) 
+880,138 
+422,719 
+1,842,066 
+1,088,926 
+2,722,204 
+1,511,645 
+(1) 
+Developed
+acreage is acreage assigned to producing wells for the spacing unit of the
+producing formation. Developed acreage of St. Mary’s properties
+that include multiple formations with different well spacing requirements
+may be considered undeveloped for certain formations, but have only been
+included as developed acreage in the presentation
+above. 
+(2) 
+Undeveloped
+acreage is lease acreage on which wells have not been drilled or completed
+to a point that would permit the production of commercial quantities of
+oil and gas, regardless of whether such acreage contains estimated
+reserves. 
+(3) 
+Subsequent
+to December 31, 2009, St. Mary divested certain non-core properties, which
+included leases covering approximately 26,100 and 25,100 developed gross
+and net acres, respectively, and 18,600 and 15,000 undeveloped gross and
+net acres, respectively. Additionally, we entered into
+agreements to divest certain non-core properties, which included leases
+covering approximately 80,200 and 44,500 developed gross and net acres,
+respectively, and 63,700 and 31,000 undeveloped gross and net acres,
+respectively. 
+Delivery
+Commitments 
+As of
+December 31, 2009, there were no material delivery
+commitments. Subsequent to year end we are subject to a certain
+gathering through-put contract that requires a minimum volume delivery of 15 Bcf
+by January 1, 2013. We will be required to pay $0.18 Mcf for any
+shortfall in delivering the minimum volume of 15 Bcf. At the current
+time, the company does not have proved developed reserves to offset
+this contractual liability, but fully intends to develop proved undeveloped
+reserves that will exceed the through-put commitment. 
+15 
+Major
+Customers 
+During
+2009, sales to Teppco Crude Oil LLC individually accounted for 12 percent of our
+total oil and gas production revenue. During 2008 and 2007, no
+customer individually accounted for ten percent or more of our total oil and gas
+production revenue. 
+Employees
+and Office Space 
+As of
+February 16, 2010, we had 550 full-time employees. None of our
+employees are subject to a collective bargaining agreement and we consider our
+relations with our employees to be good. As of
+December 31, 2009, we lease approximately 79,000 square feet of office space in
+Denver, Colorado for our executive and administrative offices, of which
+approximately 9,000 square feet is subleased. We lease approximately
+22,000 square feet of office space in Tulsa, Oklahoma; approximately 22,000
+square feet in Shreveport, Louisiana; approximately 26,000 square feet in
+Houston, Texas; approximately 17,000 square feet in Midland, Texas;
+approximately 36,000 square feet in Billings, Montana; approximately 6,000
+square feet in Williston, North Dakota; and approximately 2,000 square feet in
+Casper, Wyoming. 
+Title
+to Properties 
+Substantially
+all of our working interests are held pursuant to leases from third
+parties. A title opinion is usually obtained prior to the
+commencement of drilling operations. We have obtained title opinions
+or have conducted a thorough title review on substantially all of our producing
+properties and believe that we have satisfactory title to such properties in
+accordance with standards generally accepted in the oil and gas
+industry. The majority of the value of our properties is subject to a
+mortgage under our credit facility, customary royalty interests, liens for
+current taxes, and other burdens that we believe do not materially interfere
+with the use of or affect the value of such properties. We perform
+only a minimal title investigation before acquiring undeveloped
+leasehold. 
+Seasonality 
+Generally,
+but not always, the demand and price levels for natural gas increase during the
+colder winter months and decrease during the warmer summer months. To
+lessen seasonal demand fluctuations, pipelines, utilities, local distribution
+companies, and industrial users utilize natural gas storage facilities and
+forward purchase some of their anticipated winter requirements during the
+summer. However, increasing summertime demand for electricity is
+beginning to place increased demand on storage volumes. Crude oil and
+the demand for heating oil are also impacted by generally higher prices in the
+winter and the summer driving season – although oil is much more driven by
+global supply and demand. Seasonal anomalies such as mild winters
+sometimes lessen these fluctuations. The impact of seasonality has
+somewhat been exacerbated by the overall supply and demand economics related to
+crude oil because there is a narrow margin of production capacity in excess of
+existing worldwide demand. 
+Competition 
+The oil
+and gas industry is intensely competitive, particularly with respect to
+capturing prospective oil and natural gas properties and oil and gas
+reserves. We believe our leasehold position provides a sound
+foundation for a solid drilling program. Our competitive position
+also depends on our geological, geophysical, and engineering expertise, and our
+financial resources. We believe the location of our leasehold
+acreage, our exploration, drilling, and production expertise and available
+technologies, and the experience and knowledge of our management and industry
+partners enable us to compete effectively in our core operating and resource
+play areas. Notwithstanding our talents and assets, we still face
+stiff competition from a substantial number of major and independent oil and gas
+companies who have larger technical staffs and greater financial and operational
+resources than we do. Many of these companies not only engage in the
+acquisition, exploration, development, and production of oil and natural gas
+reserves, but also have refining operations, market refined products, own
+drilling rigs, and generate electricity. We also compete with other
+oil and natural gas companies in attempting to secure drilling rigs and other
+equipment and services necessary for the drilling and completion of
+wells. Consequently, we may face shortages 
+16 
+or delays
+in securing these services from time to time. We are seeing signs of
+tightening rig availability, although it is quite specific by
+region. The oil and natural gas industry also faces competition from
+alternative fuel sources, including other fossil fuels such as coal and imported
+liquefied natural gas. Competitive conditions may be affected by
+future legislation and regulations as the U.S. develops new energy and
+climate-related policies. Finally, we also compete for
+people. Throughout the industry, the need to attract and retain
+talented people has grown at a time when the number of people available is
+constrained. We are not insulated from this resource constraint, and
+we must compete effectively in this market in order to be
+successful. 
+Government
+Regulations 
+Our
+business is extensively regulated by numerous federal, state, and local laws and
+government regulations. These laws and regulations may be changed
+from time to time in response to economic or political conditions, or other
+developments, and our regulatory burden may increase in the
+future. Laws and regulations increase our cost of doing business and,
+consequently, affect our profitability. However, we do not believe
+that we are affected to a materially greater or lesser extent than others in our
+industry. 
+Energy
+Regulations. Many of the states in which we conduct our
+operations have adopted laws and regulations governing the exploration for and
+production of crude oil and natural gas, including laws and regulations
+requiring permits for the drilling of wells, imposing bonding requirements in
+order to drill or operate wells, and governing the location of wells, the method
+of drilling and casing wells, the surface use and restoration of properties upon
+which wells are drilled, and the plugging and abandonment of
+wells. Our operations are also subject to various state conservation
+laws and regulations, including regulations governing the size of drilling and
+spacing units or proration units, the number of wells which may be drilled in an
+area, the spacing of wells, and the unitization or pooling of crude oil and
+natural gas properties. In addition, state conservation laws
+sometimes establish maximum rates of production from crude oil and natural gas
+wells, generally prohibit the venting or flaring of natural gas, and may impose
+certain requirements regarding the ratability or fair apportionment of
+production from fields and individual wells. 
+Some of
+our operations are conducted on federal lands pursuant to oil and gas leases
+administered by the Bureau of Land Management (BLM) or the Minerals Management
+Service (MMS). These leases contain relatively standardized terms and
+require compliance with detailed regulations and orders, which are subject to
+change. In addition to permits required from other regulatory
+agencies, lessees must obtain a permit from the BLM or MMS before drilling and
+comply with regulations governing, among other things, engineering and
+construction specifications for production facilities, safety procedures, the
+valuation of production and payment of royalties, the removal of facilities, and
+the posting of bonds to ensure that lessee obligations are met. Under
+certain circumstances, the BLM or the MMS, as applicable, may require our
+operations on federal leases to be suspended or terminated. 
+In
+January 2010, the BLM announced that it will be issuing a new draft oil and gas
+leasing policy that will require, among other things, a more detailed
+environmental review prior to leasing oil and natural gas resources, increased
+public engagement in the development of master leasing and development plans
+prior to leasing areas where intensive new oil and gas development is
+anticipated, and a comprehensive parcel review process. As the policy
+has not yet been released, we are not able to determine the impact these
+potential leasing policy changes may have on our business. 
+Our sales
+of natural gas are affected by the availability, terms, and cost of natural gas
+pipeline transportation. The Federal Energy Regulatory Commission
+(FERC) has jurisdiction over the transportation and sale for resale of natural
+gas in interstate commerce. The FERC’s current regulatory framework
+generally provides for a competitive and open access market for sales and
+transportation of natural gas. However, FERC regulations continue to
+affect the midstream and transportation segments of the industry, and thus can
+indirectly affect the sales prices we receive for natural gas
+production. In addition, the less stringent regulatory approach
+recently pursued by the FERC and the U.S. Congress may not continue
+indefinitely. 
+17 
+Environmental, Health and Safety
+Regulations. Our operations are subject to stringent federal,
+state, and local laws and regulations relating to the protection of the
+environment and human health and safety. Environmental laws and
+regulations may require that permits be obtained before drilling commences,
+restrict the types, quantities, and concentration of various substances that can
+be released into the environment in connection with drilling and production
+activities, govern the handling and disposal of waste material, and limit or
+prohibit drilling activities on certain lands lying within wilderness, wetlands,
+and other protected areas, including areas containing endangered animal
+species. As a result, these laws and regulations may substantially
+increase the costs of exploring for, developing, or producing oil and gas and
+may prevent or delay the commencement or continuation of certain
+projects. In addition, these laws and regulations may impose
+substantial clean-up, remediation, and other obligations in the event of
+any discharges or emissions in violation of these laws and
+regulations. Further, possible regulations related to global warming
+or climate change could have an adverse effect on our operations and the demand
+for oil and natural gas. See “Risk Factors – Risks Related to Our
+Business - Possible regulations related to global warming or climate change
+could have an adverse effect on our operations and the demand for oil and
+natural gas.” 
+Hydraulic
+fracturing is a common process in our industry of creating artificial cracks, or
+fractures, in deep underground rock formations through the pressurized injection
+of water, sand and other additives to enable oil or natural gas to move more
+easily through the rock pores to a production well. This process is
+often necessary to produce commercial quantities of oil and natural gas from
+many reservoirs, especially shale rock formations. We routinely
+utilize hydraulic fracturing techniques in many of our reservoirs, and our shale
+resource programs utilize or contemplate the utilization of hydraulic
+fracturing. Currently, regulation of hydraulic fracturing is
+primarily conducted at the state level through permitting and other compliance
+requirements. Legislative and regulatory efforts at the federal level
+and in some states have been made which could result in additional regulations
+and permitting requirements. Those additional regulations and
+permitting requirements, as well as other regulatory developments, could lead to
+significant operational delays and increased operating costs, and make it more
+difficult to perform hydraulic fracturing. 
+Federal
+and state occupational safety and health laws require us to organize and
+maintain information about hazardous materials used, released, or produced in
+our operations. Some of this information must be provided to our
+employees, state and local governmental authorities, and local
+citizens. We are also subject to the requirements and reporting
+framework set forth in the federal workplace standards. 
+To date
+we have not experienced any materially adverse effect on our operations from
+obligations under environmental, health, and safety laws and
+regulations. We believe that we are in substantial compliance with
+currently applicable environmental, health, and safety laws and regulations, and
+that continued compliance with existing requirements would not have a materially
+adverse impact on us. 
+Cautionary
+Information about Forward-Looking Statements 
+This Form
+10-K contains “forward-looking statements” within the meaning of Section 27A of
+the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
+1934. All statements, other than statements of historical facts,
+included in this Form 10-K that address activities, events, or developments with
+respect to our financial condition, results of operations, or economic
+performance that we expect, believe, or anticipate will or may occur in the
+future, or that address plans and objectives of management for future
+operations, are forward-looking statements. The words “anticipate,”
+“assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,”
+“plan,” “project,” “will,” and similar expressions are intended to identify
+forward-looking statements. Forward-looking statements appear in a
+number of places in this Form 10-K, and include statements about such matters
+as: 
+· 
+The
+amount and nature of future capital expenditures and the availability of
+liquidity and capital resources to fund capital
+expenditures 
+· 
+The
+drilling of wells and other exploration and development activities and
+plans, as well as possible future
+acquisitions 
+18 
+· 
+Proved
+reserve estimates and the estimates of both future net revenues and the
+present value of future net revenues that are included in their
+calculation 
+· 
+Future
+oil and natural gas production
+estimates 
+· 
+Our
+outlook on future oil and natural gas prices and service
+costs 
+· 
+Cash
+flows, anticipated liquidity, and the future repayment of
+debt 
+· 
+Business
+strategies and other plans and objectives for future operations, including
+plans for expansion and growth of operations or to defer capital
+investment, and our outlook on our future financial condition or results
+of operations 
+· 
+Other
+similar matters such as those discussed in the “Management’s Discussion
+and Analysis of Financial Condition and Results of Operations” section in
+Item 7 of this Form 10-K. 
+Our
+forward-looking statements are based on assumptions and analyses made by us in
+light of our experience and our perception of historical trends, current
+conditions, expected future developments, and other factors that we believe are
+appropriate under the circumstances. These statements are subject to
+a number of known and unknown risks and uncertainties which may cause our actual
+results and performance to be materially different from any future results or
+performance expressed or implied by the forward-looking
+statements. These risks are described in the “Risk Factors” section
+in Item 1A of this Form 10-K, and include such factors as: 
+· 
+The
+volatility and level of realized oil and natural gas
+prices 
+· 
+A
+contraction in demand for oil and natural gas as a result of adverse
+general economic conditions or climate change
+initiatives 
+· 
+The
+availability of economically attractive exploration, development, and
+property acquisition opportunities and any necessary financing, including
+any constraints on the availability of opportunities and financing due to
+distressed capital and credit market
+conditions 
+· 
+Our
+ability to replace reserves and sustain
+production 
+· 
+Unexpected
+drilling conditions and results 
+· 
+Unsuccessful
+exploration and development
+drilling 
+· 
+The
+risks of hedging strategies, including the possibility of realizing lower
+prices on oil and natural gas sales as a result of commodity price risk
+management activities 
+· 
+The
+pending nature of reported divestiture plans for certain non-core oil and
+gas properties as well as the ability to complete divestiture
+transactions 
+· 
+The
+uncertain nature of the expected benefits from acquisitions and
+divestitures of oil and natural gas properties, including uncertainties in
+evaluating oil and natural gas reserves of acquired properties and
+associated potential liabilities, and uncertainties with respect to the
+amount of proceeds that may be received from
+divestitures 
+· 
+The
+imprecise nature of oil and natural gas reserve
+estimates 
+· 
+Uncertainties
+inherent in projecting future rates of production from drilling activities
+and acquisitions 
+19 
+· 
+Declines
+in the values of our oil and natural gas properties resulting in
+impairment charges and write-downs 
+· 
+The
+ability of purchasers of production to pay for amounts
+purchased 
+· 
+Drilling
+and operating service availability 
+· 
+Uncertainties
+in cash flow 
+· 
+The
+financial strength of hedge contract counterparties and credit facility
+participants, and the risk that one or more of these parties may not
+satisfy their contractual
+commitments 
+· 
+The
+negative impact that lower oil and natural gas prices could have on our
+ability to borrow and fund capital
+expenditures 
+· 
+The
+potential effects of increased levels of debt
+financing 
+· 
+Our
+ability to compete effectively against other independent and major oil and
+natural gas companies and 
+· 
+Litigation,
+environmental matters, the potential impact of government regulations, and
+the use of management estimates. 
+We
+caution you that forward-looking statements are not guarantees of future
+performance and that actual results or performance may be materially different
+from those expressed or implied in the forward-looking
+statements. Although we may from time to time voluntarily update our
+prior forward-looking statements, we disclaim any commitment to do so except as
+required by securities laws. 
+Available
+Information 
+Our
+Internet website address is www.stmaryland.com. We routinely post
+important information for investors on our website. Within our
+website’s investor relations section we make available free of charge our annual
+reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
+8-K, and amendments to those reports filed with or furnished to the SEC under
+applicable securities laws. These materials are made available as
+soon as reasonably practical after we electronically file such materials with or
+furnish such materials to the SEC. 
+We also
+make available through our website’s corporate governance section our Corporate
+Governance Guidelines, Code of Business Conduct and Ethics, and the Charters for
+our Board of Directors’ Audit Committee, Compensation Committee, Executive
+Committee, and Nominating and Corporate Governance Committee. 
+Information
+on our website is not incorporated by reference into this Form 10-K and should
+not be considered part of this document. 
+20 
+Glossary
+of Oil and Natural Gas Terms 
+The oil
+and natural gas terms defined in this section are used throughout this Form
+10-K. The definitions of the terms developed reserves, exploratory
+well, field, proved reserves, and undeveloped reserves have been abbreviated
+from the respective definitions under Rule 4-10(a) of Regulation S-X promulgated
+by the SEC. The entire definitions of those terms under Rule 4-10(a)
+of Regulation S-X can be located through the SEC’s website at
+www.sec.gov. 
+Bbl. One stock
+tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other
+liquid hydrocarbons. 
+Bcf . Billion cubic feet,
+used in reference to natural gas. 
+BCFE. Billion
+cubic feet of natural gas equivalent. Natural gas equivalents are
+determined using the volumetric ratio of six Mcf of natural gas to one Bbl of
+oil. 
+BOE. Barrels of
+oil equivalent. Oil equivalents are determined using the volumetric
+ratio of six Mcf of natural gas to one Bbl of oil. 
+Developed
+reserves. With respect to reserves as of December 31, 2009,
+and dates thereafter, the applicable SEC definition of developed reserves is
+reserves that can be expected to be recovered: (i) through existing wells with
+existing equipment and operating methods or in which the cost of the required
+equipment is relatively minor compared to the cost of a new well; and (ii)
+through installed extraction equipment and infrastructure operational at the
+time of the reserves estimate if the extraction is by means not involving a
+well. With respect to reserves as of dates prior to December 31,
+2009, the applicable SEC definition of proved developed reserves was proved
+reserves that can be expected to be recovered through existing wells with
+existing equipment and operating methods. 
+Development
+well. A well drilled within the proved area of an oil or
+natural gas reservoir to the depth of a stratigraphic horizon known to be
+productive. 
+Dry hole. A well
+found to be incapable of producing either oil or natural gas in commercial
+quantities. 
+Exploratory
+well. With respect to wells as of December 31, 2009, and dates
+thereafter, the applicable SEC definition of exploratory well is a well drilled
+to find a new field or to find a new reservoir in a field previously found to be
+productive of oil or natural gas in another reservoir. With respect
+to wells as of dates prior to December 31, 2009, the applicable SEC definition
+of exploratory well was a well drilled to find and produce oil or natural gas in
+an unproved area, to find a new reservoir in a field previously found to be
+productive of oil or natural gas in another reservoir, or to extend a known
+reservoir. 
+Farmout. An
+assignment of an interest in a drilling location and related acreage conditioned
+upon the drilling of a well on that location. 
+Fee land. The most
+extensive interest that can be owned in land, including surface and mineral
+(including oil and natural gas) rights. 
+Field. An area
+consisting of a single reservoir or multiple reservoirs all grouped on or
+related to the same individual geological structural feature and/or
+stratigraphic condition. 
+Finding
+cost. Expressed in dollars per MCFE. Finding cost
+metrics provide information as to the cost of adding proved reserves from
+various activities, and are widely utilized within the exploration and
+production industry, as well as by investors. The information used to
+calculate these metrics is included in Note 15 – Oil and Gas Activities and Note
+16 – Disclosures about Oil and Gas Producing Activities of the Notes to
+Consolidated Financial Statements included in this report. It should
+be noted that finding cost metrics have limitations. For example,
+exploration efforts related to a particular set of proved reserve additions may
+extend over several years. 
+21 
+As
+a result, the exploration costs incurred in earlier periods are not included in
+the amount of exploration costs incurred during the period in which that set of
+proved reserves is added. In addition, consistent with industry
+practice, future capital costs to develop proved undeveloped reserves are not
+included in costs incurred. Since the additional development costs
+that will need to be incurred in the future before the proved undeveloped
+reserves are ultimately produced are not included in the amount of costs
+incurred during the period in which those reserves were added, those development
+costs in future periods will be reflected in the costs associated with adding a
+different set of reserves. The calculations of various finding cost
+metrics are explained below.
+Finding cost – Drilling, excluding
+revisions. Calculated by dividing the amount of costs incurred
+for development and exploration activities, by the amount of estimated net
+proved reserves added through discoveries, extensions, and infill drilling,
+during the same period. 
+Finding cost – Drilling, including
+revisions. Calculated by dividing the amount of costs incurred
+for development and exploration activities, by the amount of estimated net
+proved reserves added through discoveries, extensions, and infill drilling, and
+revisions of previous estimates during the same period. 
+Finding cost – Drilling and acquisitions, excluding
+revisions. Calculated by dividing the amount of costs incurred for
+development, exploration and acquisition of proved properties, by the amount of
+estimated net proved reserves added through discoveries, extensions, infill
+drilling and acquisitions during the same period. 
+Finding cost – Drilling and acquisitions, including
+revisions. Calculated by dividing the amount of costs incurred for
+development, exploration and acquisition of proved properties, by the amount of
+estimated net proved reserves added through discoveries, extensions, and infill
+drilling, revisions of previous estimates, and acquisitions during the same
+period. 
+Finding cost –All in, including
+sales of reserves. Calculated by dividing the amount of total
+capital expenditures for oil and natural gas activities, by the amount of
+estimated net proved reserves added through discoveries, extensions, infill
+drilling, acquisitions, and revisions of previous estimates less sales of
+reserves during the same period. 
+Formation. A
+succession of sedimentary beds that were deposited under the same general
+geologic conditions. 
+Gross acre. An
+acre in which a working interest is owned. 
+Gross well. A well
+in which a working interest is owned. 
+Horizontal
+wells. Wells which are drilled at angles greater than 70
+degrees from vertical. 
+Lease operating
+expenses. The expenses incurred in the lifting of oil or
+natural gas from a producing formation to the surface, constituting part of the
+current operating expenses of a working interest, and also including labor,
+superintendence, supplies, repairs, maintenance, allocated overhead costs, and
+other expenses incidental to production, but not including lease acquisition,
+drilling, or completion costs. 
+MBbl. One thousand
+barrels of oil or other liquid hydrocarbons. 
+MMBbl. One million
+barrels of oil or other liquid hydrocarbons. 
+MBOE. One thousand
+barrels of oil equivalent. Oil equivalents are determined using the
+volumetric ratio of six Mcf of natural gas to one Bbl of oil. 
+MMBOE. One million
+barrels of oil equivalent. Oil equivalents are determined using the
+volumetric ratio of six Mcf of natural gas to one Bbl of oil. 
+Mcf. One thousand
+cubic feet, used in reference to natural gas. 
+22 
+MCFE. One thousand
+cubic feet of natural gas equivalent. Natural gas equivalents are
+determined using the volumetric ratio of six Mcf of natural gas to one Bbl of
+oil. 
+MMcf. One million
+cubic feet, used in reference to natural gas. 
+MMCFE. One million
+cubic feet of natural gas equivalent. Natural gas equivalents are
+determined using the volumetric ratio of six Mcf of natural gas to one Bbl of
+oil. 
+MMBtu. One million
+British Thermal Units. A British Thermal Unit is the amount of heat
+required to raise the temperature of a one-pound mass of water by one degree
+Fahrenheit. 
+Net acres or net
+wells. The sum of our fractional working interests owned in
+gross acres or gross wells. 
+Net asset value per
+share. The result of the fair market value of total assets
+less total liabilities, divided by the total number of outstanding shares of
+common stock. 
+NYMEX. New York
+Mercantile Exchange. 
+PV-10 value. The
+present value of estimated future gross revenue to be generated from the
+production of estimated net proved reserves, net of estimated production and
+future development costs, based on prices used in estimating the proved
+reserves and costs in effect as of the date indicated (unless such costs are
+subject to change pursuant to contractual provisions), without giving effect to
+non-property related expenses such as general and administrative expenses, debt
+service, future income tax expenses, or depreciation, depletion, and
+amortization, discounted using an annual discount rate of ten
+percent. While this measure does not include the effect of income
+taxes as it would in the use of the standardized measure of discounted future
+net cash flows calculation, it does provide an indicative representation of the
+relative value of the Company on a comparative basis to other companies and from
+period to period. 
+Productive well. A
+well that is producing oil or natural gas or that is capable of commercial
+production. 
+Proved
+reserves. With respect to reserves as of December 31, 2009,
+and dates thereafter, the applicable SEC definition of proved reserves is those
+quantities of oil and gas, which, by analysis of geoscience and engineering
+data, can be estimated with reasonable certainty to be economically producible –
+from a given date forward, from known reservoirs, and under existing economic
+conditions, operating methods, and government regulations – prior to the time at
+which contracts providing the right to operate expire, unless evidence indicates
+that renewal is reasonably certain, regardless of whether deterministic or
+probabilistic methods are used for the estimation. Existing economic
+conditions include prices and costs at which economic producibility from a
+reservoir is to be determined, and the price to be used is the average price
+during the 12-month period prior to the ending date of the period covered by the
+report, determined as an unweighted arithmetic average of the
+first-day-of-the-month price for each month within such period, unless prices
+are defined by contractual arrangements, excluding escalations based upon future
+conditions. With respect to reserves as of dates prior to
+December 31, 2009, the applicable SEC definition of proved reserves
+was the estimated quantities of crude oil, natural gas, and natural gas liquids
+which geological and engineering data demonstrate with reasonable certainty to
+be recoverable in future years from known reservoirs under existing economic and
+operating conditions, meaning prices and costs as of the date the estimate is
+made. 
+Recompletion. A
+completion in an existing wellbore in a formation other than that in which the
+well has previously been completed. 
+Reserve
+life. Expressed in years, represents the estimated net proved
+reserves at a specified date divided by actual production for the preceding
+12-month period. 
+Reserve
+replacement. Reserve replacement metrics are used as
+indicators of a company’s ability to replenish annual production volumes and
+grow its reserves, and provide information related to how successful a company
+is at growing its proved reserve base. These are believed to be
+useful non-GAAP measures that are widely utilized 
+23 
+within the exploration and production industry, as well as by
+investors. They are easily calculable metrics, and the information used to
+calculate these metrics is included in Note 16 – Disclosures about Oil and Gas
+Producing Activities of the Notes to Consolidated Financial Statements included
+in this report. It should be noted that reserve replacement metrics
+have limitations. They are limited because they typically vary widely
+based on the extent and timing of new discoveries and property
+acquisitions. Their predictive and comparative value is also limited
+for the same reasons. In addition, since the metrics do not embed the
+cost or timing of future production of new reserves, they cannot be used as a
+measure of value creation. The calculations of various reserve
+replacement metrics are explained below.
+Reserve replacement – Drilling,
+excluding revisions. Calculated as a numerator comprised of
+the sum of reserve extensions and discoveries and infill reserves in an existing
+proved field divided by production for that same period. This metric is an
+indicator of the relative success a company is having in replacing its
+production through drilling activity. 
+Reserve replacement – Drilling,
+including revisions. Calculated as a numerator comprised of
+the sum of reserve extensions, discoveries, and infill reserves, and revisions
+and previous estimates in an existing proved field divided by production for
+that same period. This metric is an indicator of the relative success
+a company is having in replacing its production through drilling
+activity. 
+Reserve replacement –
+Drilling and
+acquisitions, excluding revisions. Calculated as a numerator
+comprised of the sum of reserve acquisitions and reserve extensions and
+discoveries and infill reserves in an existing proved field divided by
+production for that same period. This metric is an indicator of the
+relative success a company is having in replacing its production through
+drilling and acquisition activities. 
+Reserve replacement –
+Drilling and
+acquisitions, including revisions. Calculated as a numerator
+comprised of the sum of reserve acquisitions and reserve extensions,
+discoveries, and infill reserves, and revisions and previous estimates in an
+existing proved field divided by production for that same
+period. This metric is an indicator of the relative success a company
+is having in replacing its production through drilling and acquisition
+activities. 
+Reserve replacement percentage – All
+in, excluding sales of reserves. The sum of reserve extensions
+and discoveries, infill drilling, reserve acquisitions, and reserve revisions of
+previous estimates for a specified period of time divided by production for that
+same period. 
+Reserve replacement percentage –All
+in, including sales of reserves. The sum of sales of reserves,
+infill drilling, reserve extensions and discoveries, reserve acquisitions, and
+reserve revisions of previous estimates for a specified period of time divided
+by production for that same period. 
+Reservoir. A
+porous and permeable underground formation containing a natural accumulation of
+producible oil and/or natural gas that is confined by impermeable rock or water
+barriers and is individual and separate from other
+reservoirs. 
+Resource play. A
+term used to describe an accumulation of oil and/or natural gas resources known
+to exist over a large area expanse, which when compared to a conventional play
+typically has a lower expected geological and/or commercial development
+risk. 
+Royalty. The
+amount or fee paid to the owner of mineral rights, expressed as a percentage or
+fraction of gross income from oil and natural gas produced and sold unencumbered
+by expenses relating to the drilling, completing, and operating of the affected
+well. 
+Royalty
+interest. An interest in an oil and natural gas property
+entitling the owner to shares of oil and natural gas production free of costs of
+exploration, development, and production operations. 
+Seismic. An
+exploration method of sending energy waves or sound waves into the earth and
+recording the wave reflections to indicate the type, size, shape, and depth of
+subsurface rock formations. 
+24 
+Shale. Fine-grained
+sedimentary rock composed mostly of consolidated clay or mud. Shale
+is the most frequently occurring sedimentary rock. 
+Standardized measure of discounted
+future net cash flows. The discounted future net cash flows
+relating to proved reserves based on prices used in estimating the reserves,
+year-end costs, and statutory tax rates, and a ten percent annual discount
+rate. The information for this calculation is included in the note
+regarding disclosures about oil and gas producing activities contained in the
+Notes to Consolidated Financial Statements included in this Form
+10-K. 
+Undeveloped
+acreage. Lease acreage on which wells have not been drilled or
+completed to a point that would permit the production of commercial quantities
+of oil or natural gas, regardless of whether such acreage contains estimated net
+proved reserves. 
+Undeveloped
+reserves. Reserves that are expected to be recovered from new
+wells on undrilled acreage, or from existing wells where a relatively major
+expenditure is required for recompletion. With respect to reserves as
+of December 31, 2009, and dates thereafter, the applicable SEC definition of
+undeveloped reserves provides that undrilled locations can be classified as
+having undeveloped reserves only if a development
+plan has been adopted indicating that they are scheduled to be drilled within
+five years, unless the specific circumstances justify a longer
+time. 
+Working
+interest. The operating interest that gives the owner the
+right to drill, produce, and conduct operating activities on the property and to
+share in the production, sales, and costs. 
+25 
+ITEM
+1A. RISK
+FACTORS 
+In
+addition to the other information included in this Form 10-K, the following risk
+factors should be carefully considered when evaluating St. Mary. 
+Risks
+Related to Our Business 
+Oil
+and natural gas prices are volatile, and declines in prices adversely affect our
+profitability, financial condition, cash flows, access to capital, and ability
+to grow. 
+Our
+revenues, operating results, profitability, future rate of growth, and the
+carrying value of our oil and natural gas properties depend heavily on the
+prices we receive for oil and natural gas sales. Oil and natural gas
+prices also affect our cash flows available for capital expenditures and other
+items, our borrowing capacity, and the amount and value of our oil and natural
+gas reserves. For example, the amount of our borrowing base under our
+credit facility is subject to periodic redeterminations based on oil and natural
+gas prices specified by our bank group at the time of
+redetermination. In addition, we may have oil and natural gas
+property impairments or downward revisions of estimates of proved reserves if
+prices fall significantly. 
+Historically,
+the markets for oil and natural gas have been volatile and they are likely to
+continue to be volatile. Wide fluctuations in oil and natural gas
+prices may result from relatively minor changes in the supply of and demand for
+oil and natural gas, market uncertainty, and other factors that are beyond our
+control, including: 
+· 
+Global
+and domestic supplies of oil and natural gas, and the productive capacity
+of the industry as a whole 
+· 
+The
+level of consumer demand for oil and natural
+gas 
+· 
+Overall
+global and domestic economic
+conditions 
+· 
+Weather
+conditions 
+· 
+The
+availability and capacity of transportation or refining facilities in
+regional or localized areas that may affect the realized price for oil or
+natural gas 
+· 
+The
+price and level of foreign imports of crude oil, refined petroleum
+products, and liquefied natural gas 
+· 
+The
+price and availability of alternative
+fuels 
+· 
+Technological
+advances affecting energy
+consumption 
+· 
+The
+ability of the members of the Organization of Petroleum Exporting
+Countries to agree to and maintain oil price and production
+controls 
+· 
+Political
+instability or armed conflict in oil or natural gas producing
+regions 
+· 
+Strengthening
+and weakening of the U.S dollar relative to other
+currencies 
+· 
+Governmental
+regulations and taxes. 
+These
+factors and the volatility of oil and natural gas markets make it extremely
+difficult to predict future oil and natural gas price movements with any
+certainty. Declines in oil or natural gas prices would reduce our
+revenues and could also reduce the amount of oil and natural gas that we can
+produce economically, which could have a materially adverse effect on
+us. 
+26 
+Continued
+weakness in economic conditions or uncertainty in financial markets may have
+material adverse impacts on our business that we cannot predict. 
+U.S. and
+global economies and financial systems have recently experienced turmoil and
+upheaval characterized by extreme volatility and declines in prices of
+securities, diminished liquidity and credit availability, inability to access
+capital markets, the bankruptcy, failure, collapse or sale of financial
+institutions, increased levels of unemployment, and an unprecedented level of
+intervention by the U.S. federal government and other
+governments. Although some portions of the economy appear to have
+stabilized and there have been signs of the beginning of recovery, the extent
+and timing of a recovery, and whether it can be sustained, are
+uncertain. Continued weakness in the U.S. or global economies could
+materially adversely affect our business and financial condition. For
+example: 
+· 
+the
+demand for oil and natural gas in the U.S. has declined and may remain at
+low levels or further decline if economic conditions remain weak, and
+continue to negatively impact our revenues, margins, profitability,
+operating cash flows, liquidity and financial
+condition 
+· 
+the
+tightening of credit or lack of credit availability to our customers could
+adversely affect our ability to collect our trade
+receivables 
+· 
+our
+ability to access the capital markets may be restricted at a time when we
+would like, or need, to raise capital for our business, including for
+exploration and/or development of our
+reserves 
+· 
+our
+commodity hedging arrangements could become ineffective if our
+counterparties are unable to perform their obligations or seek bankruptcy
+protection. 
+If
+we are unable to replace reserves, we will not be able to sustain
+production. 
+Our
+future operations depend on our ability to find, develop, or acquire oil and
+natural gas reserves that are economically producible. Our properties
+produce oil and natural gas at a declining rate over time. In order
+to maintain current production rates, we must locate and develop or acquire new
+oil and natural gas reserves to replace those being depleted by
+production. In addition, competition for the acquisition of producing
+oil and natural gas properties is intense and many of our competitors have
+financial and other resources needed to evaluate and integrate acquisitions that
+are substantially greater than those available to us. Therefore, we
+may not be able to acquire oil and natural gas properties that contain
+economically producible reserves, or we may not be able to acquire such
+properties at prices acceptable to us. Without successful drilling or
+acquisition activities, our reserves, production, and revenues will decline over
+time. 
+Substantial
+capital is required to replace our reserves. 
+We must
+make substantial capital expenditures to find, acquire, develop, and produce oil
+and natural gas reserves. Future cash flows and the availability of
+financing are subject to a number of factors, such as the level of production
+from existing wells, prices received for oil and natural gas sales, our success
+in locating and developing and acquiring new reserves, and the orderly
+functioning of credit and capital markets. When oil or natural gas
+prices decrease or if we encounter operating difficulties that result in our
+cash flows from operations being less than expected, we must reduce our capital
+expenditures unless we can raise additional funds through debt or equity
+financing or the divestment of assets. Debt or equity financing may
+not always be available to us in sufficient amounts or on acceptable terms, and
+the proceeds offered to us for potential divestitures may not always be of
+acceptable value to us. 
+When our
+revenues decrease due to lower oil or natural gas prices, decreased production,
+or other reasons, and if we cannot obtain capital through our revolving credit
+facility, other acceptable debt or equity financing arrangements, or the sale of
+non-core assets, our ability to execute development plans, replace our reserves,
+secure our acreage, or maintain production levels could be greatly
+limited. 
+27 
+The debt
+and equity financing markets have recently been constrained due to the global
+and domestic economic and financial downturn, and it is possible that
+circumstances may arise where one or more of the twelve participating banks in
+our credit facility, at some point, may not be able to fulfill their portion of
+the lending commitments to us under the facility. Adverse conditions
+in the credit markets may increase the cost of borrowings and decrease our
+ability to access new sources of capital. 
+Competition
+in our industry is intense, and many of our competitors have greater financial,
+technical, and human resources than we do. 
+We face
+intense competition from major oil companies, independent oil and natural gas
+exploration and production companies, financial buyers, and institutional and
+individual investors who seek oil and natural gas property investments
+throughout the world, as well as the equipment, expertise, labor, and materials
+required to operate oil and natural gas properties. Many of our
+competitors have financial, technical, and other resources vastly exceeding
+those available to us, and many oil and natural gas properties are sold in a
+competitive bidding process in which our competitors may be able and willing to
+pay more for development prospects and productive properties, or in which our
+competitors have technological information or expertise that is not available to
+us to evaluate and successfully bid for the properties. In addition,
+shortages of equipment, labor, or materials as a result of intense competition
+may result in increased costs or the inability to obtain those resources as
+needed. We may not be successful in acquiring and developing
+profitable properties in the face of this competition. 
+We also
+compete for human resources. Over the last few years, the need for
+talented people across all disciplines in the industry has grown, while the
+number of people available has been constrained. 
+The
+actual quantities and present values of our proved oil and natural gas reserves
+may be less than we have estimated. 
+This Form
+10-K and other SEC filings by us contain estimates of our proved oil and natural
+gas reserves and the estimated future net revenues from those
+reserves. These estimates are based on various assumptions, including
+assumptions required by the SEC relating to oil and natural gas prices, drilling
+and operating expenses, capital expenditures, taxes, timing of operations, and
+availability of funds. The process of estimating oil and natural gas
+reserves is complex. The process involves significant decisions and
+assumptions in the evaluation of available geological, geophysical, engineering,
+and economic data for each reservoir. These estimates are dependent
+on many variables, and therefore changes often occur as these variables
+evolve. Therefore, these estimates are inherently
+imprecise. 
+Actual
+future production, oil and natural gas prices, revenues, production taxes,
+development expenditures, operating expenses, and quantities of producible oil
+and natural gas reserves will most likely vary from those
+estimated. Any significant variance could materially affect the
+estimated quantities of and present values related to proved reserves disclosed
+by us, and the actual quantities and present values may be less than we have
+previously estimated. In addition, we may adjust estimates of proved
+reserves to reflect production history, results of exploration and development
+activity, prevailing oil and natural gas prices, costs to develop and operate
+properties, and other factors, many of which are beyond our
+control. Our properties may also be susceptible to hydrocarbon
+drainage from production on adjacent properties. 
+As of
+December 31, 2009, approximately 18 percent, or 142 BCFE, of our estimated
+proved reserves were proved undeveloped, and approximately 9 percent, or 73
+BCFE, were proved developed non-producing. Estimates of proved
+undeveloped reserves and proved developed non-producing reserves are nearly
+always based on volumetric calculations rather than the performance data used to
+estimate producing reserves. In order to develop our proved
+undeveloped reserves, we estimate approximately $296 million of capital
+expenditures would be required. Production revenues from proved
+developed non-producing reserves will not be realized until sometime in the
+future and after some investment of capital. In order to bring
+production on-line for our proved developed non-producing reserves, we estimate
+capital expenditures of approximately $44 million will be deployed in future
+years. Although we have estimated our reserves and the costs
+associated with these reserves in accordance with industry standards, estimated
+costs may not be accurate, development may not occur as scheduled and actual
+results may not occur as estimated. The balance of our currently
+anticipated capital 
+28 
+expenditures
+for 2010 is directed towards projects that are not yet classified within the
+construct of proved reserves as defined by Regulation S-X promulgated by the
+SEC. 
+You
+should not assume that the PV-10 value and standardized measure of discounted
+future net cash flows included in this Form 10-K represent the current market
+value of our estimated proved oil and natural gas
+reserves. Management has based the estimated discounted future net
+cash flows from proved reserves on price and cost assumptions required by the
+SEC, whereas actual future prices and costs may be materially higher or
+lower. For example, values of our reserves as of December 31, 2009,
+were estimated using a calculated 12-month average sales price of $3.87 per
+MMBtu of natural gas (NYMEX Henry Hub spot price) and $61.18 per Bbl of oil
+(NYMEX West Texas Intermediate spot price). We then adjust these base
+prices to reflect appropriate basis, quality, and location differentials over
+that period in estimating our proved reserves. During 2009, our
+monthly average realized natural gas prices, excluding the effect of hedging,
+were as high as $5.48 per Mcf and as low as $2.96 per Mcf. For the
+same period, our monthly average realized oil prices before hedging were as high
+as $70.31 per Bbl and as low as $30.37 per Bbl. Many other factors
+will affect actual future net cash flows, including: 
+· 
+Amount
+and timing of actual production 
+· 
+Supply
+and demand for oil and natural gas 
+· 
+Curtailments
+or increases in consumption by oil purchasers and natural gas
+pipelines 
+· 
+Changes
+in government regulations or taxes. 
+The
+timing of production from oil and natural gas properties and of related expenses
+affects the timing of actual future net cash flows from proved reserves, and
+thus their actual present value. Our actual future net cash flows
+could be less than the estimated future net cash flows for purposes of computing
+PV-10 values. In addition, the ten percent discount factor required
+by the SEC to be used to calculate PV-10 values for reporting purposes is not
+necessarily the most appropriate discount factor given actual interest rates,
+costs of capital, and other risks to which our business and the oil and natural
+gas industry in general are subject. 
+Reserve
+estimates as of December 31, 2009, have been prepared under the SEC’s new rules
+for oil and gas reporting that are effective for fiscal years ending on or after
+December 31, 2009. These new rules require SEC reporting companies to
+prepare their reserve estimates using, among other things, revised reserve
+definitions and revised pricing based on 12-month unweighted
+first-day-of-the-month average pricing, instead of the prior requirement to use
+pricing at the end of the period. The SEC has released only limited
+interpretive guidance regarding reporting of reserve estimates under the new
+rules and may not issue further interpretive guidance on the new rules in the
+near future. The interpretation of these rules and their
+applicability in different situations remains unclear in many
+respects. Changing interpretations of the rules or disagreements with
+our interpretations could result in revisions to our reserve estimates or
+write-downs in our reserves. 
+Our
+property acquisitions may not be worth what we paid due to uncertainties in
+evaluating recoverable reserves and other expected benefits, as well as
+potential liabilities. 
+Successful
+property acquisitions require an assessment of a number of factors beyond our
+control. These factors include exploration potential, future oil and
+natural gas prices, operating costs, and potential environmental and other
+liabilities. These assessments are not precise and their accuracy is
+inherently uncertain. 
+In
+connection with our acquisitions, we perform a customary review of the acquired
+properties that will not necessarily reveal all existing or potential
+problems. In addition, our review may not allow us to fully assess
+the potential deficiencies of the properties. We do not inspect every
+well, and even when we inspect a well we may not discover structural,
+subsurface, or environmental problems that may exist or arise. We may
+not be entitled to contractual indemnification for pre-closing liabilities,
+including environmental liabilities. Normally, we acquire interests
+in properties on an “as is” basis with limited remedies for breaches of
+representations and warranties. 
+29 
+In
+addition, significant acquisitions can change the nature of our operations and
+business if the acquired properties have substantially different operating and
+geological characteristics or are in different geographic locations than our
+existing properties. To the extent acquired properties are
+substantially different than our existing properties, our ability to efficiently
+realize the expected economic benefits of such acquisitions may be
+limited. 
+Integrating
+acquired properties and businesses involves a number of other special risks,
+including the risk that management may be distracted from normal business
+concerns by the need to integrate operations and systems as well as retain and
+assimilate additional employees. Therefore, we may not be able to
+realize all of the anticipated benefits of our acquisitions. 
+Exploration
+and development drilling may not result in commercially producible
+reserves. 
+Oil and
+natural gas drilling and production activities are subject to numerous risks,
+including the risk that no commercially producible oil or natural gas will be
+found. The cost of drilling and completing wells is often uncertain,
+and oil and natural gas drilling and production activities may be shortened,
+delayed, or canceled as a result of a variety of factors, many of which are
+beyond our control. These factors include: 
+· 
+Unexpected
+drilling conditions 
+· 
+Title
+problems 
+· 
+Pressure
+or geologic irregularities in
+formations 
+· 
+Equipment
+failures or accidents 
+· 
+Hurricanes
+or other adverse weather conditions 
+· 
+Compliance
+with environmental and other governmental
+requirements 
+· 
+Shortages
+or delays in the availability of or increases in the cost of drilling rigs
+and crews, fracture stimulation crews and equipment, chemicals, and
+supplies. 
+The
+prevailing prices of oil and natural gas affect the cost of and the demand for
+drilling rigs, production equipment, and related services. However,
+changes in costs may not occur simultaneously with corresponding changes in
+commodity prices. The availability of drilling rigs can vary
+significantly from region to region at any particular time. Although
+land drilling rigs can be moved from one region to another in response to
+changes in levels of demand, an undersupply of rigs in any region may result in
+drilling
+delays and higher drilling costs for the rigs that are available in that
+region. In addition, the recent economic and financial downturn has
+adversely affected the financial condition of some drilling contractors, which
+may constrain the availability of drilling services in some areas. 
+Another
+significant risk inherent in our drilling plans is the need to obtain drilling
+permits from state, local, and other governmental authorities. Delays
+in obtaining regulatory approvals and drilling permits, including delays which
+jeopardize our ability to realize the potential benefits from leased properties
+within the applicable lease periods, the failure to obtain a drilling permit for
+a well, or the receipt of a permit with unreasonable conditions or costs could
+have a materially adverse effect on our ability to explore on or develop our
+properties. 
+The wells
+we drill may not be productive and we may not recover all or any portion of our
+investment in such wells. The seismic data and other technologies we
+use do not allow us to know conclusively prior to drilling a well if oil or
+natural gas is present, or whether it can be produced
+economically. The cost of drilling, completing, and operating a well
+is often uncertain, and cost factors can adversely affect the economics of a
+project. Drilling activities can result in dry holes or wells that
+are productive but do not produce sufficient net revenues after operating and
+other costs to cover initial drilling and completion costs. 
+30 
+Drilling
+results in our newer shale plays, such as the Eagle Ford, Haynesville, and
+Marcellus shales, may be more uncertain than in shale plays that are more
+developed and have longer established production histories. For
+example, our experience with horizontal drilling in these shales, as well as the
+industry’s drilling and production history, is more limited than in the Woodford
+shale play, and we have less information with respect to the ultimate
+recoverable reserves and the production decline rates in these shales than we
+have in other areas in which we operate. Completion techniques that
+have proven to be successful in other shale formations to maximize recoveries
+are being used in the early development of these new shales; however, we can
+provide no assurance of the ultimate success of these drilling and completion
+techniques. Moreover, the recent growth in exploration in the
+Marcellus shale has drawn intense scrutiny from environmental interest groups,
+regulatory agencies, and other governmental entities. As a result, we
+may face significant opposition to our operations in that area that may make it
+difficult to obtain permits and other needed authorizations to operate or
+otherwise make operating more costly or difficult than operating
+elsewhere. 
+In
+addition, a significant part of our strategy involves increasing our drilling
+location inventories for multi-year programs scheduled out over several
+years. Such multi-year drilling inventories can be more susceptible
+to long-term horizon uncertainties that could materially alter the occurrence or
+timing of actual drilling. Because of these uncertainties, we do not
+know if the potential drilling locations we have identified will ever be
+drilled, although we have the present intent to do so, or if we will be able to
+produce oil or natural gas from these or any other potential drilling
+locations. 
+Our
+future drilling activities may not be successful. Our overall
+drilling success rate or our drilling success rate within a particular area may
+decline. In addition, we may not be able to obtain any options or
+lease rights in potential drilling locations that we
+identify. Although we have identified numerous potential drilling
+locations, we may not be able to economically produce oil or natural gas from
+all of them. 
+Our
+hedging activities may result in financial losses or may limit the prices that
+we receive for oil and natural gas sales. 
+To manage
+our exposure to price risks in the sale of our oil and natural gas production,
+we enter into commodity price risk management arrangements periodically with
+respect to a portion of our current or future production. We have
+hedged a significant portion of anticipated future production from our currently
+producing properties using zero-cost collars and swaps. As of
+December 31, 2009, we were in a net accrued liability position of approximately
+$81 million with respect to our oil and natural gas hedging activities. These
+activities may expose us to the risk of financial loss in certain circumstances,
+including instances in which: 
+· 
+Our
+production is less than expected 
+· 
+One
+or more counterparties to our hedge contracts default on their contractual
+obligations 
+· 
+There
+is a widening of price differentials between delivery points for our
+production and the delivery point assumed in the hedge
+arrangement. 
+The risk
+of one or more counterparties defaulting on their obligations is heightened by
+the recent global and domestic economic and financial downturn affecting many
+banks and other financial institutions, including our counterparties and their
+affiliates. These circumstances may adversely affect the ability of
+our counterparties to meet their obligations to us pursuant to hedge
+transactions, which could reduce our revenues and cash flows from realized hedge
+settlements. As a result, our financial condition, results of
+operations, and cash flows could be materially adversely affected if our
+counterparties default on their contractual obligations under our hedge
+contracts. 
+In
+addition, commodity price hedging may limit the prices that we receive for our
+oil and natural gas sales if oil or natural gas prices rise substantially over
+the price established by the hedge. Some of our hedging transactions
+use derivative instruments that may involve basis risk. Basis risk in
+a hedging contract can occur when the change in the index upon which the hedge
+is based does not correlate well to the change in the index upon which the
+hedged production is valued, thereby making the hedge less
+effective. For example, a change in 
+31 
+the NYMEX
+price used for hedging certain volumes of production may not correlate exactly
+to the change in the regional price used for the sale of that
+production. 
+The
+inability of one or more of our customers to meet their obligations may
+adversely affect our financial results. 
+Substantially
+all of our accounts receivable result from oil and natural gas sales or joint
+interest billings to third parties in the energy industry. This
+concentration of customers and joint interest owners may impact our overall
+credit risk in that these entities may be similarly affected by various economic
+and other conditions, including the recent global and domestic economic and
+financial downturn. 
+Future
+oil and natural gas price declines or unsuccessful exploration efforts may
+result in write-downs of our asset carrying values. 
+We follow
+the successful efforts method of accounting for our oil and natural gas
+properties. All property acquisition costs and costs of exploratory
+and development wells are capitalized when incurred, pending the determination
+of whether proved reserves have been discovered. If proved reserves
+are not discovered with an exploratory well, the costs of drilling the well are
+expensed. 
+The
+capitalized costs of our oil and natural gas properties, on a field basis,
+cannot exceed the estimated undiscounted future net cash flows of that
+field. If net capitalized costs exceed undiscounted future net
+revenues, we generally must write down the costs of each such field to the
+estimated discounted future net cash flows of that field. Unproved
+properties are evaluated at the lower of cost or fair market
+value. As a result of significant oil and natural gas price declines
+in the second half of 2008, we incurred impairment of proved property
+write-downs, impairment of unproved properties, and goodwill impairment totaling
+$302.2 million, $39.0 million, and $9.5 million, respectively, during
+2008. In addition, we incurred impairment of proved property
+write-downs and impairment of unproved properties totaling $174.8 million and
+$45.4 million, respectively, during 2009. Significant further
+declines in oil or natural gas prices in the future or unsuccessful exploration
+efforts could cause further impairment write-downs of capitalized
+costs. 
+We review
+the carrying value of our properties quarterly based on prices in effect as of
+the end of each quarter. Once incurred, a write-down of oil and
+natural gas properties cannot be reversed at a later date, even if oil or
+natural gas prices increase. 
+Lower
+oil or natural gas prices could limit our ability to borrow under our revolving
+credit facility. 
+Our
+revolving credit facility has a maximum commitment amount of $678 million,
+subject to a borrowing base that the lenders periodically redetermine based on
+the bank group’s assessment of the value of our oil and natural gas properties,
+which in turn is based in part on oil and natural gas prices. The
+current borrowing base under our credit facility is $900 million, which was
+determined as of September 29, 2009. Declines in oil or natural gas
+prices in the future could limit our borrowing base and reduce our ability to
+borrow under the credit facility. Additionally, the pending
+divestitures of non-core properties could result in a reduction of our borrowing
+base. 
+Our
+amount of debt may limit our ability to obtain financing for acquisitions, make
+us more vulnerable to adverse economic conditions, and make it more difficult
+for us to make payments on our debt. 
+As of
+December 31, 2009, we had $267 million, net of debt discount, of total long-term
+senior unsecured debt outstanding under our 3.50% Senior Convertible Notes due
+2027, and $188 million of secured debt outstanding under our revolving credit
+facility. As of February 16, 2010, we had an outstanding balance of
+$211.0 million drawn against our revolving credit facility, resulting in
+$467.0 million of available debt capacity under our revolving credit
+facility assuming the borrowing conditions of this facility were
+met. Our long-term debt represented 32 percent of our total book
+capitalization as of December 31, 2009. 
+32 
+Our
+amount of debt could have important consequences for our operations,
+including: 
+· 
+Making
+it more difficult for us to obtain additional financing in the future for
+our operations and potential acquisitions, working capital requirements,
+capital expenditures, debt service, or other general corporate
+requirements 
+· 
+Requiring
+us to dedicate a substantial portion of our cash flows from operations to
+the repayment of our debt and the service of interest costs associated
+with our debt, rather than to productive
+investments 
+· 
+Limiting
+our operating flexibility due to financial and other restrictive
+covenants, including restrictions on incurring additional debt, making
+acquisitions, and paying dividends 
+· 
+Placing
+us at a competitive disadvantage compared to our competitors that have
+less debt 
+· 
+Making
+us more vulnerable in the event of adverse economic or industry conditions
+or a downturn in our business. 
+Our
+ability to make payments on our debt and to refinance our debt and fund planned
+capital expenditures will depend on our ability to generate cash in the
+future. This, to a certain extent, is subject to general economic,
+financial, competitive, legislative, regulatory, and other factors that are
+beyond our control. If our business does not generate sufficient cash
+flow from operations or future sufficient borrowings are not available to us
+under our revolving credit facility or from other sources, we might not be able
+to service our debt or fund our other liquidity needs. If we are
+unable to service our debt, due to inadequate liquidity or otherwise, we may
+have to delay or cancel acquisitions, defer capital expenditures, sell equity
+securities, sell assets, or restructure or refinance our debt. We
+might not be able to sell our equity securities, sell our assets, or restructure
+or refinance our debt on a timely basis or on satisfactory terms or at
+all. In addition, the terms of our existing or future debt
+agreements, including our existing and future credit agreements, may prohibit us
+from pursuing any of these alternatives. The indenture for our 3.50%
+Senior Convertible Notes due 2027 provides that under certain circumstances we
+have the option to settle
+our obligations under these notes through the issuance of shares of our common
+stock if we so elect. 
+Our debt
+instruments, including our revolving credit facility agreement, also permit us
+to incur additional debt in the future. In addition, the entities we
+may acquire in the future could have significant amounts of debt outstanding
+which we could be required to assume in connection with the acquisition, or we
+may incur our own significant indebtedness to consummate an
+acquisition. 
+As
+discussed above, our revolving credit facility is subject to periodic borrowing
+base redeterminations. We could be forced to repay a portion of our
+bank borrowings in the event of a downward redetermination of our borrowing
+base, and we may not have sufficient funds to make such repayment at that
+time. If we do not have sufficient funds and are otherwise unable to
+negotiate renewals of our borrowing base or arrange new financing, we may be
+forced to sell significant assets. 
+We
+are subject to operating and environmental risks and hazards that could result
+in substantial losses. 
+Oil and
+natural gas operations are subject to many risks, including well blowouts,
+craterings, explosions, uncontrollable flows of oil, natural gas, or well
+fluids, fires, adverse weather such as hurricanes in the South Texas & Gulf
+Coast region, freezing conditions, formations with abnormal pressures, pipeline
+ruptures or spills, pollution, releases of toxic gas, and other environmental
+risks and hazards. If any of these types of events occurs, we could
+sustain substantial losses. 
+Under
+certain limited circumstances we may be liable for environmental damage caused
+by previous owners or operators of properties that we own, lease, or
+operate. As a result, we may incur substantial liabilities to third
+parties or governmental entities, which could reduce or eliminate funds
+available for exploration, development, or acquisitions, or cause us to incur
+losses. 
+33 
+We
+maintain insurance against some, but not all, of these potential risks and
+losses. We have significant but limited coverage for sudden
+environmental damages. We do not believe that insurance coverage for
+the full potential liability that could be caused by sudden environmental
+damages or insurance coverage for environmental damage that occurs over time is
+available at a reasonable cost. In addition, pollution and
+environmental risks generally are not fully insurable. Further, we
+may elect not to obtain other insurance coverage under circumstances where we
+believe that the cost of available insurance is excessive relative to the risks
+presented. Accordingly, we may be subject to liability or may lose
+substantial portions of certain properties in the event of environmental or
+other damages. If a significant accident or other event occurs and is
+not fully covered by insurance, we could suffer a material loss. 
+Following
+the severe Atlantic hurricanes in 2004, 2005, and 2008, the insurance markets
+suffered significant losses. As a result, insurance coverage for wind
+storms has become substantially more expensive, and future availability and
+costs of coverage are uncertain. 
+Our
+operations are subject to complex laws and regulations, including environmental
+regulations that result in substantial costs and other risks. 
+Federal,
+state, and local authorities extensively regulate the oil and natural gas
+industry. Legislation and regulations affecting the industry are
+under constant review for amendment or expansion, raising the possibility of
+changes that may affect, among other things, the pricing or marketing of oil and
+natural gas production. Noncompliance with statutes and regulations
+may lead to substantial penalties and the overall regulatory burden on the
+industry increases the cost of doing business and, in turn, decreases
+profitability. 
+Governmental
+authorities regulate various aspects of oil and natural gas drilling and
+production, including the drilling of wells (through permit and bonding
+requirements), the spacing of wells, the unitization or pooling of interests in
+oil and natural gas properties, environmental matters, safety standards, the
+sharing of markets, production limitations, plugging and abandonment standards,
+and restoration. Under
+certain circumstances, federal authorities may require any of our ongoing or
+planned operations on federal leases to be delayed, suspended, or
+terminated. Any such delay, suspension, or termination could have a
+materially adverse effect on our operations. 
+Our
+operations are also subject to complex and constantly changing environmental
+laws and regulations adopted by federal, state, and local governmental
+authorities in jurisdictions where we are engaged in exploration or production
+operations. New laws or regulations, or changes to current
+requirements, could result in material costs or claims with respect to
+properties we own or have owned. We will continue to be subject to
+uncertainty associated with new regulatory interpretations and inconsistent
+interpretations between state and federal agencies. Under existing or
+future environmental laws and regulations, we could face significant liability
+to governmental authorities and third parties, including joint and several as
+well as strict liability, for discharges of oil, natural gas, or other
+pollutants into the air, soil, or water, and we could be required to spend
+substantial amounts on investigations, litigation, and
+remediation. Existing environmental laws or regulations, as currently
+interpreted or enforced, or as they may be interpreted, enforced, or altered in
+the future, may have a materially adverse effect on us. 
+Proposed
+federal and state legislation and regulatory initiatives relating to hydraulic
+fracturing could result in increased costs and additional operating restrictions
+or delays. 
+The U.S.
+Congress is currently considering legislation that would amend the Safe Drinking
+Water Act to eliminate an existing exemption from federal regulation of
+hydraulic fracturing activities and require the disclosure of chemical additives
+used by the oil and gas industry in the hydraulic fracturing
+process. Hydraulic fracturing is a common process in our industry of
+creating artificial cracks, or fractures, in deep underground rock formations
+through the pressurized injection of water, sand and other additives to enable
+oil or natural gas to move more easily through the rock pores to a production
+well. This process is often necessary to produce commercial
+quantities of oil and natural gas from many reservoirs, especially shale rock
+formations. We routinely utilize hydraulic fracturing techniques in
+many of our reservoirs, and our Eagle Ford, Haynesville, Marcellus, and Woodford
+shale programs utilize or contemplate the utilization of hydraulic
+fracturing. Currently, 
+34 
+regulation
+of hydraulic fracturing is primarily conducted at the state level through
+permitting and other compliance requirements. If adopted, the
+proposed amendment to the Safe Drinking Water Act could result in additional
+regulations and permitting requirements at the federal level. In
+addition, various states are also studying or considering various additional
+regulatory measures related to hydraulic fracturing. Additional
+regulations and permitting requirements could lead to significant operational
+delays and increased operating costs, and make it more difficult to perform
+hydraulic fracturing. 
+Proposed
+legislation to eliminate or reduce certain federal income tax incentives and
+deductions available to oil and gas exploration and production companies could,
+if enacted into law, have a material adverse effect on our results of operations
+and cash flows. 
+In 2009,
+the “Oil Industry Tax Break Repeal Act of 2009” was introduced in the U.S.
+Senate. This bill proposes amendments to the Internal Revenue Code of
+1986 to eliminate or reduce certain federal income tax incentives and deductions
+currently available to oil and gas exploration and production
+companies. The proposed amendments include the elimination or
+reduction of current deductions for intangible drilling and development costs,
+percentage depletion allowances, and the manufacturing deduction for oil and gas
+properties. President Obama’s proposed Fiscal Year 2011 Budget also
+contemplates these proposed tax law amendments. If some or all of
+these provisions are enacted into law, our effective tax rate and current income
+tax expense will increase, potentially significantly, which would increase cash
+requirements to pay income tax thereby reducing cash flows from operating
+activities, which in turn will reduce cash available for drilling and other
+exploration and development activities. 
+Enactment
+of a Pennsylvania severance tax on natural gas could adversely impact the
+economic viability of exploiting natural gas drilling and production
+opportunities in our Marcellus Shale resource play. 
+The
+Governor of the Commonwealth of Pennsylvania has proposed to its legislature the
+adoption of a severance tax on the production of natural gas in
+Pennsylvania. The amount of the proposed tax is five percent of the
+value of the natural gas at the wellhead, plus $0.047 per Mcf of natural gas
+severed. Our Marcellus Shale acreage is located in
+Pennsylvania. If Pennsylvania adopts such a severance tax, it could
+impact the economic viability of exploiting natural gas drilling and production
+opportunities in the Marcellus Shale. 
+Possible
+legislation and regulations related to global warming and climate change could
+have an adverse effect on our operations and the demand for oil and natural
+gas. 
+On
+December 15, 2009, the U.S. Environmental Protection Agency (EPA) officially
+published its findings that emissions of carbon dioxide, which is a byproduct of
+the burning of refined oil products and natural gas, methane, which is a primary
+component of natural gas, and other “greenhouse gases” present an endangerment
+to human health and the environment because emissions of such gases are,
+according to the EPA, contributing to warming of the Earth’s atmosphere and
+other climatic changes. These findings by the EPA allow the agency to
+proceed with the adoption and implementation of regulations that would restrict
+emissions of greenhouse gases under existing provisions of the federal Clean Air
+Act. In late September 2009, the EPA had proposed two sets of
+regulations in anticipation of finalizing its findings that would require a
+reduction in emissions of greenhouse gases from motor vehicles and that could
+also lead to the imposition of greenhouse gas emission limitations in Clean Air
+Act permits for certain stationary sources. In addition, on September
+22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas
+emissions from specified large greenhouse gas emission sources in the United
+States beginning in 2011 for emissions occurring in 2010. The
+adoption and implementation of any regulations imposing reporting obligations
+on, or limiting emissions of greenhouse gases from, our equipment and operations
+could require us to incur increased costs to reduce emissions of greenhouse
+gases associated with our operations and could adversely affect demand for the
+oil and natural gas that we produce. 
+In
+addition, on June 26, 2009, the U.S. House of Representatives passed the
+“American Clean Energy and Security Act of 2009” (ACESA), which would establish
+an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse
+gases, including carbon dioxide and methane. ACESA would require a
+17% reduction in 
+35 
+greenhouse
+gas emissions from 2005 levels by 2020, and just over an 80% reduction of such
+emissions by 2050. Under this legislation, the EPA would issue a
+capped and steadily declining number of tradable emissions allowances to certain
+major sources of greenhouse gas emissions so that such sources could continue to
+emit greenhouse gases into the atmosphere. The cost of these
+allowances would be expected to escalate significantly over time. The
+net effect of ACESA would be to impose increasing costs on the combustion of
+carbon-based fuels such as oil, refined petroleum products, and natural
+gas. The U.S. Senate has begun work on its own legislation for
+restricting domestic greenhouse gas emissions, and the Obama administration has
+indicated its support of legislation to reduce greenhouse gas emissions through
+an emission allowance system. In addition, several states have
+considered initiatives to regulate emissions of greenhouse gases, primarily
+through the planned development of greenhouse gas emissions inventories and/or
+regional greenhouse gas cap and trade programs. Although it is not
+possible at this time to predict when the U.S. Senate may act on climate change
+legislation or how any bill passed by the Senate would be reconciled with ACESA,
+any future federal or state laws or regulations that may be adopted to address
+greenhouse gas emissions could require us to incur increased operating costs and
+could adversely affect the demand for the oil and natural gas that we
+produce. 
+The
+adoption of derivatives legislation by Congress and related regulations could
+have an adverse impact on our ability to hedge risks associated with our
+business. 
+The U.S.
+Congress is currently considering legislation to increase the regulatory
+oversight of the over-the-counter derivatives markets in order to promote more
+transparency in those markets, and impose restrictions on certain derivatives
+transactions, which could affect the use of derivatives in hedging
+transactions. ACESA contains provisions that would prohibit private
+energy commodity derivative and hedging transactions. ACESA would
+expand the power of the Commodity Futures Trading Commission (CFTC) to regulate
+derivative transactions related to energy commodities, including oil and natural
+gas, and to mandate clearance of such derivative contracts through registered
+derivative clearing organizations. Under ACESA, the CFTC’s expanded
+authority over energy derivatives would terminate upon the adoption of general
+legislation covering derivative regulatory reform. The Chairman of
+the CFTC has announced that the CFTC intends to conduct hearings to determine
+whether to set limits on trading and positions in commodities with finite
+supply, particularly energy commodities, such as crude oil, natural gas and
+other energy products. The CFTC also is evaluating whether position
+limits should be applied consistently across all markets and
+participants. In addition, the Treasury Department recently has
+indicated that it intends to propose legislation to subject all OTC derivative
+dealers and all other major OTC derivative market participants to substantial
+supervision and regulation, including by imposing conservative capital and
+margin requirements and strong business conduct standards. Derivative
+contracts that are not cleared through central clearinghouses and exchanges may
+be subject to substantially higher capital and margin
+requirements. Although it is not possible at this time to predict
+whether or when Congress may act on derivatives legislation or how any climate
+change bill approved by the Senate would be reconciled with ACESA, any new laws
+or regulations in this area may result in increased costs and cash collateral
+requirements for the types of oil and gas derivative instruments we use to hedge
+and otherwise manage our financial risks related to swings in oil and gas
+commodity prices, may impose additional restrictions on our trading and
+commodity positions, and could have an adverse effect on our ability to hedge
+risks associated with our business and on the cost of our hedging
+activity. 
+Our
+ability to sell oil and natural gas and/or receive market prices for our oil and
+natural gas production may be adversely affected by constraints on pipelines and
+gathering systems owned by others and various transportation
+interruptions. 
+The
+marketability of our oil and natural gas production depends in part on the
+availability, proximity, and capacity of pipeline transportation and gathering
+systems owned by third parties. The lack of available transportation
+capacity on these systems and facilities could result in the shutting-in of
+producing wells, the delay or discontinuance of development plans for
+properties, or lower price realizations. Although we have some
+contractual control over the transportation of our production, material changes
+in these business relationships could materially affect our
+operations. Federal and state regulation of oil and natural gas
+production and transportation, tax and energy policies, changes in supply and
+demand, pipeline pressures, damage to or 
+36 
+destruction
+of pipelines, and general economic conditions could adversely affect our ability
+to produce, gather, and transport oil and natural gas. 
+In
+particular, if drilling in the Eagle Ford, Haynesville, and Marcellus shales
+continues to be successful, the amount of natural gas being produced by us and
+others could exceed the capacity of the various gathering and intrastate or
+interstate transportation pipelines currently available in these
+areas. If this occurs, it will be necessary for new pipelines and
+gathering systems to be built. Because of the current economic
+climate, certain pipeline projects that are being considered for these areas may
+not be developed due to lack of financing. In addition, capital
+constraints could limit our ability to build intrastate gathering systems
+necessary to transport our gas to interstate pipelines. In such
+event, we might have to shut in our wells to wait for a pipeline connection or
+capacity and/or sell natural gas production at significantly lower prices than
+those quoted on NYMEX, which would adversely affect our results of operations
+and cash flows. 
+A portion
+of our natural gas and oil production in any region may be interrupted, or shut
+in, from time to time for numerous reasons, including as a result of weather
+conditions, accidents, loss of pipeline or gathering system access, field labor
+issues or strikes, or we might voluntarily curtail production in response to
+market conditions. If a substantial amount of our production is
+interrupted at the same time, it could temporarily adversely affect our cash
+flows. 
+New
+technologies may cause our current exploration and drilling methods to become
+obsolete. 
+The oil
+and gas industry is subject to rapid and significant advancements in technology,
+including the introduction of new products and services using new
+technologies. As competitors use or develop new technologies, we may
+be placed at a competitive disadvantage, and competitive pressures may force us
+to implement new technologies at a substantial cost. In addition,
+competitors may have greater financial, technical and personnel resources that
+allow them to enjoy technological advantages and may in the future allow them to
+implement new technologies before we can. One or more of the
+technologies that we currently use or that we may implement in the future may
+become obsolete. We cannot be certain that we will be able to
+implement technologies on a timely basis or at a cost that is acceptable to
+us. If we are unable to maintain technological advancements
+consistent with industry standards, our operations and financial condition may
+be adversely affected. 
+Risks
+Related to Our Common Stock 
+The
+price of our common stock may fluctuate significantly, which may result in
+losses for investors. 
+From
+January 1, 2009 to February 16, 2010, the closing daily sales price of our
+common stock as reported by the New York Stock Exchange ranged from a low of
+$11.58 per share to a high of $37.89 per share. We expect our stock
+to continue to be subject to fluctuations as a result of a variety of factors,
+including factors beyond our control. These factors
+include: 
+· 
+Changes
+in oil or natural gas prices 
+· 
+Variations
+in quarterly drilling, recompletions, acquisitions, and operating
+results 
+· 
+Changes
+in financial estimates by securities
+analysts 
+· 
+Changes
+in market valuations of comparable
+companies 
+· 
+Additions
+or departures of key personnel 
+· 
+Future
+sales of our common stock 
+· 
+Changes
+in the national and global economic
+outlook. 
+37 
+We may
+fail to meet expectations of our stockholders and/or of securities analysts at
+some time in the future, and our stock price could decline as a
+result. 
+Our
+certificate of incorporation and by-laws have provisions that discourage
+corporate takeovers and could prevent stockholders from receiving a takeover
+premium on their investment. 
+Our
+certificate of incorporation and by-laws contain provisions that may have the
+effect of delaying or preventing a change of control. These
+provisions, among other things, provide for non-cumulative voting in the
+election of members of the Board of Directors and impose procedural requirements
+on stockholders who wish to make nominations for the election of Directors or
+propose other actions at stockholder meetings. These provisions,
+alone or in combination with each other and with the shareholder rights plan
+described below, may discourage transactions involving actual or
+potential changes of control, including transactions that otherwise could
+involve payment of a premium over prevailing market prices to stockholders for
+their common stock. 
+Under our
+shareholder rights plan, if the Board of Directors determines that the terms of
+a potential acquisition do not reflect the long-term value of St. Mary, the
+Board of Directors could allow the holder of each outstanding share of our
+common stock, other than those held by the potential acquirer, to purchase one
+additional share of our common stock with a market value of twice the exercise
+price. This prospective dilution to a potential acquirer would make
+the acquisition impracticable unless the terms were improved to the satisfaction
+of the Board of Directors. The existence of the plan may impede a
+takeover not supported by our Board, even though such takeover may be desired by
+a majority of our stockholders or may involve a premium over the prevailing
+stock price. 
+Shares
+eligible for future sale may cause the market price of our common stock to drop
+significantly, even if our business is doing well. 
+The
+potential for sales of substantial amounts of our common stock in the public
+market may have a materially adverse effect on our stock price. As of
+February 16, 2010, 62,590,571 shares of our common stock were freely tradable
+without substantial restriction or the requirement of future registration under
+the Securities Act of 1933. Also, as of that date, options to
+purchase 1,271,292 shares of our common stock were outstanding, of which all
+were exercisable. These options are exercisable at prices ranging
+from $7.97 to $20.87 per share. In addition, restricted stock units
+providing for the issuance of up to a total of 403,968 shares of our common
+stock and 1,141,113 performance share awards (“PSAs”) were
+outstanding. The PSAs represent the right to receive, upon settlement
+of the PSAs after the completion of a three-year performance period, a number of
+shares of our common stock that may be from zero to two times the number of PSAs
+granted, depending on the extent to which the underlying performance criteria
+have been achieved and the extent to which the PSAs have vested. As
+of February 16, 2010, there were 62,777,688 shares of common stock
+outstanding, which is net of 126,893 treasury shares. 
+We
+may not always pay dividends on our common stock. 
+The
+payment of future dividends remains at the discretion of the Board of Directors,
+and will continue to depend on our earnings, capital requirements, financial
+condition, and other factors. In addition, the payment of dividends
+is subject to covenants in our credit facility, including a covenant regarding
+the level of our current ratio of current assets to current liabilities and a
+limit on the annual dividend rate that we may pay to no more than $0.25 per
+share. The Board of Directors may determine in the future to reduce
+the current semi-annual dividend rate of $0.05 per share, or discontinue the
+payment of dividends altogether. 
+38 
+ITEM
+1B. UNRESOLVED
+STAFF COMMENTS 
+St. Mary
+has no unresolved comments from the SEC staff regarding its periodic or current
+reports under the Securities Exchange Act of 1934. 
+ITEM
+3. LEGAL
+PROCEEDINGS 
+From time
+to time, we may be involved in litigation relating to claims arising out of our
+operations in the normal course of business. As of the date of this report, no
+legal proceedings are pending against us that we believe individually or
+collectively could have a materially adverse effect upon our financial
+condition, results of operations or cash flows. 
+ITEM
+4. SUBMISSION
+OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+There
+were no matters submitted to a vote of our security holders during the fourth
+quarter of 2009. 
+ITEM
+4A. EXECUTIVE
+OFFICERS OF THE REGISTRANT 
+The
+following table sets forth the names, ages and positions held by St. Mary’s
+executive officers. The age of the executive officers is as of
+February 16, 2010. 
+Name 
+Age 
+Position 
+Anthony
+J. Best 
+60 
+Chief
+Executive Officer and President 
+Javan
+D. Ottoson 
+51 
+Executive
+Vice President and Chief Operating Officer 
+A.
+Wade Pursell 
+44 
+Executive
+Vice President and Chief Financial Officer 
+Mark
+D. Mueller 
+45 
+Senior
+Vice President and Regional Manager 
+Milam
+Randolph Pharo 
+57 
+Senior
+Vice President and General Counsel 
+Paul
+M. Veatch 
+43 
+Senior
+Vice President and Regional Manager 
+Stephen
+C. Pugh 
+51 
+Senior
+Vice President and Regional Manager 
+Kenneth
+J. Knott 
+45 
+Vice
+President – Business Development and Land and Assistant
+Secretary 
+Gregory
+T. Leyendecker 
+52 
+Vice
+President and Regional Manager 
+John
+R. Monark 
+57 
+Vice
+President – Human Resources 
+Lehman
+E. Newton, III 
+54 
+Vice
+President and Regional Manager 
+David
+J. Whitcomb 
+47 
+Vice
+President – Marketing 
+Dennis
+A. Zubieta 
+43 
+Vice
+President – Engineering and Evaluation 
+Mark
+T. Solomon 
+41 
+Controller 
+Anthony
+J. Best joined St. Mary in June 2006 as President and Chief Operating
+Officer. In December 2006 Mr. Best relinquished his position as Chief
+Operating Officer when Javan D. Ottoson was elected to that
+office. Mr. Best was elected Chief Executive Officer of St. Mary in
+February 2007. From November 2005 to June 2006, Mr. Best was
+developing a business plan and securing capital commitments for a new
+exploration and production entity. From 2003 to October 2005, Mr.
+Best was President and Chief Executive Officer of Pure Resources, Inc., an
+independent oil and natural gas exploration and production company that was a
+subsidiary of Unocal, where he managed all of Unocal’s onshore U.S. assets. From
+2000 to 2002, Mr. Best had an oil and gas consulting practice working with
+various energy firms. From 1979 to 2000, Mr. Best was with ARCO in a variety of
+positions, including a period as President - ARCO Permian, President - ARCO
+Latin America, Field Manager for Prudhoe Bay and VP - External Affairs for ARCO
+Alaska. 
+Javan D.
+Ottoson joined St. Mary in December 2006 as Executive Vice President and Chief
+Operating Officer. Mr. Ottoson has been in the oil and gas industry
+for over 25 years. From April 2006 until he joined St. Mary in
+December 2006, Mr. Ottoson was Senior Vice President – Drilling and Engineering
+at Energy Partners, Ltd., an independent oil and natural gas exploration and
+production company, where his responsibilities included overseeing all aspects
+of its drilling and engineering functions. Mr. Ottoson managed Permian Basin
+assets for Pure Resources, Inc., a Unocal subsidiary, and its successor owner,
+Chevron, from July 2003 to April 2006. From April 2000 to July 2003,
+Mr. Ottoson owned and operated a homebuilding company in Colorado
+and 
+39 
+ran his family farm. Prior to 2000 Mr. Ottoson worked
+for ARCO in management and operational roles. These roles included
+President of ARCO China, Commercial Director of ARCO British, and Vice President
+of Operations and Development, ARCO Permian.
+A. Wade
+Pursell joined St. Mary in September 2008 as Executive Vice President and Chief
+Financial Officer. Mr. Pursell was Executive Vice President and Chief
+Financial Officer for Helix Energy Solutions Group, Inc., a global provider of
+life-of-field services and development solutions to offshore energy producers
+and an oil and gas producer, from February 2007 to September
+2008. From October 2000 to February 2007, he was Senior Vice
+President and Chief Financial Officer of Helix. He joined Helix in
+May 1997, as Vice President — Finance and Chief Accounting Officer. From
+1988 through 1997 he was with Arthur Andersen LLP, lastly as an Experienced
+Manager specializing in the offshore services industry. 
+Mark D.
+Mueller joined St. Mary in September 2007 as Senior Vice
+President. Mr. Mueller was appointed as the Regional Manager of the
+Rocky Mountain Region effective January 1, 2008. Mr. Mueller has been
+in the energy industry for over 22 years. From September 2006 to
+September 2007 he was Vice President and General Manager at Samson Exploration
+Ltd., an oil and gas exploration and production company that was a subsidiary of
+Samson Investment Company, in Calgary, Canada, where his responsibilities
+included fiscal performance, reserves, and all operational functions of the
+company. From April 2005 until its sale in August 2006, Mr. Mueller
+was Vice President and General Manager for Samson Canada Ltd., an oil and gas
+exploration and production company that was a subsidiary of Samson Investment
+Company, where he was responsible for all business units and the eventual sale
+of the company. Mr. Mueller joined Samson Canada Ltd. as Project
+Manager in May 2003 to build a new basin-centered gas business unit and was Vice
+President from December 2003 to August 2006. Prior to joining Samson,
+Mr. Mueller was West Central Alberta Engineering Manager for Northrock Resources
+Ltd., a Canadian oil and gas company that was a wholly-owned subsidiary of
+Unocal Corporation, in Calgary, Canada. From 1986 to 2003, Mr.
+Mueller held positions of increasing responsibility in engineering and
+management for Unocal throughout North America and Southeast Asia. 
+Milam
+Randolph Pharo was appointed Senior Vice President and General Counsel in August
+2008. He joined St. Mary as Vice President – Land and Assistant
+Secretary in January 1996. In May 1998 he was appointed Vice
+President – Land and Legal and Assistant Secretary. From 1979 until
+joining St. Mary, Mr. Pharo served in private practice as an attorney
+specializing in oil and gas matters. 
+Paul M.
+Veatch was appointed Senior Vice President and Regional Manager in March
+2006. Mr. Veatch joined St. Mary in April 2001 as Regional A & D
+Engineer. He was Vice President – General Manager, ArkLaTex from
+August 2004 to March 2006 and Manager of Engineering for the ArkLaTex region
+from April 2003 to August 2004. 
+Stephen
+C. Pugh joined St. Mary as Senior Vice President and Regional Manager of the
+ArkLaTex Region in July 2007. Mr. Pugh has over 27 years of
+experience in the oil and gas industry. Prior to joining St. Mary,
+Mr. Pugh was Managing Director for Scotia Waterous, a global leader in oil
+and gas merger and acquisition advisory services. Mr. Pugh was
+responsible for new business development, managing client relationships and
+providing merger and acquisition advice, including transaction execution to
+clients in the energy sector. Mr. Pugh held this position from July
+2006 to July 2007. Prior to joining Scotia Waterous, Mr. Pugh had
+over 17 years of experience in acquisitions and divestitures, operations and
+engineering with Burlington Resources, and its successor-by-merger,
+ConocoPhillips. His most recent position with Burlington Resources,
+Inc. and ConocoPhillips was General Manager, Engineering and Operations – Gulf
+Coast, a position he held from May 2004 to June 2006. Prior to that,
+he was Vice President - Acquisitions and Divestitures for Burlington Resources
+Canada. He held that position from May 2000 to May
+2004. Mr. Pugh began his career with Superior Oil (subsequently Mobil
+Oil) in Lafayette, Louisiana, where he worked in production, drilling, and
+reservoir engineering. 
+Gregory
+T. Leyendecker was appointed Vice President and Regional Manager in July
+2007. Mr. Leyendecker joined St. Mary in December 2006 as Operations
+Manager for the South Texas & Gulf Coast Region in Houston. Mr.
+Leyendecker has worked for 28 years in the energy industry and held various
+positions with Unocal Corporation, an independent oil and natural gas
+exploration and production company, from 1980 until its 
+40 
+acquisition
+in 2005. During this time he was the Asset Manager for Unocal Gulf
+Region USA from 2003 to June 2004 and Production and Reservoir Engineering
+Technology Manager for Unocal from June 2004 to August 2005. He was
+appointed Drilling and Workover Manager for the San Joaquin Valley business unit
+of Chevron, as successor-by-merger of Unocal Corporation, in Bakersfield,
+California in August 2005 and held this position until January 2006. Immediately
+prior to joining St. Mary, Mr. Leyendecker was Vice President of Drilling
+Management Services from February 2006 to November 2006 for Enventure Global
+Technology, a provider of solid expandable tubular technology. 
+John R.
+Monark was appointed Vice President – Human Resources in July
+2008. Mr. Monark joined St. Mary in May of 2008 as Director of
+Human Resources. Mr. Monark was Director – Human Resources for
+JF Shea Corporation, a leading construction and homebuilding company, from 2004
+to May 2008. He served as Vice President – Human Resources for Pameco
+Corporation, a distributor of HVAC systems and equipment and refrigeration
+products, from 2000 to 2004. From 1996 to 2000 he served as Vice
+President – Human Resources for CH2M HILL. 
+Lehman E.
+Newton, III joined St. Mary in December 2006 as General Manager for the Midland
+office and was appointed Vice President and Regional Manager of the Permian
+region in June 2007. Mr. Newton has over 28 years of experience in
+engineering, operations, and business development roles in the exploration and
+production industry. From November 2005 to November 2006 Mr. Newton
+served as Project Manager for one of Chevron’s largest lower 48
+projects. Mr. Newton joined Pure Resources in February 2003 as the
+Business Development Manager and worked in that capacity until October
+2005. Mr. Newton was a founding partner in Westwin Energy, an
+independent Permian Basin E&P firm, from June 2000 to January
+2003. Prior to that, Mr. Newton spent 21 years with ARCO in various
+engineering, operations and management roles. These assignments
+included Asset Manager, ARCO’s East Texas operations, Vice President, Business
+Development, ARCO Permian, and Vice President of Operations and Development,
+ARCO Permian. 
+Kenneth
+J. Knott was appointed Vice President – Business Development and Land and
+Assistant Secretary in August 2008. Mr. Knott joined St. Mary in
+November 2000 as Senior Landman for the South Texas & Gulf Coast region in
+Lafayette, LA and later assumed the position of South Texas & Gulf Coast
+Regional Land Manager when the office was moved to Houston in March 2004. 
+Mr. Knott has worked for 22 years in the energy industry holding various Land
+and Business Development positions with ARCO, Vastar Resources, and BP
+Amoco. Between 1987 and 1993, Mr. Knott worked for ARCO in a land capacity
+handling land and business development responsibilities in several geographic
+areas, such as Permian, Mid-Continent, Michigan, and California. Upon ARCO’s
+spin-off of Vastar Resources in 1993, he joined Vastar Resources as a Senior
+Landman working the Gulf Coast and Gulf of Mexico regions until 1999, at which
+time he assumed the role of Director of Business Development for the Gulf Coast
+region. He remained in that capacity until the merger of Vastar Resources into
+BP Amoco in September 2000, whereby he assumed a Senior Landman position working
+the Gulf Coast region. 
+David J.
+Whitcomb was appointed Vice President – Marketing in August 2008. Mr.
+Whitcomb joined St. Mary in November 1994 as Gas Contract Analyst and was
+named Assistant Vice President of Gas Marketing in October 1995. In
+March 2007 his responsibilities were expanded to include oil marketing at which
+time his title was changed to Assistant Vice President – Director of
+Marketing. From 1991 until the time of his employment with St. Mary,
+Mr. Whitcomb worked for Anderman/Smith Operating Company as a Gas Contract
+Analyst during which time his primary responsibility was to resolve take-or-pay
+gas contract disputes. Mr. Whitcomb began his career in the industry
+in 1986 with Apache Corporation where he worked as an internal auditor for
+several years and then moved into marketing where he worked as a Gas Controller
+and Gas Contracts Analyst. 
+Dennis A.
+Zubieta was appointed Vice President – Engineering and Evaluation in August
+2008. Mr. Zubieta joined St. Mary in June 2000 as Corporate
+A&D Engineer, assumed the role of Reservoir Engineer in February 2003, and
+was appointed Reservoir Engineering Manager in August 2005. Mr. Zubieta
+was employed by Burlington Resources (formerly known as Meridian Oil, Inc.) from
+June 1988 to May 2000 in various operations and reservoir engineering
+capacities. 
+41 
+Mark T.
+Solomon was appointed Controller in January 2007. Mr. Solomon was
+also appointed Acting Principal Financial Officer from April 30, 2008, to
+September 8, 2008, which was during the period of time that the Company’s Chief
+Financial Officer position was vacant. Mr. Solomon joined St. Mary in
+1996. He served as Financial Reporting Manager from February 1999 to
+September 2002, Assistant Vice President – Financial Reporting from September
+2002 to May 2006 and Assistant Vice President - Assistant Controller from May
+2006 to January 2007. Prior to joining St. Mary, Mr. Solomon was an
+auditor with Ernst & Young. 
+42 
+PART
+II 
+ITEM
+5. 
+MARKET
+FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
+PURCHASES OF EQUITY SECURITIES 
+Market
+Information. St. Mary’s common stock is currently traded on
+the New York Stock Exchange under the symbol SM. The range of high
+and low closing prices for the quarterly periods in 2009 and 2008, as reported
+by the New York Stock Exchange: 
+Quarter
+Ended 
+High 
+Low 
+December
+31, 2009 
+$ 
+38.05 
+$ 
+29.80 
+September
+30, 2009 
+33.62 
+17.13 
+June
+30, 2009 
+23.48 
+12.05 
+March
+31, 2009 
+24.60 
+11.21 
+December
+31, 2008 
+$ 
+35.81 
+$ 
+14.76 
+September
+30, 2008 
+65.58 
+32.53 
+June
+30, 2008 
+65.00 
+37.73 
+March
+31, 2008 
+39.95 
+31.70 
+43 
+PERFORMANCE
+GRAPH 
+The
+following performance graph compares the cumulative return on St. Mary’s common
+stock, not including dividend payments, for the period beginning December 31,
+2004, and ending on December 31, 2009, with the cumulative total returns of
+the Dow Jones U.S. Exploration and Production Board Index, and the Standard
+& Poor’s 500 Stock Index. 
+COMPARE
+5-YEAR CUMULATIVE TOTAL RETURN 
+“Performance
+Graph” shall be deemed to be “furnished” but not “filed” with the Securities and
+Exchange Commission. 
+Holders. As of
+February 16, 2010, the number of record holders of St. Mary’s common stock was
+111. Based on inquiry, management believes that the number of
+beneficial owners of our common stock is approximately 17,000. 
+Dividends. St.
+Mary has paid cash dividends to stockholders every year since
+1940. Annual dividends of $0.05 per share were paid in each of the
+years 1998 through 2004. Annual dividends of $0.10 per share were
+paid in 2005 through 2009. We expect that our practice of paying
+dividends on our common stock will continue, although the payment of future
+dividends will continue to depend on our earnings, cash flow, capital
+requirements, financial condition, and other factors. In addition,
+the payment of dividends is subject to covenants in our credit facility,
+including the requirement that we maintain the level of our current ratio of
+current assets to current liabilities and the limitation of our annual dividend
+rate to no more than $0.25 per share per year. Dividends are
+currently paid on a semi-annual basis. Dividends paid totaled $6.2
+million in 2009 and $6.2 million in 2008. 
+Equity Incentive Compensation
+Plan. In May 2009, the shareholders approved an amendment to
+rename the 2006 Equity Incentive Compensation Plan to the Equity Incentive
+Compensation Plan (the “Equity Plan”). 
+Restricted Shares. St. Mary has no restricted shares outstanding as of
+December 31, 2009, a side from Rule 144 restrictions on shares
+for insiders, shares are subject to transfer restrictions under the provisions
+of the Employee Stock Purchase Plan, and shares issued to directors under the
+Equity Plan. 
+44 
+Equity Compensation
+Plans. St. Mary has the Equity Plan under which options and
+shares of St. Mary common stock are authorized for grant or issuance as
+compensation to eligible employees, consultants, and members of the Board of
+Directors. Our stockholders have approved this plan. See
+Note 7 – Compensation Plans in the Notes to Consolidated Financial Statements
+included in Part IV, Item 15 of this report for further information about the
+material terms of our equity compensation plans. The following table
+is a summary of the shares of common stock authorized for issuance under the
+equity compensation plans as of December 31, 2009: 
+(a) 
+(b) 
+(c) 
+Plan
+category 
+Number
+of securities to be issued upon exercise of outstanding options, warrants,
+and rights 
+Weighted-average
+exercise price of outstanding options, warrants, and
+rights 
+Number
+of securities remaining available for future issuance under equity
+compensation plans (excluding securities reflected in column
+(a)) 
+Equity
+compensation plans approved by security holders: 
+Equity
+Incentive Compensation Plan 
+Stock
+options and incentive stock options (1) 
+1,274,920 
+$ 
+13.31 
+- 
+Restricted
+stock (1) 
+408,356 
+- 
+- 
+Performance
+share awards (1)(3) 
+1,145,871 
+$ 
+32.52 
+1,771,009 
+Total
+for Equity Incentive Compensation Plan 
+2,829,147 
+$ 
+22.40 
+1,771,009 
+Employee
+Stock Purchase Plan (2) 
+- 
+- 
+1,468,275 
+Equity
+compensation plans not approved by security holders 
+- 
+- 
+- 
+Total
+for all plans 
+2,829,147 
+$ 
+22.40 
+3,239,284 
+(1) 
+In
+May 2006 the stockholders approved the Equity Plan to authorize the
+issuance of restricted stock, restricted stock units, non-qualified stock
+options, incentive stock options, stock appreciation rights, and
+stock-based awards to key employees, consultants, and members of the Board
+of Directors of St. Mary or any affiliate of St. Mary. The
+Equity Plan serves as the successor to the St. Mary Land &
+Exploration Company Stock Option Plan, the St. Mary Land & Exploration
+Company Incentive Stock Option Plan, the St. Mary Land & Exploration
+Company Restricted Stock Plan, and the St. Mary Land & Exploration
+Company Non-Employee Director Stock Compensation Plan (collectively
+referred to as the “Predecessor Plans”). All grants of equity
+are now made out of the Equity Plan, and no further grants will be made
+under the Predecessor Plans. Each outstanding award under a
+Predecessor Plan immediately prior to the effective date of the Equity
+Plan continues to be governed solely by the terms and conditions of the
+instruments evidencing such grants or issuances. Our Board of
+Directors approved amendments to the Equity Plan on
+March 26, 2008, and the amended plan was approved by
+stockholders at our annual stockholders’ meeting
+May 21, 2008. Our Board of Directors approved
+additional amendments to the Equity Plan on March 26, 2009, and
+the amendments were approved by stockholders at our annual stockholders’
+meeting on May 20, 2009. Awards granted in 2009,
+2008, and 2007 under the Equity Plan were 1,016,931, 932,767, and 135,138,
+respectively. 
+(2) 
+Under
+the St. Mary Land & Exploration Company Employee Stock Purchase Plan
+(the “ESPP”), eligible employees may purchase shares of our common stock
+through payroll deductions of up to 15 percent of their eligible
+compensation. The purchase price of the stock is 85 percent of
+the lower of the fair market value of the stock on the first or last day
+of the six-month offering period, and shares issued under the ESPP through
+December 31, 2009, are restricted for a period of 18 months from
+the date issued. Effective January 1, 2010, shares
+issued under the ESPP will be restricted for a period six months from the
+date issued. The ESPP is intended to qualify under Section 423
+of the Internal Revenue Code. Shares issued under the ESPP
+totaled 86,308, 45,228, and 29,534 in 2009, 2008, and 2007,
+respectively. 
+(3) 
+The
+PSAs represent the right to receive, upon settlement of the PSAs after the
+completion of a three-year performance measurement period, a number of
+shares of our common stock that may be from zero to two times the number
+of PSAs granted, depending on the extent to which the underlying
+performance criteria have been achieved and the extent to which the PSAs
+have vested. The performance criteria for the PSAs are based on
+a combination of our cumulative Total Shareholder Return (“TSR”) for the
+performance period and the relative measure of our TSR compared with the
+TSR an index comprised of certain peer companies for the performance
+period. The current outstanding PSAs were granted on
+August 1, 2009, and 2008, and utilize a three-year performance
+measurement period which began on July 1, 2009, and 2008,
+respectively. On July 1, 2009, the market value per share of our
+common 
+45 
+stock
+was $21.15, and on the date of grant the market value per share of our
+common stock was $23.87. On July 1, 2008, the market
+value per share of our common stock was $62.51, and on the date of grant
+the market value per share of our common stock was $43.11. The
+PSAs do not have an exercise price associated with them, but rather the
+$32.52 price shown in the above table represents the weighted-average per
+share fair value as of December 31, 2009, calculated pursuant to
+ASC Topic 718, which is presented in order to provide additional
+information regarding the potential dilutive effect of the PSAs as of
+December 31, 2009, in view of the share price level at the
+beginning of the performance period which will be utilized to compute the
+TSR measurements for determination of the number of shares to be issued
+upon settlement of the PSAs after completion of the three-year performance
+measurement period. 
+46 
+Issuer Purchases of Equity
+Securities. The following table provides information about
+purchases by the Company or “affiliated purchaser” (as defined in Rule
+10b-18(a)(3) under the Exchange Act) during the quarters and year ended
+December 31, 2009, of shares of the Company’s common stock, which is
+the sole class of equity securities registered by the Company pursuant to
+Section 12 of the Exchange Act. 
+PURCHASES
+OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS 
+Total
+Number of Shares Purchased 
+(1)(2)(3)(4) 
+Average
+Price Paid per Share 
+Total
+Number of Shares Purchased as Part of Publicly Announced
+Program 
+Maximum
+Number of Shares that May Yet be Purchased Under the Program (5) 
+January
+1, 2009 – 
+March 31, 2009 
+58,688 
+$ 
+13.60 
+-0- 
+3,072,184 
+April
+1, 2009 - 
+June 30, 2009 
+341 
+$ 
+18.69 
+-0- 
+3,072,184 
+July
+1, 2009 - 
+September 30,
+2009 
+412 
+$ 
+24.86 
+-0- 
+3,072,184 
+October
+1, 2009 - 
+October 31,
+2009 
+30 
+$ 
+35.36 
+-0- 
+3,072,184 
+November
+1, 2009 - 
+November 30,
+2009 
+86 
+$ 
+34.10 
+-0- 
+3,072,184 
+December
+1, 2009 - 
+December 31,
+2009 
+21,391 
+$ 
+35.34 
+-0- 
+3,072,184 
+Total
+October 1, 2009 - 
+December 31,
+2009 
+21,507 
+$ 
+35.33 
+-0- 
+3,072,184 
+Total 
+80,948 
+$ 
+19.45 
+-0- 
+3,072,184 
+(1) 
+Includes
+a total of 6,500 shares purchased by Anthony J. Best, St. Mary’s President
+and Chief Executive Officer, in open market transactions that were not
+made pursuant to our stock repurchase
+program. 
+(2) 
+Includes
+a total of 5,000 shares purchased by A. Wade Pursell, St. Mary’s Executive
+Vice President and Chief Financial Officer, in open market transactions
+that were not made pursuant to our stock repurchase
+program. 
+(3) 
+Includes
+a total of 10,000 shares purchased by William D.
+Sullivan, a Director of St. Mary, in open market transactions
+that were not made pursuant to our stock repurchase
+program. 
+(4) 
+Includes
+59,448 shares withheld (under the terms of grants under the Equity
+Incentive Compensation Plan) to offset tax withholding obligations that
+occur upon the delivery of outstanding shares underlying restricted stock
+units that were not made pursuant to our stock repurchase
+program. 
+(5) 
+In
+July 2006 our Board of Directors approved an increase in the number of
+shares that may be repurchased under the original August 1998
+authorization to 6,000,000 as of the effective date of the
+resolution. Accordingly, as of the date of this filing, we have
+Board authorization to repurchase 3,072,184 shares of common stock on a
+prospective basis. The shares may be repurchased from time to
+time in open market transactions or privately negotiated transactions,
+subject to market conditions and other factors, including certain
+provisions of St. Mary’s existing bank credit facility agreement and
+compliance with securities laws. Stock repurchases may be
+funded with existing cash balances, internal cash flow, and borrowings
+under St. Mary’s bank credit facility. The stock repurchase program may be
+suspended or discontinued at any
+time. 
+The
+payment of dividends and stock repurchases are subject to covenants in our
+bank credit facility, including the requirement that we maintain certain
+levels of stockholders’ equity and the limitation that does not allow our
+annual dividend rate to exceed $0.25 per
+share. 
+47 
+ITEM
+6. SELECTED
+FINANCIAL DATA 
+The
+following table sets forth supplemental selected financial and operating data
+for St. Mary as of the dates and periods indicated. The financial
+data for each of the five years presented were derived from the consolidated
+financial statements of St. Mary. The following data should be read
+in conjunction with “Management’s Discussion and Analysis of Financial Condition
+and Results of Operations,” which includes a discussion of factors materially
+affecting the comparability of the information presented, and in conjunction
+with St. Mary’s consolidated financial statements included in this
+report. 
+Years
+Ended December 31, 
+2009 
+2008
+(1) 
+2007 (1) 
+2006 
+2005 
+(In
+thousands, except per share data) 
+Total
+operating revenues 
+$ 
+832,201 
+$ 
+1,301,301 
+$ 
+990,094 
+$ 
+787,701 
+$ 
+739,590 
+Net
+income (loss) 
+$ 
+(99,370 
+) 
+$ 
+87,348 
+$ 
+187,098 
+$ 
+190,015 
+$ 
+151,936 
+Net
+income (loss) per share: 
+Basic 
+$ 
+(1.59 
+) 
+$ 
+1.40 
+$ 
+3.02 
+$ 
+3.38 
+$ 
+2.67 
+Diluted 
+$ 
+(1.59 
+) 
+$ 
+1.38 
+$ 
+2.90 
+$ 
+2.94 
+$ 
+2.33 
+Total
+assets at year end 
+$ 
+2,360,936 
+$ 
+2,697,247 
+$ 
+2,572,942 
+$ 
+1,899,097 
+$ 
+1,268,747 
+Long-term
+obligations: 
+Line
+of credit 
+$ 
+188,000 
+$ 
+300,000 
+$ 
+285,000 
+$ 
+334,000 
+$ 
+- 
+Senior
+convertible notes, net of debt discount 
+$ 
+266,902 
+$ 
+258,713 
+$ 
+251,070 
+$ 
+99,980 
+$ 
+99,885 
+Cash
+dividends declared and paid per common share 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+(1) 
+As
+Adjusted, see Note 5 to the Consolidated Financial
+Statements 
+48 
+Supplemental
+Selected Financial and Operations Data 
+Years
+Ended December 31, 
+2009 
+2008 
+2007 
+2006 
+2005 
+(In
+thousands, except per share data) 
+Balance
+Sheet Data 
+Total
+working capital (deficit) 
+$ 
+(87,625 
+) 
+$ 
+15,193 
+$ 
+(92,604 
+) 
+$ 
+22,870 
+$ 
+4,937 
+Total
+stockholders’ equity 
+$ 
+973,570 
+$ 
+1,162,509 
+$ 
+902,574 
+$ 
+743,374 
+$ 
+569,320 
+Weighted-average
+shares outstanding 
+Basic 
+62,457 
+62,243 
+61,852 
+56,291 
+56,907 
+Diluted 
+62,457 
+63,133 
+64,850 
+65,962 
+66,894 
+Reserves 
+Oil
+(MMBbl) 
+53.8 
+51.4 
+78.8 
+74.2 
+62.9 
+Gas
+(Mcf) 
+449.5 
+557.4 
+613.5 
+482.5 
+417.1 
+MCFE 
+772.2 
+865.5 
+1,086.5 
+927.6 
+794.5 
+Production
+and Operational: 
+Oil
+and gas production revenues, including hedging 
+$ 
+756,601 
+$ 
+1,158,304 
+$ 
+936,577 
+$ 
+758,913 
+$ 
+711,005 
+Oil
+and gas production expenses 
+$ 
+206,800 
+$ 
+271,355 
+$ 
+218,208 
+$ 
+176,590 
+$ 
+142,873 
+DD&A 
+$ 
+304,201 
+$ 
+314,330 
+$ 
+227,596 
+$ 
+154,522 
+$ 
+132,758 
+General
+and administrative 
+$ 
+76,036 
+$ 
+79,503 
+$ 
+60,149 
+$ 
+38,873 
+$ 
+32,756 
+Production
+Volumes: 
+Oil
+(MMBbl) 
+6.3 
+6.6 
+6.9 
+6.1 
+5.9 
+Gas
+(Bcf) 
+71.1 
+74.9 
+66.1 
+56.4 
+51.8 
+BCFE 
+109.1 
+114.6 
+107.5 
+92.8 
+87.4 
+Realized
+price – pre hedging: 
+Per
+Bbl 
+$ 
+54.40 
+$ 
+92.99 
+$ 
+67.56 
+$ 
+59.33 
+$ 
+53.18 
+Per
+Mcf 
+$ 
+3.82 
+$ 
+8.60 
+$ 
+6.74 
+$ 
+6.58 
+$ 
+8.08 
+Realized
+price – net of hedging: 
+Per
+Bbl 
+$ 
+56.74 
+$ 
+75.59 
+$ 
+62.60 
+$ 
+56.60 
+$ 
+50.93 
+Per
+Mcf 
+$ 
+5.59 
+$ 
+8.79 
+$ 
+7.63 
+$ 
+7.37 
+$ 
+7.90 
+Expense
+per MCFE: 
+LOE 
+$ 
+1.33 
+$ 
+1.46 
+$ 
+1.31 
+$ 
+1.25 
+$ 
+0.99 
+Transportation 
+$ 
+0.19 
+$ 
+0.19 
+$ 
+0.14 
+$ 
+0.12 
+$ 
+0.09 
+Production
+taxes 
+$ 
+0.37 
+$ 
+0.71 
+$ 
+0.58 
+$ 
+0.54 
+$ 
+0.56 
+DD&A 
+$ 
+2.79 
+$ 
+2.74 
+$ 
+2.12 
+$ 
+1.67 
+$ 
+1.52 
+General
+and administrative 
+$ 
+0.70 
+$ 
+0.69 
+$ 
+0.56 
+$ 
+0.42 
+$ 
+0.37 
+Cash
+Flow: 
+Provided
+by operations 
+$ 
+436,106 
+$ 
+679,190 
+$ 
+632,054 
+$ 
+467,700 
+$ 
+409,379 
+Used
+in investing 
+$ 
+(304,092 
+) 
+$ 
+(673,754 
+) 
+$ 
+(805,134 
+) 
+$ 
+(724,719 
+) 
+$ 
+(339,779 
+) 
+Provided
+by (used in) financing 
+$ 
+(127,496 
+) 
+$ 
+(42,815 
+) 
+$ 
+215,126 
+$ 
+243,558 
+$ 
+(61,093 
+) 
+49 
+ITEM
+7. MANAGEMENT’S
+DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
+OPERATION 
+This
+discussion includes forward-looking statements. Please refer to
+“Cautionary Information about Forward-Looking Statements” in Part I, Items 1 and
+2 of this Form 10-K for important information about these types of
+statements. 
+Overview
+of the Company 
+General
+Overview 
+We are an
+independent energy company focused on the development, exploration,
+exploitation, acquisition, and production of natural gas and crude oil in North
+America. We generate nearly all our revenues and cash flows from the
+sale of produced natural gas and crude oil. Our oil and gas reserves
+and operations are concentrated primarily in the Rocky Mountain Williston Basin;
+the Mid-Continent Anadarko and Arkoma basins; the Permian Basin; the productive
+formations of East Texas and North Louisiana; north central Pennsylvania; the
+Maverick Basin in South Texas; and the onshore Gulf Coast and offshore Gulf of
+Mexico. We have developed a balanced and diverse portfolio of proved
+reserves, development drilling opportunities, and unconventional resource
+prospects. 
+Our
+mission is to deliver outstanding net asset value per share growth to our
+investors via attractive oil and gas investments. Historically, we
+have relied on a strategy of growing through niche acquisitions focused in the
+continental United States. Over the last few years, we have shifted
+our strategy to focus more on capturing potential resource plays earlier and at
+a lower cost. We believe that this shift will allow for more stable
+and predictable production and proved reserves growth. Going forward,
+we will focus on continuing to acquire significant leasehold positions in
+existing and emerging resource plays in North America. 
+In 2009
+we had the following financial and operational results: 
+· 
+Average
+daily gas production of 194.8 MMcf was down five percent from
+2008. Average daily oil production of 17.3 MBbl was down four
+percent from 2008. Average total equivalent daily production
+was 298.8 MMCFE, which was down five percent from
+2008. 
+· 
+Estimated
+proved reserves of 53.8 MMBbls of oil and 449.5 Bcf of natural gas, or
+772.2 BCFE, as of December 31, 2009. This was a decrease of 11
+percent from year-end 2008 proved reserves of 865.5 BCFE and reflects
+the divestiture of 44.2 BCFE of non-strategic properties, 61.6 BCFE in net
+downward performance revisions, and 12.0 BCFE of net positive price
+revisions. We had reserve additions from extensions and
+discoveries and infill drilling of 109.6
+BCFE. 
+· 
+We
+recorded a net loss of $99.4 million and diluted loss per share of $1.59
+for the year ended December 31, 2009. This compares
+with net income of $87.3 million, or $1.38 per diluted share, for the year
+ended December 31, 2008. 
+· 
+Cash
+flow from operating activities of $436.1 million, a decrease of 36 percent
+from 2008. 
+· 
+Costs
+incurred for oil and gas producing activities for the year ended
+December 31, 2009, were $419.0 million, compared with $857.7
+million for the same period in
+2008. 
+Our
+operations are generally funded first through cash flows from operating
+activities and then through borrowings under our existing credit
+facility. The divestiture of non-core assets is also a potential
+source of liquidity. Acquisitions may be funded with proceeds from
+sales of public or private debt and equity, borrowings under our existing
+facility, property sales, and cash flow from operating activities. In
+2009 we
+invested $377.2 million for development and exploration and $41.7 million
+for leasehold. 
+50 
+A major
+determination of the value of our company is the value of our proved
+reserves. At year-end 2009 we had proved reserves of 772.2 BCFE of
+which 58 percent were natural gas and 82 percent were characterized as proved
+developed. There were a number of changes that took effect in 2009
+impacting the calculation of our year-end proved reserves. The SEC
+instituted a number of revisions to its existing oil and gas reporting
+requirements. A key revision to the rules pertains to the use of
+12-month average pricing as opposed to year-end pricing in estimating proved
+reserves. The prices used in the calculation of proved reserve
+estimates as of December 31, 2009, were $61.18 per Bbl and $3.87 per
+MMBTU for oil and natural gas, respectively. These prices were 23
+percent and 33 percent lower, respectively, than the year-end prices that would
+have been used under the SEC’s previous methodology. Additional
+changes in the SEC rules provide for the use of new technology to determine
+proved reserves and the ability to include nontraditional resources in proved
+reserves. In addition to these regulatory changes, in 2009 we began
+recording estimates of proved reserve volumes for properties we believe are
+reasonably certain to generate positive net cash flows on an undiscounted basis,
+which we have the intent to drill, and which meet our internal economic criteria
+for drilling even though they may have a negative PV-10
+value. Previously, we booked proved reserve volumes if the
+properties showed a positive PV-10 value, we had the intent to drill, and the
+wells met our economic criteria. 
+We added
+109.6 BCFE from our drilling program during the year, with our emerging resource
+play in the Eagle Ford shale in the Maverick Basin in South Texas contributing a
+significant portion of those additions. Our programs targeting the
+Woodford shale in eastern Oklahoma and the Bakken/Three Forks formations in the
+North Dakota portion of the Williston Basin also added meaningful additions in
+2009. We sold 44.2 BCFE of proved reserves during the year, with
+roughly 90 percent of those relating to the divestiture of our coalbed methane
+project at Hanging Woman Basin along the border of Montana and
+Wyoming. The balance of the divested properties sold in 2009 was
+non-strategic assets, which were spread across the company. We had a downward
+net revision of 49.6 BCFE that consisted of 61.6 BCFE in net downward
+engineering revisions and a net positive pricing revision of 12.0
+BCFE. The largest portion of the performance revision relates to
+producing properties in our Wolfberry tight oil program in the Permian Basin in
+West Texas. Well performance data collected during 2009 for Wolfberry
+assets at Sweetie Peck and Halff East indicated these assets are underperforming
+our year-end 2008 decline forecasts. Accordingly, we removed roughly
+37 BCFE from proved reserves in the Permian region, primarily related to the
+Wolfberry tight oil program. We believe that a significant portion of
+these reserves, while not meeting the criteria to be booked as proved reserves
+at year-end, are likely to be produced eventually. We also saw a
+downward performance revision of approximately 12 BCFE related to certain Cotton
+Valley assets in our ArkLaTex region. Due to the pricing methodology
+changes noted above, we recognized positive price revisions in our oil-weighted
+Rocky Mountain and Permian regions that offset negative price revisions we
+recognized in the natural gas weighted Mid-Continent, ArkLaTex, and South Texas
+& Gulf Coast regions. Under the previous methodology of using
+year-end pricing for the determination of proved reserves, we would have had an
+increase of four percent in proved reserves to approximately 897
+BCFE. 
+The PV-10
+value of our proved reserves was $1.3 billion as of December 31,
+2009. The after tax value of $1.0 billion as represented by the
+standardized measure calculation is presented in Note 16 – Disclosures about Oil
+and Gas Producing Activities of Part IV, Item 15 of
+this report. A reconciliation between these two amounts is shown
+under Reserves in Part I, Items 1 and 2 of this report. 
+51 
+Reserve
+Replacement, Finding Costs, and Growth 
+Like all
+oil and gas exploration and production companies, we face the challenge of
+growing oil and natural gas reserves. An exploration and production
+company depletes part of its asset base with each unit of oil or gas it
+produces. Our future growth will depend on our ability to
+economically add reserves in excess of production. 
+The
+following table provides various reserve replacement and finding cost metrics
+for the year ended December 31, 2009: 
+Reserve
+Replacement Percentage 
+Finding
+Cost per MCFE 
+Excluding
+sales 
+Including
+sales 
+Excluding
+sales 
+Including
+sales 
+Drilling,
+excluding revisions 
+100% 
+60% 
+$ 
+3.44 
+$ 
+5.77 
+Drilling,
+including revisions 
+55% 
+14% 
+$ 
+6.29 
+$ 
+23.91 
+Drilling
+and acquisitions, excluding revisions 
+100% 
+60% 
+$ 
+3.44 
+$ 
+5.77 
+Drilling
+and acquisitions, including revisions 
+55% 
+14% 
+$ 
+6.29 
+$ 
+23.92 
+Acquisitions 
+N/M 
+N/M 
+N/M 
+N/M 
+All-in 
+55% 
+14% 
+$ 
+6.99 
+$ 
+26.56 
+The
+following table provides three-year average reserve replacement and finding cost
+metrics for the years ended December 31, 2009, 2008, and 2007: 
+Reserve
+Replacement Percentage 
+Finding
+Cost per MCFE 
+Excluding
+sales 
+Including
+sales 
+Excluding
+sales 
+Including
+sales 
+Drilling,
+excluding revisions 
+124% 
+92% 
+$ 
+4.27 
+$ 
+5.77 
+Drilling,
+including revisions 
+48% 
+16% 
+$ 
+11.07 
+$ 
+33.90 
+Drilling
+and acquisitions, excluding revisions 
+162% 
+129% 
+$ 
+3.68 
+$ 
+4.60 
+Drilling
+and acquisitions, including revisions 
+85% 
+53% 
+$ 
+6.97 
+$ 
+11.22 
+Acquisitions 
+37% 
+5% 
+$ 
+1.72 
+$ 
+12.60 
+All-in 
+85% 
+53% 
+$ 
+7.79 
+$ 
+12.53 
+Our
+challenge is to grow net asset value per share, which we believe drives
+appreciation in our stock price over the long term. To accomplish
+this, we believe it is important to economically replace annual production with
+new reserves. We believe annual reserve replacement percentage and
+finding cost amounts are important analytical measures that are widely used by
+investors and industry peers in evaluating and comparing the performance of oil
+and gas companies. While single-year measurements have some meaning
+in terms of a trend, we believe that aberrations, causing both relatively good
+and bad results, will occur over short intervals of time. The
+information used to calculate the above reserve replacement and finding cost
+metrics is included in Note 15 – Oil and Gas Activities and Note 16 –
+Disclosures about Oil and Gas Producing Activities of the Notes to Consolidated
+Financial Statements included in part IV, Item 15 of this report. For
+additional information about these metrics, see the reserve replacement and
+finding cost terms in the Glossary at the end of Part I, Items 1 and 2 of this
+report. 
+52 
+Financial
+Standing and Liquidity 
+During
+and subsequent to the third quarter of 2008, specific issues related to the
+financial sector rippled through the broader economy. The failure or
+takeovers of several large financial institutions adversely impacted the wider
+equity, debt, and credit markets. Financial strength and liquidity
+became increasingly important as investors considered the ability of companies
+to fund their planned levels of activity and to service their debt
+obligations. In addition, fears of prolonged weakness in the global
+economy leading to anemic energy demand resulted in a significant decline in oil
+and natural gas prices. As a result of these events, we entered 2009
+with a business plan designed to operate within our operating cash
+flow. We have maintained a disciplined approach with our capital
+investments during the year, which, combined with higher operating cash flows
+than we anticipated originally, have allowed us to maintain our strong financial
+position and reduce borrowings under our credit facility. Our
+exploration and development program at the beginning of 2009 was designed to
+stay within generated cash flow. We met this goal in
+2009. We continue to believe we have adequate liquidity available to
+us through our credit facility as discussed below under the caption Overview of
+Liquidity and Capital Resources. 
+Oil
+and Gas Prices 
+Our
+financial condition and the results of our operations are significantly affected
+by oil and natural gas commodity prices, which can fluctuate
+dramatically. We sell a majority of our natural gas under contracts
+that use first of the month index pricing, which means that gas produced in a
+given month is sold at the first of the month price regardless of the spot price
+on the day the gas is produced. Our crude oil is sold using contracts
+that pay us either the average of the NYMEX West Texas Intermediate daily
+settlement or the average of alternative posted prices for the periods in which
+the crude oil is produced, adjusted for quality, transportation, and location
+differentials. The following table is a summary of commodity price
+data for the years ended December 31, 2009, 2008, and 2007. 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+Crude Oil (per Bbl): 
+Average
+NYMEX WTI spot price 
+$ 
+61.99 
+$ 
+99.92 
+$ 
+72.23 
+Realized
+price, before the effects of hedging 
+$ 
+54.40 
+$ 
+92.99 
+$ 
+67.56 
+Net
+realized price, including the effects of hedging 
+$ 
+56.74 
+$ 
+75.59 
+$ 
+62.60 
+Natural Gas (per Mcf): 
+Average
+NYMEX Henry Hub spot price 
+$ 
+3.94 
+$ 
+8.89 
+$ 
+6.97 
+Realized
+price, before the effects of hedging 
+$ 
+3.82 
+$ 
+8.60 
+$ 
+6.74 
+Net
+realized price, including the effects of hedging 
+$ 
+5.59 
+$ 
+8.79 
+$ 
+7.63 
+We expect
+future prices for oil and natural gas to be volatile. The comparative
+strength of the U.S. Dollar will likely continue to impact crude prices just as
+changes in domestic industrial demand will continue to impact the price of
+natural gas. The 12-month strip prices for NYMEX WTI crude and NYMEX
+Henry Hub gas as of December 31, 2009, were $82.15 per Bbl and $5.87 per MMBTU,
+respectively; comparable prices as of February 16, 2010, were $79.43 per Bbl and
+$5.76 per MMBTU, respectively. 
+While
+changes in quoted NYMEX oil and natural gas prices are generally used as a basis
+for comparison within our industry, the price we receive for oil and natural gas
+is affected by quality, energy content, location, and transportation
+differentials for these products. We refer to this price as our
+realized price, which excludes the effects of hedging. Our realized
+price is further impacted by the results of our hedging arrangements that are
+settled in the respective periods. We refer to this price as our net
+realized price. For the year ended December 31, 2009, our net natural
+gas price realization was positively impacted by $125.9 million of realized
+hedge settlements and our net oil price realization was positively impacted by
+$14.8 million of realized hedge settlements. 
+53 
+Hedging
+Activities 
+Hedging
+is an important part of our financial risk management program. We
+have a Board-authorized financial risk management policy that governs our
+practices related to hedging. The amount of production we hedge is
+driven by the amount of debt on our consolidated balance sheet and the level of
+capital commitments and long-term obligations we have in place. In
+the case of a significant acquisition of producing properties, we will consider
+hedging a portion of the acquired production in order to protect the economics
+assumed in the acquisition. With the hedges we have in place, we
+believe we have established a base cash flow stream for our future operations,
+and our use of collars for a portion of the hedges allows us to participate in
+upward movements in oil and gas prices while also setting a price floor for a
+portion of our production. Please see Note 10 – Derivative Financial
+Instruments of Part IV, Item 15 of this report for additional information
+regarding our oil and gas hedges, and see the caption, Summary of Oil and Gas Production
+Hedges in Place, later in this section. 
+We
+attempt to qualify our oil and gas derivative instruments as cash flow hedges
+for accounting purposes under Accounting Standards Codification Topic
+815. Changes in the value of our hedge positions are primarily
+reflected in our consolidated balance sheets. A portion of the change
+in the value of our hedge positions is recognized in our consolidated statements
+of operations due to the hedges being partially ineffective. We
+recognized a $20.5 million in non-cash derivative loss for the year ended
+December 31, 2009. 
+The U.S.
+Congress is currently considering recent proposals to increase the regulatory
+oversight of the over-the-counter derivatives markets in order to promote more
+transparency in those markets. Although we cannot predict the
+ultimate outcome of these proposals, new regulations in this area may result in
+increased costs and cash collateral requirements for the types of oil and gas
+derivative instruments we use to hedge and otherwise manage our financial risks
+related to swings in oil and gas commodity prices. 
+2009
+Highlights 
+Developments in emerging resource
+plays. During 2008, the Haynesville shale, the Eagle Ford
+shale, and the Marcellus shale resource plays emerged as significant new sources
+of gas supply for the exploration and production industry. We have
+exposure to each of these plays that, if successful, could provide for
+significant future organic growth in reserves and production. The
+Haynesville shale emerged early in 2008 in northern Louisiana and eastern Texas
+and quickly became the most active resource play in the country. Our
+position was built as a result of prior leasing activity targeting the James
+Lime and Cotton Valley formations. Our Eagle Ford shale position in
+the Maverick Basin in South Texas was built from 2007 through 2009 through a
+combination of property acquisitions, leasing activity, and participation in a
+joint venture with industry partners. Late in 2008 we entered into
+arrangements that allow us to earn or purchase acreage in the Marcellus shale in
+north central Pennsylvania. During 2009 we worked to advance our
+understanding of these plays and move them closer to development
+mode. The most progress was made in our Eagle Ford shale program in
+South Texas. We successfully tested seven wells across our operated
+acreage position during the second half of 2009. The early results
+from this program suggest wells at the southern end of our acreage will produce
+drier gas while wells drilled further north will produce higher BTU-content gas
+and some condensate. We are currently booking only the parallel
+offsets to producing wells as proved undeveloped locations. As a
+result, we believe meaningful potential exists to grow proved reserves on our
+operated acreage with our planned drilling activity for 2010 and increased
+understanding of how reliable technology will allow the play to be
+developed. On our joint venture acreage in Dimmit County, Texas, we
+believe these wells will produce even higher amounts of condensate and oil
+compared to our operated position. In the Haynesville shale program
+in the ArkLaTex region, a number of successful wells were drilled around our
+acreage position in East Texas in 2009. We began horizontal drilling
+early in 2010 when our 3D seismic analysis was completed. In our
+Marcellus shale program in north central Pennsylvania, we drilled and completed
+our first two horizontal wells during 2009. Initial indications from
+the well tests were encouraging. The gathering line that will connect
+these wells to sales is in the process of being constructed. 
+Shift toward
+oil-weighted projects. As a result of continued downward
+pressure on natural gas prices and an increase in oil prices, we began shifting
+capital investment dollars toward oil-weighted projects during the third 
+54 
+quarter. We
+saw an increase in activity in our Permian and Rocky Mountain regions as a
+result of this shift in capital. 
+Borrowing base on credit facility
+maintained. On September 29, 2009, the borrowing base on our
+credit facility was redetermined and maintained by our bank group at a value of
+$900 million. 
+Impairments. We
+recognized a pre-tax non-cash impairment of proved properties in the amount of
+$174.8 million in 2009. There was an impairment of proved properties
+in the amount of $302.2 million in 2008. A significant decrease in
+the market price for natural gas, including differentials in effect at March 31,
+2009, caused the majority of the non-cash impairment. The largest
+portion of the change in 2009 was $97.3 million related to assets located in the
+Mid-Continent region which were impacted by the lower March 31, 2009, prices
+referred to above as well as wider than normal differentials. The
+ArkLaTex region was impacted by a $20.4 million impairment related to downward
+pricing and engineering revisions. We incurred a $14.0 million
+impairment on proved properties related to the write-down of certain assets
+located in the Gulf of Mexico for which we are relinquishing our ownership
+interests. 
+During
+the year, we abandoned or impaired $45.4 million related to unproved
+properties. The largest specific components of the 2009 impairment
+and abandonment related to the Floyd Shale acreage located in Mississippi and
+acreage in Oklahoma. The remaining write-offs were related to acreage
+we believe we will not be able to hold due to current allocations of capital and
+to acreage that we do not believe will be prospective. 
+Lastly,
+we incurred inventory write-downs of $14.2 million for the year ended
+December 31, 2009 in order to present inventory at the lower of cost
+or market value. The market value of tubular goods and other
+inventory items that were purchased in 2008 when prices for these goods were
+considerably higher declined over the course of 2009 as a result of lower levels
+of activity throughout the industry. 
+Divestitures. We continue to optimize our portfolio of assets as
+part of our overall strategy to focus on concentrated resource
+plays. As part of this strategy, on December 18, 2009, we completed
+the divestiture of our non-strategic coalbed methane project at Hanging Woman
+Basin located in the Rocky Mountain region. Total cash received was
+$23.3 million, which is subject to customary post-closing
+adjustments. During 2009 we recorded an $11.4 million gain on
+divestiture activity, which included the gain from the Hanging Woman Basin
+divestiture, as well as other smaller divestitures. 
+Production
+results . The table below details the regional breakdown of our
+2009 production. 
+ArkLaTex 
+Mid-Continent 
+South
+Texas & Gulf Coast 
+Permian 
+Rocky 
+Mountain 
+Total (1) 
+2009
+Production: 
+Oil
+(MBbl) 
+124 
+274 
+407 
+1,845 
+3,678 
+6,328 
+Gas
+(MMcf) 
+14,167 
+34,380 
+7,255 
+4,075 
+11,229 
+71,106 
+Equivalent
+(MMCFE) 
+14,912 
+36,026 
+9,696 
+15,148 
+33,295 
+109,077 
+Avg.
+Daily Equivalents (MMCFE/per day) 
+40.8 
+98.7 
+26.6 
+41.5 
+91.2 
+298.8 
+Relative
+percentage 
+14% 
+33% 
+9% 
+14% 
+30% 
+100% 
+(1)
+Totals may not add due to rounding 
+In 2009
+our production and oil and gas production revenues have outperformed our initial
+budget for 2009 due to stronger than anticipated production results from our
+Mid-Continent and Permian regions. Please
+refer to Comparison of Financial Results and
+Trends between 2009 and 2008 below for additional
+discussion on production. 
+55 
+Net Profits
+Plan. For the year ended December 31, 2009, the
+change in the value of this liability resulted in a non-cash benefit of $7.1
+million compared with a $34.0 million benefit for the same period in
+2008. Decreases in oil and gas commodity prices have decreased the
+estimated liability for the future amounts to be paid to plan
+participants. This liability is a significant management
+estimate. Adjustments to the liability are subject to estimation and
+may change dramatically from period to period based on assumptions used for
+production rates, reserve quantities, commodity pricing, discount rates, tax
+rates, and production costs. 
+Payments
+made from the Net Profits Plan have been expensed as compensation costs in the
+amounts of $19.9 million, $36.3 million, and $31.9 million for the years ended
+December 31, 2009, 2008, and 2007, respectively. Additionally, we
+accrued cash payments under the Net Profits Plan of $724,000 for the year ended
+December 31, 2009, as a result of sales proceeds during the fourth quarter of
+2009. For the year ended December 31, 2008, we accrued
+for cash payments under the Net Profits Plan of $15.1 million as a result
+of sales proceeds from the Abraxas and Greater Green River Basin
+divestitures. These cash payments are accounted for as a reduction in
+the gain (loss) on divestiture activity in the accompanying consolidated
+statements of operations. There were no significant cash payments
+made or accrued for under the Net Profits Plan as a result of divestitures
+during 2007. 
+The
+recurring cash payments we make are dependent on actual production, realized
+prices, and operating and capital costs associated with the properties in each
+individual pool. Actual cash payments will be inherently different
+from the estimated liability amounts. More detailed discussion is
+included in the analysis in the Comparison of Financial Results and
+Trends sections below and in Note 11 – Fair Value Measurements in Part
+IV, Item 15. An increasing percentage of the costs associated with
+the payments from the Net Profits Plan are now being categorized as general and
+administrative expense as compared to exploration expense. This is a
+function of the normal departure of employees who previously contributed to our
+exploration efforts. In December 2007, our Board approved an
+incentive compensation plan restructuring, whereby the Net Profits Plan was
+replaced with a long-term incentive program utilizing equity
+awards. As a result, the 2007 Net Profits Plan pool was the last pool
+established. 
+The
+calculation of the estimated liability for the Net Profits Plan is highly
+sensitive to our price estimates and discount rate assumptions. For
+example, if we changed the commodity prices in our calculation by five percent,
+the liability recorded on the balance sheet at December 31, 2009, would differ
+by approximately $14 million. A one percentage point decrease in
+the discount rate would result in an increase to the liability of approximately
+$9 million, while a one percentage point increase in the discount rate would
+result in a decrease to the liability of approximately $8 million. We
+frequently re-evaluate the assumptions used in our calculations and consider the
+possible impacts stemming from the current market environment including current
+and future oil and gas prices, discount rates, and overall market
+conditions. In 2009 we made adjustments to the discount rate used for
+Net Profits Plan pools not in payout. Additionally, we changed the
+price assumption used for estimating the liability from a 36-month combination
+of historical and future prices to one using NYMEX strip prices at the end of
+the respective period. 
+Outlook
+for 2010 
+The
+general economic outlook for the country has improved compared to this time a
+year ago. We successfully weathered a tough 2009, and in the process
+advanced a number of potential resource plays and improved our financial
+condition. 
+As we
+enter 2010, we are well positioned both financially and
+operationally. Early in 2009, we extended the maturity of our
+revolving credit facility and subsequently paid down outstanding borrowings on
+that facility during the year. At the end of 2009, we had almost $500
+million available under the revolving credit facility. We have no
+debt maturities until 2012. Additionally, we believe access to the
+capital markets has improved significantly since last year and that we could
+access capital through the public markets if necessary. From an
+operational standpoint, we believe 2010 has the potential to be a promising year
+for us. We will be building upon our successful testing programs from
+2009. We have moved the Eagle Ford shale program much closer to
+development mode, and it will receive the largest portion of our capital budget
+this year. We will also be allocating more capital toward oil and
+rich natural gas projects given their higher returns in the current
+56 
+environment. Specifically,
+we will be drilling more Wolfberry tight oil and Bakken/Three Forks wells in the
+Permian and Rocky Mountain regions, respectively. We recently began
+drilling horizontal wells in the Haynesville shale. We continue to
+monitor service costs as the recent uptick in industry activity threatens to
+push rates for the drilling and completion of wells higher than the levels we
+saw in 2009. 
+57 
+Financial
+Results of Operations and Additional Comparative Data 
+We
+recorded a net loss for the year ended December 31, 2009 of $99.4 million or
+$(1.59) per diluted share compared to 2008 results of net income of $87.3
+million or $1.38 per diluted share. 
+The table
+below provides information regarding selected production and financial
+information for the quarter ended December 31, 2009, and the immediately
+preceding three quarters. Additional details of per MCFE costs are
+contained later in this section. 
+For
+the Three Months Ended 
+December
+31, 
+September
+30, 
+June
+30, 
+March
+31, 
+2009 
+2009 
+2009 
+2009 
+(In
+millions, except production sales data) 
+Production
+(BCFE) 
+26.1 
+26.4 
+28.2 
+28.4 
+Oil
+and gas production revenue, excluding the effects of
+hedging 
+$ 
+187.6 
+$ 
+152.7 
+$ 
+145.3 
+$ 
+130.4 
+Realized
+oil and gas hedge gain 
+$ 
+13.4 
+$ 
+28.3 
+$ 
+43.3 
+$ 
+55.6 
+Gain
+(loss) on divestiture activity 
+$ 
+22.1 
+$ 
+(11.3 
+) 
+$ 
+1.3 
+$ 
+(0.6 
+) 
+Lease
+operating expense 
+$ 
+34.3 
+$ 
+34.3 
+$ 
+35.6 
+$ 
+41.2 
+Transportation
+costs 
+$ 
+5.2 
+$ 
+5.3 
+$ 
+4.6 
+$ 
+5.5 
+Production
+taxes 
+$ 
+13.3 
+$ 
+9.0 
+$ 
+9.3 
+$ 
+9.1 
+DD&A 
+$ 
+75.1 
+$ 
+67.0 
+$ 
+70.4 
+$ 
+91.7 
+Exploration 
+$ 
+13.4 
+$ 
+15.7 
+$ 
+19.5 
+$ 
+13.6 
+Impairment
+of proved properties 
+$ 
+21.6 
+$ 
+0.1 
+$ 
+6.0 
+$ 
+147.0 
+Abandonment
+and impairment of unproved properties 
+$ 
+25.2 
+$ 
+4.8 
+$ 
+11.6 
+$ 
+3.9 
+Impairment
+of materials inventory 
+$ 
+0.8 
+$ 
+2.1 
+$ 
+2.7 
+$ 
+8.6 
+General
+and administrative 
+$ 
+20.7 
+$ 
+20.8 
+$ 
+18.2 
+$ 
+16.4 
+Bad
+debt recovery 
+$ 
+(5.2 
+) 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+Change
+in Net Profits Plan liability 
+$ 
+7.0 
+$ 
+6.8 
+$ 
+2.4 
+$ 
+(23.3 
+) 
+Unrealized
+derivative (gain) loss 
+$ 
+3.2 
+$ 
+4.1 
+$ 
+11.3 
+$ 
+1.8 
+Net
+income (loss) 
+$ 
+1.0 
+$ 
+(4.4 
+) 
+$ 
+(8.3 
+) 
+$ 
+(87.6 
+) 
+Percentage
+change from previous quarter: 
+Production
+(BCFE) 
+(1)% 
+(6)% 
+(1)% 
+(5)% 
+Oil
+and gas production revenue, excluding the effects of
+hedging 
+23% 
+5% 
+11% 
+(32)% 
+Realized
+oil and gas hedge gain 
+(53)% 
+(35)% 
+(22)% 
+24% 
+Gain
+(loss) on divestiture activity 
+(296)% 
+(969)% 
+317% 
+(106)% 
+Lease
+operating expense 
+-% 
+(4)% 
+(14)% 
+(14)% 
+Transportation
+costs 
+(2)% 
+15% 
+(16)% 
+(10)% 
+Production
+taxes 
+48% 
+(3)% 
+2% 
+(23)% 
+DD&A 
+12% 
+(5)% 
+(23)% 
+(4)% 
+Exploration 
+(15)% 
+(19)% 
+43% 
+(23)% 
+Impairment
+of proved properties 
+21,500% 
+(98)% 
+(96)% 
+(50)% 
+Abandonment
+and impairment of unproved properties 
+425% 
+(59)% 
+197% 
+(89)% 
+Impairment
+of materials inventory 
+(62)% 
+(22)% 
+(69)% 
+N/A 
+General
+and administrative 
+-% 
+14% 
+11% 
+32% 
+Bad
+debt recovery 
+N/A 
+N/A 
+N/A 
+N/A 
+Change
+in Net Profits Plan liability 
+3% 
+183% 
+(110)% 
+(71)% 
+Unrealized
+derivative (gain) loss 
+(22)% 
+(64)% 
+528% 
+(115)% 
+Net
+income (loss) 
+(123)% 
+(47)% 
+(91)% 
+(31)% 
+58 
+Changes
+in production volumes, oil and gas production revenues, and costs reflect the
+cyclical and highly volatile nature of our industry. As a result of
+the effects of lower commodity prices, we have seen reduced activity among many
+exploration and production companies over the past year which has led to lower
+lease operating costs over the last two quarters. We believe that
+industry activity may be stabilizing to a point where these costs no longer have
+much room to decline further. Production taxes are largely dependent
+on the prices we receive for oil and natural gas. Depreciation,
+depletion, and amortization generally had been pressured upward in recent years
+as production related to properties acquired or developed in a higher cost
+environment became a larger percentage of our production mix. During
+2009, we have seen our DD&A rate fluctuate as a result of impairments and
+changes to our underlying proved reserve volumes, both of which have been
+affected by the swings in commodity prices we have seen this
+year. Additionally, the accounting treatment for assets that are
+classified as assets held for sale also impacted our DD&A rate since
+properties held for sale are no longer depreciated. A portion of our
+general and administrative expense is tied to the net revenues we generate,
+which are driven in large part by the realized commodity prices we receive for
+our production. The Net Profits Plan and a portion of our current
+short-term incentive compensation are tied to net revenues and therefore are
+subject to variability. 
+A
+year to year overview of selected reserve, production and financial information,
+including trends: 
+Selected
+Operations Data (In thousands, except sales price, volumes, and per MCFE
+amounts): 
+As
+of and for the Years Ended December 31, 
+Percent
+Change Between 
+2009 
+2008 
+2007 
+2009/2008 
+2008/2007 
+Total proved reserves 
+Oil
+(MMBbl) 
+53.8 
+51.4 
+78.8 
+Natural
+gas (Bcf) 
+449.5 
+557.4 
+613.5 
+BCFE 
+772.2 
+865.5 
+1,086.5 
+(11)% 
+(20)% 
+Net production volumes 
+Oil
+(MMBbl) 
+6.3 
+6.6 
+6.9 
+Natural
+gas (Bcf) 
+71.1 
+74.9 
+66.1 
+BCFE 
+109.1 
+114.6 
+107.5 
+(5)% 
+7% 
+Average daily production 
+Oil
+(MBbl) 
+17.3 
+18.1 
+18.9 
+Natural
+gas (MMcf) 
+194.8 
+204.7 
+181.0 
+MMCFE 
+298.8 
+313.1 
+294.5 
+(5)% 
+6% 
+Oil & gas production
+revenues 
+Oil
+production, including hedging 
+$ 
+359,075 
+$ 
+500,062 
+$ 
+432,375 
+Gas
+production, including hedging 
+397,526 
+658,242 
+504,202 
+Total 
+$ 
+756,601 
+$ 
+1,158,304 
+$ 
+936,577 
+(35)% 
+24% 
+Oil & gas production
+costs 
+Lease
+operating expenses 
+$ 
+145,463 
+$ 
+167,384 
+$ 
+140,389 
+Transportation
+costs 
+20,657 
+22,205 
+15,529 
+Production
+taxes 
+40,680 
+81,766 
+62,290 
+Total 
+$ 
+206,800 
+$ 
+271,355 
+$ 
+218,208 
+(24)% 
+24% 
+Average net realized sales price (1) 
+Oil
+(per Bbl) 
+$ 
+56.74 
+$ 
+75.59 
+$ 
+62.60 
+(25)% 
+21% 
+Natural
+gas (per Mcf) 
+$ 
+5.59 
+$ 
+8.79 
+$ 
+7.63 
+(36)% 
+15% 
+Per MCFE data 
+Average
+net realized price (1) 
+$ 
+6.94 
+$ 
+10.11 
+$ 
+8.71 
+(31)% 
+16% 
+Lease
+operating expense 
+(1.33 
+) 
+(1.46 
+) 
+(1.31 
+) 
+(9)% 
+11% 
+Transportation
+costs 
+(0.19 
+) 
+(0.19 
+) 
+(0.14 
+) 
+-% 
+36% 
+Production
+taxes 
+(0.37 
+) 
+(0.71 
+) 
+(0.58 
+) 
+(48)% 
+22% 
+General
+and administrative 
+(0.70 
+) 
+(0.69 
+) 
+(0.56 
+) 
+1% 
+23% 
+Operating
+profit 
+$ 
+4.35 
+$ 
+7.06 
+$ 
+6.12 
+(38)% 
+15% 
+Depletion,
+depreciation and amortization 
+$ 
+2.79 
+$ 
+2.74 
+$ 
+2.12 
+2% 
+29% 
+(1) 
+Includes
+the effects of our hedging
+activities. 
+59 
+We
+present per MCFE information because we use this information to evaluate our
+performance relative to our peers and to identify and measure trends we believe
+require analysis. Volatility in commodity prices has impacted our
+operating margins. The decrease in our equivalent realized price for
+production has corresponded with the significant downward move in commodity
+prices over the last year. While our cost structure has improved over
+the past year, it has not moved to the same degree. Our operating
+profit of $4.35 per MCFE for the year ended December 31, 2009, decreased 38
+percent from the $7.06 per MCFE we realized for the comparable period in
+2008. 
+Average
+daily production for the year ended December 31, 2009, decreased to 298.8 MMCFE
+compared with 313.1 MMCFE for the same period in 2008. For the year ended
+December 31, 2009, our average net realized price decreased by $3.17
+per MCFE to $6.94 per MCFE from the same period in 2008. Lower commodity
+prices were the principal driver of the decrease in 2009. Unit costs
+decreased for the year ended December 31, 2009, as lease operating expense
+decreased $0.13 per MCFE to $1.33 per MCFE and production taxes decreased $0.34
+per MCFE to $0.37 per MCFE. Production taxes are highly correlated to
+commodity prices, and a portion of our general and administrative expense is
+linked to our profitability and cash flow. Transportation costs
+remained steady at $0.19 per MCFE for the years ended December 31, 2009, and
+2008. 
+For the
+year ended December 31, 2009, depletion, depreciation, amortization, and
+asset retirement obligation accretion expense, increased $0.05 per MCFE to $2.79
+per MCFE compared with the same period in 2008. The depletion,
+depreciation, and amortization increase is a result of a decrease in proved
+reserves used to calculate DD&A in the first quarter of 2009, please refer
+to additional DD&A discussion above. Exploration expense for the
+year ended December 31, 2009, was $62.2 million, which was four percent higher
+than the $60.1 million incurred during the comparable period in
+2008. Geological and geophysical expense increased $6.0 million due
+to an increase in the amount spent for seismic analysis. Exploratory
+dry hole expense increased $1.0 million. These increases were offset
+by a $4.9 million decrease in exploration overhead due to a decrease in Net
+Profits Plan payments resulting from decreased oil and gas commodity
+prices. 
+Proved
+reserves decreased 11 percent to 772.2 BCFE at December 31, 2009, from
+865.5 BCFE at December 31, 2008. Please see Note 16 – Disclosures
+about Oil and Gas Producing Activities of Part IV,
+Item 15 of this report and the above discussion under the caption General Overview for
+additional details and discussion on the individual components of the
+change. Over time, our ability to economically replace volumes
+produced annually has proven to be a key factor that determines whether we are
+successful in achieving our goal of increasing net asset value per
+share. The measure of our success will vary year-to-year due to
+changes in these factors. 
+Financial
+information (In thousands, except per share amounts): 
+As
+of and for the Years Ended December 31, 
+Percent
+Change Between 
+2009 
+2008 
+2007 
+2009/2008 
+2008/2007 
+Working
+capital (deficit) 
+$ 
+(87,625 
+) 
+$ 
+15,193 
+$ 
+(92,604 
+) 
+(677)% 
+116% 
+Long-term
+debt 
+$ 
+454,902 
+$ 
+558,713 
+$ 
+536,070 
+(19)% 
+4% 
+Stockholders’
+equity 
+$ 
+973,570 
+$ 
+1,162,509 
+$ 
+902,574 
+(16)% 
+29% 
+Net
+income 
+$ 
+(99,370 
+) 
+$ 
+87,348 
+$ 
+187,098 
+(214)% 
+(53)% 
+Basic
+net income per common share 
+$ 
+(1.59 
+) 
+$ 
+1.40 
+$ 
+3.02 
+(214)% 
+(54)% 
+Diluted
+net income per common share 
+$ 
+(1.59 
+) 
+$ 
+1.38 
+$ 
+2.90 
+(215)% 
+(52)% 
+Basic
+weighted-average shares outstanding 
+62,457 
+62,243 
+61,852 
+-% 
+1% 
+Diluted
+weighted-average shares outstanding 
+62,457 
+63,133 
+64,850 
+(1)% 
+(3)% 
+Net
+cash provided by operating activities 
+$ 
+436,106 
+$ 
+679,190 
+$ 
+632,054 
+(36)% 
+7% 
+Net
+cash used in investing activities 
+$ 
+(304,092 
+) 
+$ 
+(673,754 
+) 
+$ 
+(805,134 
+) 
+(55)% 
+(16)% 
+Net
+cash provided by (used in) financing activities 
+$ 
+(127,496 
+) 
+$ 
+(42,815 
+) 
+$ 
+215,126 
+198% 
+(120)% 
+60 
+We
+present this table as a summary of information relating to key indicators of
+financial condition and operating performance that we believe are
+important. 
+We
+account for our 3.50% Senior Convertible Notes under the treasury stock
+method. There is no impact on the diluted share calculation for the
+periods presented since our average stock price for the relevant reporting
+periods has not exceeded the conversion price. The 3.50% Senior
+Convertible Notes were issued April 4, 2007, and have not been dilutive for a
+reporting period since their issuance. We have in-the-money stock
+options, unvested RSUs, and PSAs that may be potentially dilutive
+securities. Both basic and diluted earnings per share are presented
+in the table above. There were no potentially dilutive shares related
+to in-the-money stock options, unvested RSUs, and PSAs included in the diluted
+earnings per share calculation for the year ended December 31, 2009,
+as we recorded a net loss for the period. A detailed explanation is
+presented under the caption Earnings per Share included
+in Note 1 – Summary of Significant Accounting Policies, in Part IV, Item 15 of
+this report. 
+Basic and
+diluted weighted-average common shares outstanding used in our 2009, 2008, and
+2007 earnings per share calculations reflect our stock repurchases, offset by
+increases in outstanding shares related to stock option exercises, ESPP shares
+issued, and vested RSUs. We issued 189,740 shares of common stock in
+2009, 868,372 shares in 2008, and 733,650 shares in 2007 as a result of stock
+option exercises. These share issuances were offset by the repurchase
+of 2,135,600 shares of common stock in 2008, and 792,216 shares in 2007 through
+our stock repurchase plan. Additionally, the number of RSUs that
+vested in 2009, 2008, and 2007 were 211,092, 291,659, and 268,123,
+respectively. 
+Additional
+Comparative Data in Tabular Format: 
+Change
+Between Years 
+Oil and Gas Production
+Revenues: 
+2009
+and 2008 
+2008
+and 2007 
+Increase
+(decrease) in oil and gas production revenues, net of hedging (in
+thousands) 
+$ 
+(401,703 
+) 
+$ 
+221,727 
+Components
+of Revenue Increases (Decreases): 
+Oil 
+Realized
+price change per Bbl, net of hedging 
+$ 
+(18.85 
+) 
+$ 
+12.99 
+Realized
+price percent change 
+(25)% 
+21% 
+Production
+change (MBbl) 
+(287 
+) 
+(292 
+) 
+Production
+percentage change 
+(4)% 
+(4)% 
+Natural Gas 
+Realized
+price change per Mcf, net of hedging 
+$ 
+(3.20 
+) 
+$ 
+1.16 
+Realized
+price percentage change 
+(36)% 
+15% 
+Production
+change (MMcf) 
+(3,804 
+) 
+8,849 
+Production
+percentage change 
+(5)% 
+13% 
+Our
+product mix as a percentage of total oil and gas revenue and
+production: 
+Years
+Ended December 31, 
+Revenue 
+2009 
+2008 
+2007 
+Oil 
+47% 
+43% 
+46% 
+Natural
+Gas 
+53% 
+57% 
+54% 
+Production 
+Oil 
+35% 
+35% 
+39% 
+Natural
+Gas 
+65% 
+65% 
+61% 
+61 
+Information
+regarding the effects of oil and gas hedging activity: 
+Years
+Ended December 31, 
+2009 
+2008 
+2007 
+Oil Hedging 
+Percentage
+of oil production hedged 
+52% 
+61% 
+66% 
+Oil
+volumes hedged (MBbl) 
+3,306 
+4,022 
+4,565 
+Increase
+(Decrease) in oil revenue 
+$ 
+$14.8 million 
+$ 
+(115.1
+million 
+) 
+$ 
+(34.3
+million 
+) 
+Average
+realized oil price per Bbl before hedging 
+$ 
+54.40 
+$ 
+92.99 
+$ 
+67.56 
+Average
+realized oil price per Bbl after hedging 
+$ 
+56.74 
+$ 
+75.59 
+$ 
+62.60 
+Natural Gas Hedging 
+Percentage
+of gas production hedged 
+45% 
+46% 
+46% 
+Natural
+gas volumes hedged (MMBtu) 
+$ 
+34.3
+million 
+$ 
+36.4
+million 
+$ 
+32.5
+million 
+Increase
+in gas revenue 
+$ 
+125.9
+million 
+$ 
+14.0
+million 
+$ 
+58.7
+million 
+Average
+realized gas price per Mcf before hedging 
+$ 
+3.82 
+$ 
+8.60 
+$ 
+6.74 
+Average
+realized price per Mcf after hedging 
+$ 
+5.59 
+$ 
+8.79 
+$ 
+7.63 
+Information
+regarding the components of exploration expense: 
+Years
+Ended December 31, 
+Summary of Exploration Expense (in
+millions) 
+2009 
+2008 
+2007 
+Geological
+and geophysical expenses 
+$ 
+20.2 
+$ 
+14.2 
+$ 
+17.0 
+Exploratory
+dry holes 
+7.8 
+6.8 
+14.4 
+Overhead
+and other expenses 
+34.2 
+39.1 
+27.3 
+Total 
+$ 
+62.2 
+$ 
+60.1 
+$ 
+58.7 
+Comparison
+of Financial Results and Trends between 2009 and 2008 
+Oil and gas production
+revenue. Production decreased five percent to 109.1 BCFE for
+the year ended December 31, 2009, compared with 114.6 BCFE for the year ended
+December 31, 2008. Production for the year ended December 31, 2009,
+includes approximately 5.1 BCFE related to non-core properties divested
+throughout 2009. Adjusting for divestitures of non-core
+properties that were sold in the last two years, production on retained
+properties declined slightly from 104.5 BCFE in 2008 to 104.0 BCFE in
+2009. The following table presents the regional changes in our
+production and oil and gas revenues and costs between the two
+years: 
+Average
+Net Daily Production Added/(Lost) 
+Pre-Hedge 
+Oil
+and Gas Revenue Added (Lost) 
+Production
+Costs Increase (Decrease) 
+(MMCFE) 
+(In
+millions) 
+(In
+millions) 
+ArkLaTex 
+(9.9 
+) 
+$ 
+(115.0 
+) 
+$ 
+(1.1 
+) 
+Mid-Continent 
+8.5 
+(142.1 
+) 
+(16.4 
+) 
+South
+Texas & Gulf Coast 
+(12.4 
+) 
+(97.0 
+) 
+(13.8 
+) 
+Permian 
+3.7 
+(79.1 
+) 
+(1.7 
+) 
+Rocky
+Mountain 
+(4.2 
+) 
+(210.2 
+) 
+(31.6 
+) 
+Total 
+(14.3 
+) 
+$ 
+(643.4 
+) 
+$ 
+(64.6 
+) 
+Daily
+production decreased by approximately 14.3 MMCFE during 2009 compared to
+2008. Production decreased between these two periods as a result of
+decreased levels of capital investment throughout
+2009 and the lack of contribution in 2009 from properties that were sold in the
+second half of 2008. The largest regional 
+62 
+increase
+between 2009 and 2008 occurred in the Mid-Continent region as a result of
+success in the horizontal Woodford shale program in the Arkoma Basin and strong
+results from our Deep Springer program in the Anadarko
+Basin. Production growth in the Permian region is the result of
+continued development of Wolfberry assets at Sweetie Peck and Halff
+East. The decrease in the South Texas & Gulf Coast region’s
+production is primarily a result of the loss of production from the Judge Digby
+Field due to an exchange of assets that occurred in late 2008. The
+ArkLaTex decrease is due to natural decline and decreased levels of capital
+investment in the region by us and our partners, particularly at the Elm Grove
+Field. The Rocky Mountain region realized a slight decline as a
+result of its more mature production decline profile and modest capital
+investment. 
+Realized oil and gas hedge gain
+(loss). We recorded a net realized hedge gain of $140.6
+million for the year ended December 31, 2009, mainly related to favorable
+settlements on gas hedges. For the year ended December 31, 2008, we
+recorded a net realized hedge loss of $101.1 million mainly due to unfavorable
+settlements on oil hedges. Please refer to our discussion above under
+the heading Oil and Gas
+Prices . 
+Marketed gas system revenue and
+expense. Marketed gas system revenue decreased $18.9 million
+to $58.5 million for the year ended December 31, 2009, compared with $77.4
+million for the comparable period of 2008. Concurrent with the
+decrease in marketed gas system revenue, marketed gas system expense decreased
+$14.6 million to $57.6 million for the year ended December 31, 2009,
+compared with $72.2 million for the comparable period of
+2008. We expect that marketed gas system revenue and expense will
+continue to trend with increases and decreases in production and our price
+realizations before the impact of hedging. 
+Gain (loss) on divestiture
+activity. We recorded a gain on divestiture
+activity of $11.4 million for the year ended
+December 31, 2009, compared with $63.6 million for the comparable
+period of 2008. The 2009 gain is mainly related to the Hanging Woman
+Basin divestiture that closed in December of 2009, which is subject to normal
+post-closing adjustments and is expected to be finalized during the first
+quarter of 2010. The 2008 gain is mainly related to the Abraxas
+divestiture that closed in January 2008. We expect to continue to
+evaluate potential divestitures of non-strategic properties. 
+Oil and gas production
+expense. Total production costs decreased $64.6 million or 24
+percent to $206.8 million for the year ended December 31, 2009, compared
+with $271.4 million in 2008. Total oil and gas production costs per
+MCFE decreased $0.47 to $1.89 for the year ended December 31, 2009, compared
+with $2.36 in 2008. This decrease is comprised of the
+following: 
+· 
+A
+$0.34 decrease in production taxes on a per MCFE basis due to the decrease
+in realized prices between periods. We expect production taxes
+to trend with commodity prices. 
+· 
+A
+$0.11 decrease in recurring lease operating expense on a per MCFE basis is
+related to reductions in recurring LOE that stems from the slowdown in
+activity in the exploration and production industry, as well as the
+broader economy. 
+· 
+A
+$0.02 decrease in overall workover LOE on a per MCFE basis is related to a
+reduction in the amount of workovers that were performed given the
+slowdown in activity in the exploration and production
+industry. 
+· 
+Transportation
+costs on a per MCFE basis remained flat year over
+year. 
+Depletion, depreciation,
+amortization, and asset retirement obligation liability
+accretion. DD&A decreased $10.1 million, or three percent,
+to $304.2 million in 2009 compared with $314.3 million in
+2008. DD&A expense per MCFE increased two percent to $2.79
+in 2009 compared to $2.74 in 2008. The decrease in absolute DD&A
+reflects lower total production volumes in 2009 compared to 2008. Our
+DD&A
+expense per MCFE decreased due to the significant decrease in our carrying value
+of our properties as a result of proved property impairments that we incurred in
+the fourth quarter of 2008 and the first quarter of 2009. Proved
+property impairments and changes in underlying proved reserve volumes will
+continue to be affected by the swings in commodity prices. 
+63 
+Exploration. Exploration
+expense increased $2.1 million or four percent to $62.2 million in 2009 compared
+with $60.1 million for 2008. The increase is due to a $1.0 million
+increase in exploratory dry hole expense and a $6.0 million increase in
+geological and geophysical expense due to an increase in the amount spent on
+seismic. We anticipate that we will continue to acquire seismic data
+into 2010 in order to minimize risk with respect to the acreage in our emerging
+resource plays with the expectation that we can optimize their future
+development. These increases were offset by a $4.9 million decrease
+in exploration overhead expense due to a decrease in Net Profits Plan payments
+as a result of decreased oil and gas commodity prices. We expect
+payments made under the Net Profits Plan to trend with commodity
+prices. 
+Impairment of proved
+properties. We recorded a $174.8 million impairment of proved
+oil and gas properties in 2009 compared to $302.2 million in 2008. A
+significant decrease in commodity prices, including differentials, during the
+first quarter of 2009 caused the majority of the non-cash
+impairment. The largest portion of the impairment in 2009 was $97.3
+million related to assets located in the Mid-Continent region which were
+impacted at the end of the first quarter by low natural gas prices and wider
+than normal differentials. The ArkLaTex region was impacted by a
+$20.4 million impairment related to negative pricing and engineering
+revisions. We incurred a $14.0 million impairment on proved
+properties related to the write-down of certain assets located in the Gulf of
+Mexico in which we are relinquishing our ownership interests. We
+generally expect proved property impairments will be more likely to occur in
+periods of low commodity prices. 
+Abandonment and impairment of
+unproved properties. During 2009, we abandoned or impaired
+$45.4 million of unproved properties compared with $39.0 million for
+2008. The largest specific components of the 2009 impairment and
+abandonment related to the Floyd Shale acreage located in Mississippi and
+acreage in Oklahoma. Additionally, we incurred write-offs related to
+acreage we believe we will not keep based on our current capital allocation
+plans or related to acreage that we do not believe will be prospective. We
+generally expect impairments of unproved properties to be more likely to occur
+in periods of low commodity prices since fewer dollars will be available for
+exploratory and development efforts. 
+Impairment of
+Goodwill. We recorded a $9.5 million impairment of goodwill in
+2008. The goodwill was the result of our purchase of Agate Petroleum,
+Inc. in January 2005. The impairment was a result of downward price
+adjustments to reserves for properties located in our Mid-Continent and Rocky
+Mountain regions and represented our entire goodwill balance. We had
+no goodwill impairment in 2009. 
+Impairment of materials
+inventory. We recorded a $14.2 million impairment of materials
+inventory for the year ended December 31, 2009. There were
+no impairments recorded in 2008. The inventory impairment was
+caused by a decrease in the value of tubular goods and other raw materials.
+Impairments of materials inventory are impacted by fluctuations in the materials
+cost environment and increases and decreases in development and exploration
+activity, which generally trend with commodity prices. 
+General and
+administrative. General and administrative expense decreased
+$3.5 million or four percent to $76.0 million for the year ended
+December 31, 2009, compared with $79.5 million for the same period in
+2008. G&A increased $0.01 to $0.70 per MCFE for the year ended
+December 31, 2009, compared to $0.69 per MCFE for the same period in
+2008. 
+General
+and administrative expense decreased due to an $11.3 million decrease in cash
+payments made under the Net Profits Plan. As a result of the lower
+price realization we received in 2009 compared to 2008,
+the payouts from this plan were meaningfully smaller than those paid out in the
+prior year. We expect payments made under the Net Profits Plan to
+trend with commodity prices. 
+Compensation
+related costs allocated to general and administrative expense increased in
+2009. The largest increases were for headcount related costs, such as
+salary, benefits, and payroll taxes, which increased $10.6 million for the year
+ended December 31, 2009, when compared with the same period in
+2008. A significant driver of this headcount increase had been the
+conversion from contract lease operators to internal lease operators which began
+to take place in 2008. Stock compensation was also up $ 3.3 million
+year over year as a result of layering in the second year of stock compensation
+amortization from our PSA long-term incentive program. 
+64 
+COPAS
+overhead reimbursements were $6.4 million higher for the year ended
+December 31, 2009, compared with the same period in 2008. 
+Bad debt expense
+(recovery). We recorded a recovery of bad debt expense of $5.2
+million in 2009. We recorded $16.7 million of bad debt expense
+in 2008 of which $16.6 million was a result of SemGroup L.P. and certain of its
+North American subsidiaries filing for bankruptcy protection. Certain
+SemGroup entities had purchased a portion of our crude oil
+production. This amount related to oil produced in June and July of
+2008 that was fully reserved in the year ended
+December 31, 2008. 
+Change in Net Profits Plan
+liability. For the year ended December 31, 2009, this non-cash
+item was a $7.1 million benefit compared to $34.0 million benefit for the same
+period in 2008. Significant decreases in oil and gas commodity prices
+have decreased the estimated liability for the future amounts to be paid to plan
+participants. This liability is a significant management
+estimate. Adjustments to the liability are subject to estimation and
+may change dramatically from period to period based on assumptions used for
+production rates, reserve quantities, commodity pricing, discount rates, tax
+rates, and production costs. We expect the change in this liability
+to trend with commodity prices. 
+Unrealized derivative (gain)
+loss. We recognized a loss of $20.5 million for the year ended
+December 31, 2009, compared to a gain of $11.2 million for the same
+period in 2008. This non-cash item is driven by the change in the
+value of our hedge position, as well as the portion of that position that is
+considered ineffective for accounting purposes. Please refer to our
+discussion under the heading Oil and Gas
+Prices. 
+Other
+expense. Other expense increased $3.1 million to $13.5 million
+for the year ended December 31, 2009, compared with $10.4 million for the same
+period in 2008. During the year ended December 31, 2009, we incurred
+$1.5 million of expense related to the assignment of a drilling rig contract in
+our Rocky Mountain region. We also incurred a loss related to
+hurricanes of $8.3 million for the year ended December 31, 2009, compared with a
+loss related to hurricanes of $7.0 million for the same period in
+2008. 
+Income tax benefit
+(expense). Income tax benefit totaled $60.1 million for 2009
+compared to tax expense of $57.4 million for 2008, resulting in effective tax
+rates of 37.7 percent and 39.7 percent, respectively. The effects of
+individual components of our tax rate can vary between periods resulting in
+fluctuations. The effective rate change from 2008 primarily reflects
+the impact of goodwill impairment in that year, but changes in the mix of the
+highest marginal state tax rates and differing effects of other permanent
+differences, including the impact between years of the domestic production
+activities deduction and percentage depletion, also had an
+effect. Our current income tax benefit in 2009 is $20.4 million
+compared to current income tax expense of $19.2 million in
+2008. These amounts are 34 percent and 33 percent, respectively,
+of the total income tax benefit or expense for each period. Our 2009 current
+income tax benefit reflects creation of a net operating loss which we can carry
+back to one or more prior tax years to obtain a refund. In future
+years, creation of net operating losses may not create current tax
+benefits. During 2009 we observed with interest U.S. Congressional
+legislative activity relating to possible changes in taxation of our
+industry. If the proposed legislation, which would reduce or
+eliminate current tax deductions for intangible drilling costs, the domestic
+production activities deduction, and percentage depletion allowance passes, we
+would expect our effective tax rate and the cash tax portion of our income tax
+expense to increase in the year the legislation becomes effective. 
+65 
+Comparison
+of Financial Results and Trends between 2008 and 2007 
+Oil and gas production
+revenue. Production increased seven percent to 114.6 BCFE for
+the year ended December 31, 2008, compared with 107.5 BCFE for the year ended
+December 31, 2007. Production for the year ended December 31, 2007,
+includes approximately 6.8 BCFE related to non-core properties divested
+throughout 2008. The following table presents the regional changes in
+our production and oil and gas revenues and costs between the two
+years: 
+Average
+Net Daily Production Added/(Lost) 
+Pre-Hedge 
+Oil
+and Gas Revenue Added 
+Production
+Costs Increase 
+(MMCFE) 
+(In
+millions) 
+(In
+millions) 
+ArkLaTex 
+12.8 
+$ 
+76.1 
+$ 
+8.3 
+Mid-Continent 
+(2.8 
+) 
+30.4 
+3.9 
+South
+Texas & Gulf Coast 
+10.8 
+75.4 
+17.5 
+Permian 
+8.5 
+85.6 
+11.5 
+Rocky
+Mountain 
+(10.7 
+) 
+79.8 
+11.9 
+Total 
+18.6 
+$ 
+347.3 
+$ 
+53.1 
+We grew
+daily production by approximately 18.6 MMCFE during 2008 compared to
+2007. The largest regional increase occurred in the ArkLaTex region
+as a result of the success in the Cotton Valley and James Lime
+programs. Production in the South Texas & Gulf Coast region
+increased as a result of two acquisitions of properties targeting the shallow
+Olmos gas formation that were made in the second half of 2007 as well as several
+successful offshore wells. The production growth in the Permian
+region was the result of continued development of the Wolfberry assets at
+Sweetie Peck and Halff East. The declines in production in the
+Mid-Continent and Rocky Mountain regions were the result of the divestiture of
+non-core properties in these regions, which resulted in a smaller production
+base for 2008. 
+Realized oil and gas hedge gain
+(loss). We recorded a realized hedge loss of $101.1 million
+for the year ended December 31, 2008, mainly related to settlements on oil
+hedges. For the year ended December 31, 2007, we recorded a realized
+hedge gain of $24.5 million mainly due to favorable settlements on natural gas
+hedges. 
+Marketed gas system revenue and
+expense. Marketed gas system revenue increased $32.2 million
+to $77.4 million for the year ended December 31, 2008, compared with $45.1
+million for the comparable period of 2007. Concurrent with the
+increase in marketed gas system revenue, marketed gas system expense increased
+$29.7 million to $72.2 million for the year ended December 31, 2008,
+compared with $42.5 million for the comparable period of
+2007. The net margin has stayed consistent with historical
+performance. 
+Other
+revenue. Other revenues decreased $6.6 million to $2.1 million
+for the year ended December 31, 2008, compared with $8.7 million for
+2007. The decrease was due primarily to a $5.2 million gain
+recognized in 2007 associated with a global insurance settlement attributed to
+Hurricane Rita. 
+Gain (loss) on divestiture
+activity. We recorded a gain on sale of proved properties of
+$63.6 million for the year ended December 31, 2008, mainly
+related to the Abraxas divestiture in January 2008. 
+66 
+Oil and gas production
+expense. Total production costs increased $53.1 million or 24
+percent to $271.4 million for 2008, from $218.2 million in
+2007. Total oil and gas production costs per MCFE increased $0.33 to
+$2.36 for 2008, compared with $2.03 for 2007. This increase was
+comprised of the following: 
+· 
+A
+$0.05 increase in overall transportation cost on a per MCFE basis was
+driven by the addition of Olmos shallow gas assets in the Maverick Basin
+that were acquired in the fourth quarter of 2007, as well as wells
+completed in 2008 that had higher transportation
+costs 
+· 
+A
+$0.13 increase in production taxes on a per MCFE basis due to the increase
+in realized prices between periods, particularly in the oil-weighted Rocky
+Mountain and Permian regions 
+· 
+A
+$0.10 increase in recurring lease operating expense on a per MCFE basis
+was related to higher costs, particularly in oil-weighted regions, for
+items such as fuel and fluid disposal and an increase in the South Texas
+& Gulf Coast region due to wells acquired and developed in South Texas
+during the fourth quarter of 2007 
+· 
+A
+$0.05 overall increase in workover lease operating expense on a per MCFE
+basis relating to workover charges in the Mid-Continent and South Texas
+& Gulf Coast regions. 
+Depletion, depreciation,
+amortization and asset retirement obligation liability
+accretion. DD&A increased $86.7 million, or 38 percent, to
+$314.3 million in 2008 compared with $227.6 million in
+2007. DD&A expense per MCFE increased 29 percent to $2.74 in 2008
+compared to $2.12 in 2007. This increase was due to a higher per unit
+rate associated with our acquisition and drilling costs in 2008 and 2007 caused
+by overall upward cost pressure in the industry in recent years. Additionally,
+this increase reflected the costs of production facilities in the offshore Gulf
+Coast that had increased significantly in recent years and that started
+impacting our DD&A rate as those projects begin production. The
+DD&A per MCFE rate was further affected by downward revisions of 244.2 BCFE
+of proved reserves due to pricing and performance between December 31, 2008, and
+December 31, 2007, causing a general increase in
+DD&A. 
+Exploration. Exploration
+expense increased $1.4 million or two percent to $60.1 million in 2008 compared
+with $58.7 million for 2007. The increase was due to a $2.8 million
+increase in drilling arrangements and a $9.0 million increase in exploration
+overhead. These increases were offset by a $2.8 million decrease in
+geological and geophysical expense as well as a $7.6 million decrease related to
+exploratory dry hole expense due to fewer and less expensive dry
+holes. 
+Impairment of proved
+properties. We recorded a $302.2 million impairment of proved
+oil and gas properties in 2008 compared to no impairment in
+2007. This impairment was primarily due to downward price adjustments
+to reserves and declining performance for properties primarily located in the
+South Texas & Gulf Coast region, as well as for gas properties in the Rocky
+Mountain region. 
+Abandonment and impairment of
+unproved properties. During the year, we abandoned or impaired
+$39.0 million of unproved properties. Approximately $13.4
+million related to acreage to which we had assigned value in 2007 acquisitions
+targeting the Olmos shallow gas formation. The remaining write-offs
+related to acreage that we believed we either would not be able to hold in the
+current period of limited capital availability or to acreage that we did not
+believe would be prospective. 
+Impairment of
+Goodwill. We recorded a $9.5 million impairment of goodwill in
+2008. The goodwill was the result of our purchase of Agate Petroleum,
+Inc. in January 2005. The impairment was a result of downward price
+adjustments to reserves for properties located in our Mid-Continent and Rocky
+Mountain regions and represented our entire goodwill balance. 
+General and
+administrative. General and administrative expenses increased
+$19.4 million or 32 percent to $79.5 million for 2008, compared with $60.1
+million for 2007. G&A increased $0.13 to $0.69 per MCFE for 2008
+compared to $0.56 per MCFE for the same period in 2007 as G&A grew at a
+faster rate than the seven percent increase in production. A
+significant increase in employee count resulted in an increase in base employee
+67 
+compensation,
+including taxes and benefits, of approximately $23.9 million between 2008 and
+2007. A significant driver of this headcount increase had been the
+conversion from contract lease operators to internal lease
+operators. 
+An
+increase in 2008 oil and gas commodity prices triggered additional Net Profits
+Plan payments. Additionally, an increased percentage of the
+distribution dollars under the Net Profits Plan associated with general and
+administrative expense contributed to a $4.4 million increase in the current
+period realized expense in 2008 compared with the same period in
+2007. 
+Cash
+bonus and long-term incentive compensation expense increased by $8.4 million for
+the year ended December 31, 2008, compared with the same period in
+2007. The increase resulted from the application of the Cash Bonus
+Plan as amended on March 28, 2008 and an increase in our employee
+count. 
+The
+amounts described above were offset by a $9.1 million increase in the amount of
+G&A that was allocated to exploration expense and an $8.2 million increase
+in COPAS overhead reimbursements. Our COPAS overhead reimbursements
+from operations increased due to an increase in our operated well count from our
+drilling program. 
+Change in Net Profits Plan
+liability. For the year ended December 31, 2008, this non-cash
+item was a benefit of $34.0 million compared to an expense of $50.8 million for
+the same period in 2007. Significant decreases in oil and gas
+commodity prices during the last half of 2008 and payments out of the plan have
+decreased the estimated liability for the future amounts to be paid to plan
+participants. 
+Bad debt
+expense. We recorded $16.7 million of bad debt expense in
+2008, of which $16.6 million was a result of SemGroup, L.P. and certain of its
+North American subsidiaries filing for bankruptcy protection. Certain
+SemGroup entities had purchased a portion of our crude oil
+production. This amount related to oil produced in June and July of
+2008 that was fully reserved in the year ended
+December 31, 2008. 
+Income tax benefit (expense).
+Income tax expense totaled $57.4 million for 2008 and $109.0 million for
+2007, resulting in effective tax rates of 39.7 percent and 36.8 percent,
+respectively. The effective rate change from 2007 was primarily due
+to the impact of goodwill impairment, changes in the mix of the highest marginal
+state tax rates, and also reflects other permanent differences including
+differing estimated effects between years of the domestic production activities
+deduction. 
+Our
+current income tax expense in 2008 was $19.2 million compared to $17.6 million
+in 2007. These amounts were 33 percent and 16 percent of the total
+income tax expense for the respective periods. 
+Overview
+of Liquidity and Capital Resources 
+In order
+to meet our projected growth targets, we will have to effectively invest capital
+into new projects and acquisitions. The following analysis and
+discussion includes our assessment of market risk and possible effects of
+inflation and changing prices. 
+Sources
+of cash 
+Based on
+our current outlook, we expect our generated cash flow from operations in 2010
+plus proceeds from our pending Rocky Mountain oil and other non-core asset
+divestiture packages to fund our exploration and development budget for
+2010. Accordingly, we do not expect to access the capital markets in
+2010. Throughout 2009, we identified and marketed non-core oil and
+gas properties. Net cash proceeds from transactions that closed in
+2009, after commission costs, were $39.9
+million. Subsequent to year end, we closed the Wyoming
+68 
+portion
+of our Rocky Mountain oil package and we plan to close the remaining North
+Dakota portion by the end of the first quarter of 2010. We anticipate
+we will continue to evaluate our property base to identify and divest of
+properties we consider non-core to our strategic goals. 
+Our
+primary sources of liquidity are the cash flows provided by operating
+activities, use of our credit facility, sales of non-core properties, and access
+to capital markets. All of these sources can be impacted by the
+general condition of the broad economy and by significant fluctuations in oil
+and gas prices, operating costs, and volumes produced all of which affect us and
+our industry. We have no control over the market prices for oil and
+natural gas, although we are able to influence the amount of our net realized
+revenues related to our oil and gas sales through the use of derivative
+contracts. The borrowing base on our credit facility could be reduced
+as a result of lower commodity prices or sales of non-core producing
+properties. Historically, decreases in market prices have limited our
+industry’s access to the capital markets. We believe the public debt
+markets are currently accessible. Equity and convertible debt
+issuances are also available to us as alternative financing
+sources. We do not anticipate the need to raise public debt or equity
+financing in the near term, however these are options we would consider under
+the appropriate circumstances. We intend to rely on our credit
+facility for borrowings. 
+Current
+credit facility 
+On
+April 14, 2009, we entered into an amended $1.0 billion senior secured
+revolving credit facility with twelve participating banks. The
+initial borrowing base was set at $900 million. On
+September 29, 2009, the lending group redetermined our reserve-backed
+borrowing base under the credit facility at $900 million. We have
+been provided a $678 million commitment amount by the bank group. The
+new amended credit facility agreement has a maturity date of
+July 31, 2012. Management believes that the current
+commitment is sufficient for our liquidity needs. To date, we have
+experienced no issues drawing upon our credit facility. No individual
+bank participating in the credit facility represents more than 16 percent of the
+lending commitments under the credit facility. We monitor the credit
+environment closely and have frequent discussions with the lending
+group. 
+As of
+February 16, 2010, we had $467.0 million of available borrowing capacity
+under this facility. Interest and commitment fees are accrued based
+on the borrowing base utilization percentage. Euro-dollar loans
+accrue interest at LIBOR plus the applicable margin from the utilization table
+located in Note 5 of Part IV, Item 15 of this report, and Alternate Base Rate
+loans accrue interest at Prime plus the applicable margin from the utilization
+table. Outstanding loans reduce the amount available under the
+commitment amount on a dollar-for-dollar basis, as do letters of
+credit. Borrowings under the facility are secured by mortgages on the
+majority of our oil and gas properties and a pledge of the common stock of our
+material subsidiary companies. 
+Our
+weighted-average interest rate paid in 2009 was 5.4 percent and included fees
+paid on the unused portion of the credit facility’s aggregate commitment amount
+and amortization of deferred financing costs and the debt
+discount. We decreased our net borrowings from the previous year by
+$112.0 million when comparing the ending 2009 and 2008 balance sheet
+amounts. A decrease in the average outstanding credit facility
+balance throughout 2009, plus a decrease in interest rates, was offset by higher
+applicable margins, higher commitment fees on the unused portion of our credit
+facility and amortization of upfront financing costs and the 3.50% Senior
+Convertible Notes debt discount. This resulted in interest expense of
+$28.9 million in 2009 compared with $27.0 million in 2008. 
+We are
+subject to customary covenants under our credit facility, including limitations
+on dividend payments and requirements to maintain certain financial ratios,
+which include debt to earnings before interest, taxes, depreciation, and
+amortization of
+less than 3.5 to 1.0 and a current ratio as defined by our credit agreement
+of not less than 1.0. As of December 31, 2009, our debt to
+EBITDA ratio and current ratio as defined by our credit agreement, were 1.10 and
+2.75, respectively. We are in compliance with all covenants under
+this credit facility and expect to be in compliance for at least 12
+months. 
+We may
+from time to time repurchase certain amounts of our outstanding debt securities
+for cash and/or through exchanges for other securities. Such
+repurchases or exchanges may be made in open market transactions, privately
+negotiated transactions, or otherwise. Any such repurchases or
+exchanges will depend on prevailing 
+69 
+market
+conditions, our liquidity requirements, contractual restrictions, compliance
+with securities laws and other factors. The amounts involved in any
+such transaction may be material. 
+Uses
+of cash 
+We use
+cash for the acquisition, exploration, and development of oil and gas
+properties, and for the payment of debt obligations, trade payables, income
+taxes, common stock repurchases, and stockholder dividends. During
+2009 we spent $379.3 million of cash on capital development and $76,000 of cash
+for property acquisitions. These amounts differ from the cost
+incurred amounts based on the timing of cash payments associated with these
+activities as compared to the accrual-based activity upon which the costs
+incurred amounts are presented. These cash flows were funded using
+cash inflows from operations, proceeds from the sale of assets, and available
+borrowing capacity under our revolving credit facility. 
+Expenditures
+for exploration and development of oil and gas properties and acquisitions are
+the primary use of our capital resources. Our capital and exploration
+expenditures in 2010 will be funded with current year operating cash flows and
+proceeds from the divestiture of non-core assets. The amount and
+allocation of future capital expenditures will depend upon a number of factors
+including the number and size of available economic acquisitions and drilling
+opportunities, our cash flows from operating, investing and financing
+activities, and our ability to assimilate acquisitions. Also the
+impact of oil and gas prices on investment opportunities, the availability of
+capital and borrowing facilities, and the success of our development and
+exploratory activities could lead to changes in funding requirements for future
+development. We regularly review our capital expenditure budget to
+assess changes in current and projected cash flows, acquisition opportunities,
+debt requirements, and other factors. 
+As of the
+filing date of this report we have Board authorization to repurchase up to
+3,072,184 shares of our common stock under our stock repurchase
+program. Shares may be repurchased from time to time in open market
+transactions or privately negotiated transactions subject to market conditions
+and other factors including certain provisions of our existing bank credit
+facility agreement, compliance with securities laws, and the terms and
+provisions of our stock repurchase program. There were no share
+repurchases in 2009. 
+Current
+proposals to fund the federal budget include eliminating or reducing current tax
+deductions for intangible drilling costs, the domestic production activities
+deduction, and percentage depletion. Legislation modifying or
+eliminating these deductions would have the immediate effect of reducing
+operating cash flows thereby reducing funding available for our exploration and
+development capital programs and those of our peers in the
+industry. These funding reductions could have a significant adverse
+effect on drilling in the United States for a number of years. 
+In 2009
+we paid $6.2 million in dividends to our stockholders. Our intention
+is to continue to make these dividend payments for the foreseeable future
+subject to our future earnings, our financial condition, possible credit
+facility covenants, and other currently unexpected factors which could
+arise. 
+The
+following table presents amounts and percentage changes between years in net
+cash flows from our operating, investing, and financing
+activities. The analysis following the table should be read in
+conjunction with our consolidated statements of cash flows in Part IV, Item 15
+of this report. 
+Amount
+of Changes Between 
+Percent
+of Change Between 
+2009/2008 
+2008/2007 
+2009/2008 
+2008/2007 
+Net
+Cash Provided By (Used in ) Operating Activities 
+$ 
+(243,084 
+) 
+$ 
+47,136 
+(36)% 
+7% 
+Net
+Cash Provided By Investing Activities 
+$ 
+369,662 
+$ 
+131,380 
+(55)% 
+(16)% 
+Net
+Cash Used In Financing Activities 
+$ 
+(84,681 
+) 
+$ 
+(257,941 
+) 
+198% 
+(120)% 
+70 
+Analysis
+of cash flow changes between 2009 and 2008 
+Operating
+activities. Cash received from oil and gas production
+revenues, net of the realized effects of hedging, decreased $438.5 million to
+$751.8 million for the year ended December 31, 2009. The decrease was
+the result of a five percent decrease in production and a 31 percent decrease in
+our net realized price after hedging, resulting in a 35 percent decrease in
+production revenue. Included in the 2009 oil and gas production
+revenue amounts is $140.6 million of net realized hedging gains. We
+received $9.9 million in income tax refunds in 2009 compared to payments of
+$17.3 million during 2008. 
+Investing
+activities. Cash used for investing activities decreased
+$369.7 million for the year ended December 31, 2009, compared with the
+same period in 2008. Cash outflows for 2009 capital expenditures for
+development and exploration activities decreased $367.3 million or 49 percent to
+$379.3 million, which reflects a reduced level of activity as a result of
+lower commodity prices. Total cash outflow for 2009 related to the
+acquisition of oil and gas properties decreased $81.7 million or
+100 percent to $76,000. We had no significant acquisitions of
+oil and gas properties in 2009, compared with the acquisition of Carthage
+Field properties during 2008. Proceeds from an insurance settlement
+relating to Hurricane Ike were $16.8 million for the year ended
+December 31, 2009, compared with the same period in 2008 when we
+received no proceeds from insurance settlements. Proceeds from the
+sale of oil and gas properties for the year ended December 31, 2009,
+decreased $139.0 million compared to the same period in 2008. Current
+year proceeds received from the sale of oil and gas properties relate to
+non-core properties located in the Rocky Mountain region that were divested of
+in the fourth quarter of 2009. The majority of the 2008 proceeds
+related to non-core properties sold to Abraxas in the first quarter of
+2008. 
+Financing
+activities. Net repayments to our credit facility increased
+$127.0 million for the year ended December 31, 2009, compared to
+2008. We spent $11.1 million on debt issuance costs for our amended
+credit facility during the year ended December 31, 2009. We did
+not incur any debt issuance costs during 2008. Our income tax benefit
+attributable to the exercise of stock awards decreased $13.9 million in the year
+ended December 31, 2009, compared with 2008. We received
+$8.8 million less in proceeds from the sale of common stock in 2009, than
+in 2008. Additionally, we invested $77.2 million less to repurchase
+shares of our common stock during 2009, than in 2008. 
+We had
+$10.6 million in cash and cash equivalents and a working capital deficit of
+$87.6 million as of December 31, 2009, compared to $6.1 million in cash and
+cash equivalents and working capital of $15.2 million as of December 31,
+2008. 
+Analysis
+of cash flow changes between 2008 and 2007 
+Operating
+activities. Cash received from oil and gas production
+revenues, net of the realized effects of hedging, increased $265.2 million to
+$1.2 billion for the year ended December 31, 2008. The increase was
+the result of a seven percent increase in production and a 16 percent increase
+in our net realized price after hedging, resulting in a 24 percent increase in
+production revenue. Included in the oil and gas
+production revenue amounts was $101.1 million of net realized hedging
+losses. Net cash payments made for income taxes increased
+$18.5 million due to fluctuating oil and gas prices which increased our
+estimated quarterly income tax payments in 2008. 
+Investing
+activities. Total cash outflow for 2008 capital expenditures
+for leasehold and drilling activities increased $107.6 million or 17 percent to
+$746.6 million. Total cash outflow for 2008 related to the
+acquisition of oil and gas properties decreased $101.1 million or 55 percent to
+$81.8 million. Cash received from the sale of oil and gas properties
+increased $178.4 million and deposits to restricted cash increased $14.4 million
+for 2008 as compared to 2007. 
+Financing
+activities. Net repayments to our credit facility decreased
+$64.0 million for the year ended December 31, 2008, compared to
+2007. We received $280.7 million less during 2008, compared to the
+same period in 2007, from the issuance of senior convertible
+debt. Our income tax benefit attributable to the exercise of
+stock awards increased $3.9 million to $13.9 million for the year ended
+December 31, 2008, compared with the 
+71 
+same
+period in 2007. We received $1.9 million more proceeds from the
+sale of common stock in 2008, compared to 2007. Additionally, we
+invested $51.3 million more to repurchase shares of our common stock during 2008
+compared to 2007. 
+We had
+$6.1 million in cash and cash equivalents and working capital of $15.2 million
+as of December 31, 2008, compared to $43.5 million in cash and cash
+equivalents and a working capital deficit of $92.6 million as of December
+31, 2007. 
+Capital
+Expenditures 
+The
+following table sets forth certain historical information regarding the costs
+incurred by us in our oil and gas producing activities. 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Development
+costs 
+$ 
+223,108 
+$ 
+587,548 
+$ 
+592,275 
+Exploration
+costs 
+154,122 
+92,199 
+111,470 
+Acquisitions 
+Proved
+properties 
+76 
+51,567 
+161,665 
+Unproved
+properties – acquisitions of 
+proved
+properties (1) 
+- 
+43,274 
+23,495 
+Unproved
+properties - other 
+41,677 
+83,078 
+38,436 
+Total,
+including asset retirement obligations (2)(3) 
+$ 
+418,983 
+$ 
+857,666 
+$ 
+927,341 
+(1) 
+Represents
+a portion of the allocated purchase price of unproved properties acquired
+as part of the acquisition of proved properties. Refer to Note
+3 – Acquisitions, Divestitures, and Assets Held for Sale in Part IV, Item
+15 of this report for additional
+information. 
+(2) 
+Includes
+capitalized interest of $1.9 million, $4.7 million, and $6.7 million for
+the years ended December 31 2009, 2008, and 2007,
+respectively. 
+(3) 
+Includes
+amounts relating to estimated asset retirement obligations of $(805,000),
+$15.4 million, and $27.6 million for the years ended December 31 2009,
+2008, and 2007, respectively. 
+Commodity
+Price Risk and Interest Rate Risk 
+We are
+exposed to market risk, including the effects of changes in oil and gas
+commodity prices and changes in interest rates. Changes in interest
+rates can affect the amount of interest we earn on our cash, cash equivalents,
+and short-term investments and the amount of interest we pay on borrowings under
+our revolving credit facility. Changes in interest rates do not
+affect the amount of interest we pay on our fixed-rate 3.50% Senior Convertible
+Notes, but do affect their fair market value. 
+Market
+risk is estimated as the potential change in fair value resulting from an
+immediate hypothetical one percentage point parallel shift in the yield
+curve. For fixed-rate debt, interest changes affect the fair market
+value but do not impact results of operations or cash
+flows. Conversely, interest rate changes for floating-rate debt
+generally do not affect the fair market value but do impact future results of
+operations and cash flows, assuming other factors are held
+constant. The carrying amount of our floating-rate debt typically
+approximates its fair value. We had $188.0 million of floating-rate
+debt outstanding as of December 31, 2009. Our fixed-rate debt
+outstanding, net of debt discount, at this same date was $266.9 million. As of December
+31, 2009, we do not have any interest rate hedges in place to mitigate
+potential risks. 
+Since we
+produce and sell natural gas and crude oil, our financial results are affected
+when prices for these commodities fluctuate. The following table
+reflects our estimate of the effect on net cash flows from operations of a ten
+percent change in our average realized sales price for natural gas, for oil, and
+in combination for the years presented, inclusive of the impact of
+hedging. These amounts have been reduced by the effective income tax
+rate applicable to each period since a reduction in revenue would reduce cash
+requirements to pay income taxes. General and administrative expenses
+have not been adjusted. To fund the capital expenditures we
+72 
+incurred
+in those years we would have been required to utilize amounts under our credit
+facility as a source of funds. In each of these years we would have
+had sufficient borrowing base available under our credit facility to meet this
+contingency without reducing or eliminating expenditures or altering our growth
+strategy. 
+Pro
+forma effect on net cash flow from operations of a ten
+percent decrease in average realized sales price: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Oil 
+$ 
+29,523 
+$ 
+27,818 
+$ 
+25,248 
+Natural
+Gas 
+11,874 
+37,288 
+29,998 
+Total 
+$ 
+41,397 
+$ 
+65,106 
+$ 
+55,246 
+We enter
+into hedging transactions in order to reduce the impact of fluctuations in
+commodity prices. Please refer to Note 10 – Derivative Financial Instruments of
+Part IV, Item 15 of this report for additional information about our oil and gas
+derivative contracts, and additional information is below under the caption
+Summary of Oil and Gas
+Production Hedges in Place. We do not anticipate significant
+changes in existing hedge contracts or derivative contract
+transactions. 
+Summary
+of Oil and Gas Production Hedges in Place 
+Our oil
+and natural gas derivative contracts include swap and costless collar
+arrangements. All contracts are entered into for other-than-trading
+purposes. Please refer to Note 10 – Derivative Financial Instruments
+in Part IV, Item 15 of this report for additional information regarding
+accounting for our derivative transactions. 
+Our net
+realized oil and gas prices are impacted by hedges we have placed on future
+forecasted production. Hedging is an important part of our financial
+risk management program. The amount of production we hedge is driven
+by the amount of debt on our consolidated balance sheet and the level of capital
+and long-term commitments we have made. In the case of a significant
+acquisition of producing properties, we will consider hedging a portion of the
+anticipated production in order to protect the economics assumed at the time of
+the acquisition. As of December 31, 2009, and through the date of
+this filing, our hedged positions of anticipated production through 2012 totaled
+approximately 6 million Bbls of oil, 63 million MMBtu of natural gas, and 1
+million Bbls of natural gas liquids. 
+In a
+typical commodity swap agreement, if the agreed-upon published third-party index
+price is lower than the swap fixed price, we receive the difference between the
+index price per unit of production and the agreed upon swap fixed
+price. If the index price is higher than the swap fixed price, we pay
+the difference. For collar agreements, we receive the difference
+between an agreed upon index and the floor price if the index price is below the
+floor price. We pay the difference between the agreed upon contracted
+ceiling price and the index price if the index price is above the contracted
+ceiling price. No amounts are paid or received if the index price is
+between the contracted floor and ceiling prices. 
+73 
+The
+following table describes the volumes, average contract prices, and fair value
+of contracts we have in place as of December 31, 2009. We seek to
+minimize basis risk and index the majority of our oil contracts to NYMEX WTI
+prices and the majority of our gas contracts to various regional index prices
+associated with pipelines in proximity to our areas of gas
+production. 
+Oil
+contracts 
+Oil Swaps 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair
+Value at 
+December
+31, 2009 
+Asset/(Liability) 
+(Bbls) 
+(per
+Bbl) 
+(in
+thousands) 
+First
+quarter 2010 
+468,000 
+$ 
+69.92 
+$ 
+(4,777 
+) 
+Second
+quarter 2010 
+426,000 
+$ 
+69.46 
+(5,180 
+) 
+Third
+quarter 2010 
+393,000 
+$ 
+68.77 
+(5,513 
+) 
+Fourth
+quarter 2010 
+309,000 
+$ 
+66.06 
+(5,457 
+) 
+2011 
+1,164,000 
+$ 
+67.06 
+(20,977 
+) 
+2012 
+1,051,400 
+$ 
+82.19 
+(5,503 
+) 
+All
+oil swap contracts 
+3,811,400 
+$ 
+(47,407 
+) 
+Oil Collars 
+Contract Period 
+NYMEX
+WTI 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+Fair
+Value at 
+December
+31, 2009 
+Asset/(Liability) 
+(Bbls) 
+(per
+Bbl) 
+(per
+Bbl) 
+(in
+thousands) 
+First
+quarter 2010 
+337,500 
+$ 
+50.00 
+$ 
+64.91 
+$ 
+(5,264 
+) 
+Second
+quarter 2010 
+341,000 
+$ 
+50.00 
+$ 
+64.91 
+(6,198 
+) 
+Third
+quarter 2010 
+344,500 
+$ 
+50.00 
+$ 
+64.91 
+(6,916 
+) 
+Fourth
+quarter 2010 
+344,500 
+$ 
+50.00 
+$ 
+64.91 
+(7,378 
+) 
+2011 
+1,236,000 
+$ 
+50.00 
+$ 
+63.70 
+(29,707 
+) 
+All
+oil collars 
+2,603,500 
+$ 
+(55,463 
+) 
+74 
+Gas
+Contracts 
+Gas Swaps 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair
+Value at 
+December
+31, 2009 
+Asset/(Liability) 
+(MMBtu) 
+(per
+MMBtu) 
+(in
+thousands) 
+First
+quarter 2010 
+IF
+ANR OK 
+160,000 
+$ 
+6.38 
+$ 
+136 
+IF
+CIG 
+210,000 
+$ 
+5.40 
+10 
+IF
+EL PASO 
+400,000 
+$ 
+6.94 
+587 
+IF
+HSC 
+2,270,000 
+$ 
+9.05 
+7,778 
+IF
+NGPL 
+460,000 
+$ 
+5.69 
+82 
+IF
+NNG VENTURA 
+380,000 
+$ 
+5.72 
+(60 
+) 
+IF
+PEPL 
+410,000 
+$ 
+5.27 
+(102 
+) 
+IF
+RELIANT 
+1,150,000 
+$ 
+5.33 
+(135 
+) 
+IF
+TETCO STX 
+270,000 
+$ 
+5.66 
+28 
+NYMEX
+Henry Hub 
+990,000 
+$ 
+7.38 
+1,719 
+Second
+quarter 2010 
+IF
+ANR OK 
+150,000 
+$ 
+5.31 
+(3 
+) 
+IF
+CIG 
+200,000 
+$ 
+5.16 
+13 
+IF
+EL PASO 
+390,000 
+$ 
+6.00 
+264 
+IF
+HSC 
+1,870,000 
+$ 
+7.80 
+4,297 
+IF
+NGPL 
+430,000 
+$ 
+5.23 
+(31 
+) 
+IF
+NNG VENTURA 
+360,000 
+$ 
+5.71 
+68 
+IF
+PEPL 
+170,000 
+$ 
+5.23 
+(9 
+) 
+IF
+RELIANT 
+1,250,000 
+$ 
+5.10 
+(270 
+) 
+IF
+TETCO STX 
+250,000 
+$ 
+5.64 
+45 
+NYMEX
+Henry Hub 
+960,000 
+$ 
+6.75 
+1,144 
+Third
+quarter 2010 
+IF
+ANR OK 
+70,000 
+$ 
+5.64 
+6 
+IF
+CIG 
+240,000 
+$ 
+5.38 
+13 
+IF
+EL PASO 
+370,000 
+$ 
+6.33 
+264 
+IF
+HSC 
+1,350,000 
+$ 
+8.03 
+3,119 
+IF
+NGPL 
+500,000 
+$ 
+5.43 
+(47 
+) 
+IF
+NNG VENTURA 
+360,000 
+$ 
+5.89 
+55 
+IF
+PEPL 
+230,000 
+$ 
+5.56 
+7 
+IF
+RELIANT 
+1,190,000 
+$ 
+5.37 
+(151 
+) 
+IF
+TETCO STX 
+230,000 
+$ 
+5.81 
+37 
+NYMEX
+Henry Hub 
+960,000 
+$ 
+6.94 
+1,132 
+Fourth
+quarter 2010 
+IF
+ANR OK 
+140,000 
+$ 
+5.97 
+4 
+IF
+CIG 
+270,000 
+$ 
+5.87 
+15 
+IF
+EL PASO 
+370,000 
+$ 
+6.43 
+190 
+IF
+HSC 
+590,000 
+$ 
+8.61 
+1,483 
+IF
+NGPL 
+430,000 
+$ 
+5.61 
+(124 
+) 
+IF
+NNG VENTURA 
+360,000 
+$ 
+6.34 
+24 
+IF
+PEPL 
+520,000 
+$ 
+5.92 
+23 
+IF
+RELIANT 
+1,350,000 
+$ 
+5.71 
+(219 
+) 
+IF
+TETCO STX 
+180,000 
+$ 
+6.23 
+33 
+NYMEX
+Henry Hub 
+840,000 
+$ 
+7.52 
+1,083 
+75 
+Gas Swaps (continued) 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair
+Value at 
+December
+31, 2009 
+Asset/(Liability) 
+(MMBtu) 
+(per
+MMBtu) 
+(in
+thousands) 
+2011 
+IF
+ANR OK 
+500,000 
+$ 
+6.10 
+23 
+IF
+CIG 
+1,030,000 
+$ 
+5.96 
+217 
+IF
+EL PASO 
+1,780,000 
+$ 
+6.35 
+510 
+IF
+HSC 
+360,000 
+$ 
+9.01 
+859 
+IF
+NGPL 
+1,040,000 
+$ 
+6.09 
+42 
+IF
+NNG VENTURA 
+1,200,000 
+$ 
+6.36 
+34 
+IF
+PEPL 
+1,830,000 
+$ 
+6.04 
+39 
+IF
+RELIANT 
+4,510,000 
+$ 
+6.13 
+494 
+IF
+TETCO STX 
+1,420,000 
+$ 
+6.51 
+465 
+NYMEX
+Henry Hub 
+2,130,000 
+$ 
+6.72 
+909 
+2012 
+IF
+ANR OK 
+360,000 
+$ 
+6.18 
+(11 
+) 
+IF
+CIG 
+1,020,000 
+$ 
+5.77 
+(160 
+) 
+IF
+EL PASO 
+850,000 
+$ 
+6.04 
+(139 
+) 
+IF
+NGPL 
+660,000 
+$ 
+6.34 
+94 
+IF
+NNG VENTURA 
+620,000 
+$ 
+6.51 
+(35 
+) 
+IF
+PEPL 
+2,730,000 
+$ 
+6.25 
+316 
+IF
+RELIANT 
+2,440,000 
+$ 
+6.22 
+9 
+IF
+TETCO STX 
+660,000 
+$ 
+6.30 
+(16 
+) 
+All
+gas swap contracts 
+48,420,000 
+$ 
+26,158 
+76 
+Gas Collars 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+Fair
+Value at 
+December
+31, 2009 
+Asset/(Liability) 
+(MMBtu) 
+(per
+MMBtu) 
+(per
+MMBtu) 
+(in
+thousands) 
+First
+quarter 2010 
+IF
+CIG 
+510,000 
+$ 
+4.85 
+$ 
+7.08 
+$ 
+65 
+IF
+HSC 
+150,000 
+$ 
+5.57 
+$ 
+7.88 
+46 
+IF
+PEPL 
+1,230,000 
+$ 
+5.31 
+$ 
+7.61 
+302 
+NYMEX
+Henry Hub 
+60,000 
+$ 
+6.00 
+$ 
+8.38 
+27 
+Second
+quarter 2010 
+IF
+CIG 
+510,000 
+$ 
+4.85 
+$ 
+7.08 
+177 
+IF
+HSC 
+150,000 
+$ 
+5.57 
+$ 
+7.88 
+84 
+IF
+PEPL 
+1,235,000 
+$ 
+5.31 
+$ 
+7.61 
+639 
+NYMEX
+Henry Hub 
+60,000 
+$ 
+6.00 
+$ 
+8.38 
+49 
+Third
+quarter 2010 
+IF
+CIG 
+510,000 
+$ 
+4.85 
+$ 
+7.08 
+121 
+IF
+HSC 
+150,000 
+$ 
+5.57 
+$ 
+7.88 
+72 
+IF
+PEPL 
+1,240,000 
+$ 
+5.31 
+$ 
+7.61 
+518 
+NYMEX
+Henry Hub 
+60,000 
+$ 
+6.00 
+$ 
+8.38 
+46 
+Fourth
+quarter 2010 
+IF
+CIG 
+510,000 
+$ 
+4.85 
+$ 
+7.08 
+(23 
+) 
+IF
+HSC 
+150,000 
+$ 
+5.57 
+$ 
+7.88 
+38 
+IF
+PEPL 
+1,240,000 
+$ 
+5.31 
+$ 
+7.61 
+247 
+NYMEX
+Henry Hub 
+60,000 
+$ 
+6.00 
+$ 
+8.38 
+28 
+2011 
+IF
+CIG 
+1,800,000 
+$ 
+5.00 
+$ 
+6.32 
+(360 
+) 
+IF
+HSC 
+480,000 
+$ 
+5.57 
+$ 
+6.77 
+(63 
+) 
+IF
+PEPL 
+4,225,000 
+$ 
+5.31 
+$ 
+6.51 
+(786 
+) 
+NYMEX
+Henry Hub 
+120,000 
+$ 
+6.00 
+$ 
+7.25 
+15 
+All
+gas collars 
+14,450,000 
+$ 
+1,242 
+77 
+Natural
+Gas Liquid Contracts 
+Natural Gas Liquid Swaps 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair
+Value at 
+December
+31, 2009 
+Asset/(Liability) 
+(approx.
+Bbls) 
+(per
+Bbl) 
+(in
+thousands) 
+First
+quarter 2010 
+206,000 
+$ 
+46.73 
+$ 
+(770 
+) 
+Second
+quarter 2010 
+191,000 
+$ 
+46.28 
+(364 
+) 
+Third
+quarter 2010 
+179,000 
+$ 
+46.20 
+(339 
+) 
+Fourth
+quarter 2010 
+169,000 
+$ 
+46.16 
+(424 
+) 
+2011 
+480,000 
+$ 
+43.20 
+(2,334 
+) 
+2012 
+214,000 
+$ 
+43.70 
+(1,181 
+) 
+All
+natural gas liquid swaps 
+1,439,000 
+$ 
+(5,412 
+) 
+Please
+see Note 10 – Derivative Financial Instruments in Part IV, Item 15 of this
+report for additional information regarding our oil and gas hedges. 
+Schedule
+of Contractual Obligations 
+The
+following table summarizes our future estimated principal payments and minimum
+lease payments for the periods specified (in millions): 
+Contractual
+Obligations 
+Total 
+Less
+than 1 year 
+1-3
+years 
+3-5
+years 
+More
+than 5 years 
+Long-Term
+Debt 
+$ 
+498.2 
+$ 
+10.1 
+$ 
+488.1 
+$ 
+- 
+$ 
+- 
+Operating
+Leases 
+61.1 
+27.8 
+9.7 
+5.3 
+18.3 
+Other
+Long-Term Liabilities 
+302.8 
+92.1 
+125.1 
+59.9 
+25.7 
+Total 
+$ 
+862.1 
+$ 
+130.0 
+$ 
+622.9 
+$ 
+65.2 
+$ 
+44.0 
+This
+table includes the remaining unfunded portion of our estimated pension liability
+of $9.5 million even though we recognize that we cannot determine with
+accuracy the timing of future payments. The Company is not required
+to make a contribution to the Pension Plan in 2010. We made
+contributions of $2.0 million, $2.5 million, and $2.2 million in 2009, 2008, and
+2007, respectively, towards the pension liability. The table also
+includes $166.1 million in other long-term liabilities that represents six years
+of undiscounted forecasted payments for the Net Profits
+Plan. Payments are expected to be similar on an annual
+basis for the years beyond what is shown in this table. The
+amounts recorded on the consolidated balance sheets reflect all future Net
+Profits Plan payments and the impact of discounting and therefore differ from
+the amounts disclosed in this table. The variability in the amount of
+payments will be a direct reflection of commodity prices, production rates,
+capital expenditures, and operating costs in future
+periods. Predicting the timing and amounts of payments associated
+with this liability is contingent upon estimates of appropriate discount
+factors, adjusting for risk and time value, and upon a number of factors that we
+cannot control. The components of the operating leases are discussed
+in more detail in Note 6 – Commitments and Contingencies of Part IV, Item 15 of
+this report. 
+The
+scheduled repayment of the long-term credit facility is
+2012. Accordingly, it has been disclosed in the table as
+such. Since this is a revolving credit facility, the actual payments
+will vary significantly. We anticipate refinancing this obligation
+prior to its expiration date. For purposes of this table, we assume
+we will net share settle the 3.50% Senior Convertible
+Notes. Accordingly, $22.7 million of interest payments related
+to the 3.50% Senior Convertible Notes are included in the long-term debt line in
+table above. We have excluded asset retirement obligations because we
+are not able to accurately predict the precise timing of these
+amounts. Pension 
+78 
+liabilities,
+asset retirement obligations, and Net
+Profits Plan are discussed in Note 8 – Pension Benefits, Note 9 – Asset
+Retirement Obligations, and Note 7 – Compensation Plans of Part IV, Item 15 of
+this report. 
+This
+table also includes estimated oil and natural gas derivative payments of $119.4
+million based on future market prices as of December 31, 2009. This
+amount represents only the cash outflows; it does not include estimated oil and
+gas derivative receipts of $38.0 million that would be paid based on December
+31, 2009, market prices. The net liability of $81.4 million
+represents cash flows from the intrinsic value of our collar arrangements and
+differs in amount from our recorded fair value, which as of December 31, 2009,
+was a net liability of $80.9 million. The fair value considers time
+value, volatility, and the risk of non-performance for us and for our
+counterparties. Both the intrinsic value and fair value will change
+as oil and natural gas commodity prices change. Please refer to the
+discussion above under the caption Summary of Oil and Gas Production
+Hedges in Place and Note 10 – Derivative Financial Instruments
+in Part IV, Item 15 of this report for additional information regarding our oil
+and gas hedges. 
+We
+believe that we will continue to pay annual dividends of $0.10 per
+share. We anticipate making cash payments for income taxes, dependent
+on net income and capital spending. 
+Off-balance
+Sheet Arrangements 
+As part
+of our ongoing business, we have not participated in transactions that generate
+relationships with unconsolidated entities or financial partnerships, such as
+entities often referred to as structured finance or special purpose entities,
+which would have been established for the purpose of facilitating off-balance
+sheet arrangements or other contractually narrow or limited
+purposes. As of December 31, 2009, we have not been involved in any
+unconsolidated SPE transactions. 
+We
+evaluate our transactions to determine if any variable interest entities
+exist. If it is determined that we are the primary beneficiary of a
+variable interest entity, that entity is consolidated into our consolidated
+financial statements. 
+Critical
+Accounting Policies and Estimates 
+Our
+discussion of financial condition and results of operations is based upon the
+information reported in our consolidated financial statements. The
+preparation of these consolidated financial statements requires us to make
+assumptions and estimates that affect the reported amounts of assets,
+liabilities, revenues, and expenses as well as the disclosure of contingent
+assets and liabilities as of the date of our financial statements. We
+base our decisions affecting the estimates we use on historical experience and
+various other sources that are believed to be reasonable under the
+circumstances. Actual results may differ from the estimates we
+calculate due to changes in business conditions or due to unexpected
+circumstances. Policies we believe are critical to understanding our
+business operations and results of operations are detailed below. For
+additional information on our significant accounting policies, please refer to
+Note 1 – Summary of Significant Accounting Policies, Note 9 – Asset Retirement
+Obligations, and Note 16 – Disclosures about Oil and Gas Producing Activities in
+Part IV, Item 15 of this report. 
+Proved Oil and gas reserve
+quantities. Estimated reserve quantities and the related
+estimates of future net cash flows are critical estimates for our company
+because they affect the perceived value of an exploration and production
+company. Additionally, they are used in comparative financial
+analysis ratios and are used as the basis for the most significant accounting
+estimates in our financial statements. Those significant accounting
+estimates include the periodic calculations of depletion, depreciation, and
+impairment of our proved oil and gas properties and the estimates of our
+liability for future payments under the Net Profits Plan. Future cash
+inflows and future production and development costs are determined by applying
+prices and costs, including transportation, quality differentials, and basis
+differentials, applicable to each period to the estimated quantities of proved
+oil and gas reserves remaining to be produced as of the end of that
+period. Expected cash flows are discounted to present value using a
+discount rate that depends upon the purpose for which the reserve estimates will
+be used. For example, the standardized measure calculations required
+by Accounting Standards Codification Topic 932 
+79 
+Extractive Activities – Oil and
+Gas requires a ten percent discount rate to be
+applied. Although reserve estimates are inherently imprecise, and
+estimates of new discoveries and undeveloped locations are more imprecise than
+those of established producing oil and gas properties, we make a considerable
+effort in estimating our reserves, including using independent reserve
+engineering consultants. We expect that periodic reserve estimates
+will change in the future as additional information becomes available and as oil
+and gas prices and operating and capital costs change. We evaluate
+and estimate our proved oil and gas reserves at December 31 and June 30 of each
+year. For purposes of depletion, depreciation, and impairment,
+reserve quantities are adjusted at all interim periods for the estimated impact
+of additions and dispositions. Changes in depletion, depreciation, or
+impairment calculations caused by changes in reserve quantities or net cash
+flows are recorded in the period the reserve estimates change. 
+The
+following table presents information regarding reserve changes from period to
+period that reflect changes from items we do not control, such as price, and
+from changes resulting from better information due to production history, and
+from well performance. These changes do not require a capital
+expenditure on our part, but may have resulted from capital expenditures we
+incurred to develop other estimated proved reserves. 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+BCFE 
+BCFE 
+BCFE 
+Change 
+Change 
+Change 
+Revisions
+resulting from price changes 
+12.0 
+(199.7 
+) 
+34.5 
+Revisions
+resulting from performance 
+(61.6 
+) 
+(44.5 
+) 
+6.4 
+Total 
+(49.6 
+) 
+(244.2 
+) 
+40.9 
+We have
+added 282.8 BCFE of reserves over a three-year period, excluding
+divestitures. A 99.7 BCFE decrease in reserves was a result of
+changes in engineering estimates based on the performance of our oil and gas
+properties. A 153.2 BCFE decrease in reserves was a result of price
+changes. As previously noted, oil and gas prices are volatile, and
+estimates of reserves are inherently imprecise. Consequently, we
+anticipate we may continue to experience these types of changes. 
+The
+following table reflects the estimated BCFE change and percentage change to our
+total reported reserve volumes from the described hypothetical
+changes: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+BCFE 
+Percentage 
+BCFE 
+Percentage 
+BCFE 
+Percentage 
+Change 
+Change 
+Change 
+Change 
+Change 
+Change 
+A
+10% decrease in pricing 
+(25.1 
+) 
+(3)% 
+(120.8 
+) 
+(14)% 
+(16.3 
+) 
+(2)% 
+A
+10% decrease in proved undeveloped reserves 
+(14.2 
+) 
+(2)% 
+(15.0 
+) 
+(2)% 
+(25.0 
+) 
+(2)% 
+Additional
+reserve information can be found in the reserve table and discussion included in
+Items 1 and 2 of Part I of this report. 
+Successful efforts method of
+accounting. Generally accepted accounting principles provide
+for two alternative methods for the oil and gas industry to use in accounting
+for oil and gas producing activities. These two methods are generally
+known in our industry as the full cost method and the successful efforts
+method. Both methods are widely used. The methods are
+different enough that in many circumstances the same set of facts will provide
+materially different financial statement results within a
+given year. We have chosen the successful efforts method of
+accounting for our oil and gas producing activities, and a detailed description
+is included in Note 1 of Part IV, Item 15 of this report. 
+80 
+Revenue
+recognition. Our revenue recognition policy is significant
+because revenue is a key component of our results of operations and our
+forward-looking statements contained in our analysis of liquidity and capital
+resources. We derive our revenue primarily from the sale of produced
+natural gas, natural gas liquids, and crude oil. We report revenue as
+the gross amounts we receive before taking into account production taxes and
+transportation costs, which are reported as separate
+expenses. Revenue is recorded in the month our production is
+delivered to the purchaser, but payment is generally received between 30 and 90
+days after the date of production. No revenue is recognized unless it
+is determined that title to the product has transferred to a
+purchaser. At the end of each month we make estimates of the amount
+of production delivered to the purchaser and the price we will
+receive. We use our knowledge of our properties, their historical
+performance, NYMEX and local spot market prices, and other factors as the basis
+for these estimates. Variances between our estimates and the actual
+amounts received are recorded in the month payment is received. A ten
+percent change in our year-end revenue accrual would have impacted net income
+before tax by approximately $8 million in 2009. 
+Crude oil and natural gas
+hedging. Our crude oil and natural gas hedging contracts are
+intended to and usually do qualify for cash flow deferral hedge
+accounting under Accounting Standards Codification Topic 815. Under
+this guidance a majority of the gain or loss from a contract qualifying as a
+cash flow hedge is deferred from recognition in the consolidated statement of
+operations. The realized gain or loss reflected in the consolidated
+statement of operations is based on actual hedge contract
+settlements. If our natural gas and crude oil hedge contracts did not
+qualify for hedge accounting treatment or if we chose not to use hedge
+accounting methodology, our periodic consolidated statements of operations could
+include significant changes in the estimate of non-cash derivative gain or loss
+due to swings in the value of these contracts. Consequently, we would
+report a different amount of oil and gas hedge loss in our statements of
+operations. These fluctuations could be especially significant in a
+volatile pricing environment such as what we have encountered over the last few
+years. The amounts recorded to accumulated other comprehensive income
+(loss) of $103.3 million of loss, $223.5 million of income, and $170.0 million
+of loss for 2009, 2008, and 2007, respectively, would have increased or
+decreased net income after tax if our hedges did not qualify as cash flow
+deferral hedges under Accounting Standards Codification Topic 815. 
+Change in Net Profits Plan
+Liability. We record the estimated liability of future
+payments for our Net Profits Plan. The estimated liability is
+calculated based on a number of assumptions, including estimates of proved oil
+and gas reserves, recurring and workover lease operating expense, production and
+ad valorem tax rates, present value discount factors, and pricing
+assumptions. Additional discussion is included in the analysis in the
+above section titled Overview
+of the Company, under the heading Net Profits
+Plan. In December 2007 our Board approved an incentive
+compensation plan restructuring whereby the Net Profits Plan was replaced with a
+long-term incentive program utilizing performance shares. As a
+result, the 2007 Net Profits Plan pool was the last pool
+established. 
+Asset retirement
+obligations. We are required to recognize an estimated
+liability for future costs associated with the abandonment of our oil and gas
+properties. We base our estimate of the liability on our historical
+experience in abandoning oil and gas wells projected into the future based on
+our current understanding of federal and state regulatory
+requirements. Our present value calculations require us to estimate
+the economic lives of our properties, assume what future inflation rates apply
+to external estimates, and determine what credit adjusted risk-free rate
+discount to use. The impact to the consolidated statement of
+operations from these estimates is reflected in our depreciation, depletion, and
+amortization calculations and occurs over the remaining life of our oil and gas
+properties. 
+Valuation of long-lived and
+intangible assets. Our property and equipment are recorded at
+cost. An impairment allowance is provided on unproven property when
+we determine that the property will not be developed or the carrying value will
+not be realized. We evaluate the realizability of our proved
+properties and other long-lived assets whenever events or changes in
+circumstances indicate that impairment may be appropriate. Our
+impairment test compares the expected undiscounted future net revenues from
+property, using escalated pricing, with the related net capitalized cost of the
+property at the end of each period. When the net capitalized costs
+exceed the undiscounted future net revenue of a property, the cost of the
+property is written down to its estimate of fair value, which is determined by
+applying a discount rate we believe is indicative of the current
+market. Our criteria for an acceptable internal rate of return are
+subject to change over time. Different pricing 
+81 
+assumptions
+or discount rates could result in a different calculated
+impairment. We recorded a $174.8 million impairment of proved oil and
+gas properties in 2009. A significant decrease in commodity prices
+and increase in differentials during the first quarter of 2009 caused the
+majority of the non-cash impairment. The largest portion of the
+impairment in 2009 was $97.3 million related to assets located in the
+Mid-Continent region that were significantly impacted by lower prices and wider
+than normal differentials. 
+Income taxes. We
+provide for deferred income taxes on the difference between the tax basis of an
+asset or liability and its carrying amount in our financial statements in
+accordance with Accounting Standards Codification Topic 740. This
+difference will result in taxable income or deductions in future years when the
+reported amount of the asset or liability is recovered or settled,
+respectively. Considerable judgment is required in determining when
+these events may occur and whether recovery of an asset is more likely than
+not. Additionally, our federal and state income tax returns are
+generally not filed before the consolidated financial statements are prepared,
+therefore, we estimate the tax basis of our assets and liabilities at the end of
+each period as well as the effects of tax rate changes, tax credits, and net
+operating and capital loss carryforwards and carrybacks. Adjustments
+related to differences between the estimates we use and actual amounts we report
+are recorded in the periods in which we file our income tax
+returns. These adjustments and changes in our estimates of asset
+recovery and liability settlement could have an impact on our results of
+operations. A one percent change in our effective tax rate would have
+changed our calculated income tax benefit by $675,000 for the year ended
+December 31, 2009. 
+Other
+Liquidity and Capital Resources Information 
+Pension
+Benefits 
+Substantially
+all of our employees who meet age and service requirements participate in a
+non-contributory defined benefit pension plan. At December 31, 2009, and
+2008, our underfunded status was $9.4 million and $8.2 million,
+respectively. The increase in underfunding from 2008 to 2009 was primarily
+attributable to lower discount rates, which were 6.6 percent in 2008 and 6.1
+percent in 2009. Our pension plan assets increased from $6.6 million at
+December 31, 2008, to $9.1 million at December 31, 2009. On an
+Employee Retirement Income Security Act basis, the Company’s pension plan
+remains fully funded at January 1, 2010. We are not required to make any
+contributions to the pension plan in 2010. For additional information
+please refer to Note 8 – Pension Benefits in Part IV, Item 15 of this
+report. 
+Accounting
+Matters 
+Please
+refer to Note 5 – Long-term Debt, Note 8 – Pension Benefits, Note 10 -
+Derivative Financial Instruments, Note 11 – Fair Value Measurements, Note 16 –
+Disclosures about Oil and Gas Producing Activities, and the section entitled
+“ Recently Issued Accounting
+Standards ” under Note 1 – Summary of Significant Accounting Policies for
+additional information on the recent adoption of new authoritative accounting
+guidance in Part IV, Item 15 of this report. 
+Environmental 
+St.
+Mary’s compliance with applicable environmental regulations has to date not
+resulted in significant capital expenditures or material adverse effects on our
+liquidity or results of operations. We believe we are in substantial
+compliance with environmental regulations and do not currently anticipate that
+material future expenditures will be required under the existing regulatory
+framework. However, we are unable to predict the impact that
+compliance with future laws or regulations, such as those currently being
+considered as discussed below, may have on future capital expenditures,
+liquidity, and results of operations. 
+The U.S.
+Congress is currently considering legislation that would amend the Safe Drinking
+Water Act to eliminate an existing exemption from federal regulation of
+hydraulic fracturing activities. Hydraulic fracturing is a common
+process in our industry of creating artificial cracks, or fractures, in deep
+underground rock formations through the pressurized injection of water, sand and
+other additives to enable oil or natural gas to move more easily through the
+rock pores to a production well. This process is often necessary to
+produce commercial 
+82 
+quantities
+of oil and natural gas from many reservoirs, especially shale rock
+formations. We routinely utilize hydraulic fracturing in many of our
+reservoirs, and our Eagle Ford, Haynesville, Marcellus , and Woodford
+shale programs utilize or contemplate the utilization of hydraulic
+fracturing. Currently, regulation of hydraulic fracturing is
+primarily conducted at the state level through permitting and other compliance
+requirements. If adopted, the proposed amendment to the Safe Drinking
+Water Act could result in additional regulations and permitting requirements at
+the federal level. Those additional regulations and permitting
+requirements, as well as other regulatory developments at the state level, could
+lead to significant operational delays and increased operating costs, and could
+make it more difficult to perform hydraulic fracturing. 
+Climate
+Change 
+Climate
+change has become the subject of an important public policy
+debate. While climate change remains a complex issue, scientific
+research suggests that an increase in greenhouse gas emissions may pose a risk
+to society and the environment. The oil and natural gas exploration
+and production industry is a source of certain greenhouse gas emissions, namely
+carbon dioxide and methane, and future restrictions on the combustion of fossil
+fuels or the venting of natural gas could have a significant impact on our
+future operations. We are actively monitoring the following climate
+change related issues: 
+Impact of Legislation and
+Regulation. The commercial risk associated with the
+exploration and production of fossil fuels lies in the uncertainty of
+government-imposed climate change legislation, including cap and trade systems,
+and regulations that may affect us, our suppliers, and our
+customers. The cost of meeting these requirements may have an adverse
+impact on our financial condition, results of operations and cash flows, and
+could reduce the demand for the oil and natural gas that we
+produce. The U.S. Congress and several states are considering
+adopting climate change legislation. However, the current state of
+development of many state and federal climate change regulatory initiatives
+makes it difficult to predict with certainty the future impact on us, including
+accurately estimating the related compliance costs that we may
+incur. 
+Impact of U.S. Participation in
+International Accords. The U.S. has
+participated in international discussions to develop a treaty or other agreement
+to require reductions in greenhouse gas emissions after 2012, and has indicated
+that it wishes to associate itself with the Copenhagen Accord, which includes a
+non-binding commitment to reduce greenhouse gas emissions. While no
+specific new international climate change accord has been adopted that would
+affect our current operating locations, the current state of development of many
+initiatives makes it difficult to assess the timing or effect of any pending
+discussions of future accords or predict with certainty the future costs that we
+may incur in order to comply with any applicable requirements from future
+international treaties or regulations. 
+Indirect Consequences of Regulation
+or Business Trends. We believe that there are both risks and
+opportunities arising from climate change issues. See Items 1 and 2.
+Business and Properties – Government Regulations, and the following risk factors
+listed in Item 1A. Risk Factors – 
+· 
+We are subject to operating
+and environmental risks and hazards that could result in substantial
+losses. 
+· 
+Our operations are subject to
+complex laws and regulations, including environmental regulations that
+result in substantial costs and other
+risks. 
+· 
+Possible legislation and
+regulations related to global warming and climate change could have an
+adverse effect on our operations and the demand for oil and natural
+gas. 
+In terms
+of opportunities, the regulation of greenhouse gas emissions and the
+introduction of alternative incentives, such as enhanced oil recovery, carbon
+sequestration and low carbon fuel standards, could benefit us in a variety of
+ways. For example, although climate change legislation could reduce
+the overall demand for the oil and natural gas that we produce, the relative
+demand for natural gas may increase since the burning of natural gas produces
+lower levels of emissions than other readily available fossil fuels such as oil
+and coal. In addition, if renewable resources, such as wind or solar
+power become more prevalent, natural gas-fired electric plants may 
+83 
+provide
+an alternative backup to maintain consistent electricity
+supply. Also, if states adopt low-carbon fuel standards, natural gas
+may become a more attractive transportation fuel. More than 60% of
+our 2009 production on an MCFE basis was natural gas. Market-based
+incentives for the capture and storage of carbon dioxide in underground
+reservoirs, particularly in oil and natural gas reservoirs, could also benefit
+us through the potential to obtain greenhouse gas emission allowances or offsets
+from or government incentives for the sequestration of carbon
+dioxide. 
+Physical Impacts of Climate Change
+on our Costs and Operations. There has been public discussion
+that climate change may be associated with extreme weather conditions such as
+more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well
+as rising sea levels. Extreme weather conditions can increase our
+costs, and damage resulting from extreme weather may not be fully
+insured. However, the extent to which climate change may lead to
+increased storm or weather hazards affecting our operations is difficult to
+identify at this time. See Item 1A. Risk Factors – We are subject to operating and
+environmental risks and hazards that could result in substantial
+losses . 
+84 
+ITEM
+7A. QUANTITATIVE
+AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+The
+information required by this item is provided under the captions “ Commodity Price Risk and Interest
+Rate Risk, ” “ Summary of
+Oil and Gas Production Hedges in Place ,” and “ Summary of Interest Rate Hedges in
+Place ” in Item 7 above and is incorporated herein by
+reference. 
+ITEM
+8. FINANCIAL
+STATEMENTS AND SUPPLEMENTARY DATA 
+The
+Consolidated Financial Statements that constitute Item 8 follow the text of this
+report. An index to the Consolidated Financial Statements and
+Schedules appears in Item 15(a) of this report. 
+ITEM
+9. CHANGES
+IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
+DISCLOSURE 
+None. 
+ITEM
+9A. CONTROLS
+AND PROCEDURES 
+We
+maintain a system of disclosure controls and procedures that are designed to
+ensure that information required to be disclosed in our SEC reports is recorded,
+processed, summarized, and reported within the time periods specified in the
+SEC’s rules and forms, and to ensure that such information is accumulated and
+communicated to our management, including the Chief Executive Officer and the
+Chief Financial Officer, as appropriate, to allow for timely decisions regarding
+required disclosure. 
+We
+carried out an evaluation, under the supervision and with the participation of
+our management, including the Chief Executive Officer and the Chief Financial
+Officer, of the effectiveness of the design and operation of our disclosure
+controls and procedures as of the end of the period covered by the Annual Report
+on Form 10-K. Based upon that evaluation, the Chief Executive Officer
+and the Chief Financial Officer concluded that our disclosure controls and
+procedures are effective for the purpose discussed above as of the end of the
+period covered by this Annual Report on Form 10-K. There was no
+change in our internal control over financial reporting that occurred during our
+most recent fiscal quarter that has materially affected, or is reasonably likely
+to materially affect, our internal control over financial
+reporting. 
+85 
+MANAGEMENT’S
+REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 
+To the
+Stockholders’ of St. Mary Land & Exploration Company 
+Management
+of the Company is responsible for establishing and maintaining adequate internal
+control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f)
+under the Securities Exchange Act of 1934, as amended. The Company’s
+internal control over financial reporting is designed to provide reasonable
+assurance regarding the reliability of financial reporting and the preparation
+of financial statements for external purposes in accordance with generally
+accepted accounting principles. The Company’s internal control over
+financial reporting includes those policies and procedures that: 
+(i)
+Pertain
+to the maintenance of records that, in reasonable detail, accurately and
+fairly reflect the transactions and dispositions of the assets of the
+Company; 
+(ii) 
+Provide
+reasonable assurance that transactions are recorded as necessary to permit
+preparation of financial statements in accordance with generally accepted
+accounting principles, and that receipts and expenditures of the Company
+are being made only in accordance with authorizations of management and
+directors of the Company; and 
+(iii) 
+Provide
+reasonable assurance regarding prevention or timely detection of
+unauthorized acquisition, use, or disposition of the Company’s assets that
+have a material effect on the financial
+statements. 
+Because
+of the inherent limitations, internal controls over financial reporting may not
+prevent or detect misstatements. Also, projections of any evaluation
+of effectiveness to future periods are subject to the risk that controls may
+become inadequate because of the changes in conditions, or that the degree of
+compliance with the policies and procedures may deteriorate. 
+Management
+assessed the effectiveness of the Company’s internal control over financial
+reporting as of December 31, 2009. In making this assessment,
+management used the criteria set forth by the Committee of Sponsoring
+Organizations of the Treadway Commission in Internal Control-Integrated
+Framework. 
+Based on
+our assessment and those criteria, management believes that the Company
+maintained effective internal control over financial reporting as of December
+31, 2009. 
+The
+Company’s independent registered public accounting firm has issued an
+attestation report on the Company’s internal controls over financial
+reporting. That report immediately follows this report. 
+/s/ ANTHONY J. BEST 
+/s/ A. WADE PURSELL 
+Anthony
+J. Best 
+A.
+Wade Pursell 
+President
+and Chief Executive Officer 
+Executive
+Vice President and Chief Financial Officer 
+February
+23, 2010 
+February
+23, 2010 
+86 
+REPORT OF
+INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the
+Board of Directors and Stockholders of 
+St. Mary
+Land & Exploration Company and Subsidiaries 
+Denver,
+Colorado 
+We have
+audited the internal control over financial reporting of St. Mary Land &
+Exploration Company and subsidiaries (the “Company”) as of December 31, 2009,
+based on criteria established in Internal Control – Integrated
+Framework issued by the Committee of Sponsoring Organizations of the
+Treadway Commission. The Company’s management is responsible for
+maintaining effective internal control over financial reporting and for its
+assessment of the effectiveness of internal control over financial reporting,
+included in the accompanying Management’s Report on Internal Control Over
+Financial Reporting. Our responsibility is to express an opinion on
+the Company’s internal control over financial reporting based on our
+audit. 
+We
+conducted our audit in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). Those standards require
+that we plan and perform the audit to obtain reasonable assurance about whether
+effective internal control over financial reporting was maintained in all
+material respects. Our audit included obtaining an understanding of
+internal control over financial reporting, assessing the risk that a material
+weakness exists, testing and evaluating the design and operating effectiveness
+of internal control based on the assessed risk, and performing such other
+procedures as we considered necessary in the circumstances. We
+believe that our audit provides a reasonable basis for our opinion. 
+A
+company’s internal control over financial reporting is a process designed by, or
+under the supervision of, the company’s principal executive and principal
+financial officers, or persons performing similar functions, and effected by the
+company’s board of directors, management, and other personnel to provide
+reasonable assurance regarding the reliability of financial reporting and the
+preparation of the financial statements for external purposes in accordance with
+generally accepted accounting principles. A company’s internal
+control over financial reporting includes those policies and procedures that (1)
+pertain to the maintenance of records that, in reasonable detail, accurately and
+fairly reflect the transactions and dispositions of the assets of the company;
+(2) provide reasonable assurance that transactions are recorded as necessary to
+permit preparation of financial statements in accordance with generally accepted
+accounting principles, and that receipts and expenditures of the company are
+being made only in accordance with authorizations of management and directors of
+the company; and (3) provide reasonable assurance regarding prevention or timely
+detection of unauthorized acquisition, use, or disposition of the company’s
+assets that could have a material effect on the financial
+statements. 
+Because
+of the inherent limitations of internal control over financial reporting,
+including the possibility of collusion or improper management override of
+controls, material misstatements due to error or fraud may not be prevented or
+detected on a timely basis. Also, projections of any evaluation of
+the effectiveness of the internal control over financial reporting to future
+periods are subject to the risk that controls may become inadequate because of
+changes in conditions, or that the degree of compliance with the policies or
+procedures may deteriorate. 
+In our
+opinion, the Company maintained, in all material respects, effective internal
+control over financial reporting as of December 31, 2009, based on the criteria
+established in Internal
+Control – Integrated Framework issued by the Committee of Sponsoring
+Organizations of the Treadway Commission. 
+We have
+also audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), the consolidated financial statements as of and
+for the year ended December 31, 2009, of the Company and our report
+dated February 23, 2010, expressed an unqualified opinion on those financial
+statements and included explanatory paragraphs regarding the Company’s adoption
+of new accounting standards. 
+/s/
+DELOITTE & TOUCHE LLP 
+Denver,
+Colorado 
+February
+23, 2010 
+87 
+ITEM
+9B. OTHER
+INFORMATION 
+None. 
+PART
+III 
+ITEM
+10. DIRECTORS,
+EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE 
+The
+information required by this Item concerning St. Mary’s Directors and corporate
+governance is incorporated by reference to the information provided under the
+captions “Structure of the Board of Directors,” “Proposal 1 - Election of
+Directors,” and “Corporate Governance” in St. Mary’s definitive proxy statement
+for the 2010 annual meeting of stockholders to be filed within 120 days from
+December 31, 2009. The information required by the Item
+concerning St. Mary’s executive officers is incorporated by reference to the
+information provided in Part I – Item 4A – EXECUTIVE OFFICERS OF THE REGISTRANT,
+included in this Form 10-K. 
+The
+information required by this Item concerning compliance with Section 16(a) of
+the Securities Exchange Act of 1934 is incorporated by reference to the
+information provided under the caption “Section 16(a) Beneficial Ownership
+Reporting Compliance” in St. Mary’s definitive proxy statement for the 2010
+annual meeting of stockholders to be filed within 120 days from December 31,
+2009. 
+ITEM
+11. EXECUTIVE
+COMPENSATION 
+The
+information required by this Item is incorporated by reference to the
+information provided under the captions, “Executive Compensation” and
+“Director Compensation”” in St. Mary’s definitive proxy statement for the 2010
+annual meeting of stockholders to be filed within 120 days from December 31,
+2009. 
+ITEM
+12. SECURITY
+OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
+MATTERS 
+The
+information required by this Item concerning security ownership of certain
+beneficial owners and management is incorporated by reference to the information
+provided under the caption “Security Ownership of Certain Beneficial Owners and
+Management” in St. Mary’s definitive proxy statement for the 2010 annual meeting
+of stockholders to be filed within 120 days from December 31, 2009. 
+The
+information required by this Item concerning securities authorized for issuance
+under equity compensation plans is incorporated by reference to the information
+provided under the caption “Equity Compensation Plans” in Part II, Item 5 –
+Market for Registrant’s Common Equity, Related Stockholder Matter and Issuer
+Purchases of Equity Securities, included in this Form 10-K. 
+ITEM
+13. CERTAIN
+RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
+INDEPENDENCE 
+The
+information required by this Item is incorporated by reference to the
+information provided under the caption “Certain Relationships and Related
+Transactions,” and “Corporate Governance,” in St. Mary’s definitive proxy
+statement for the 2010 annual meeting of stockholders to be filed within 120
+days from December 31, 2009. 
+88 
+ITEM
+14. PRINCIPAL
+ACCOUNTANT FEES AND SERVICES 
+The
+information required by this Item is incorporated by reference to the
+information provided under the caption “Independent Accountants” and “Audit
+Committee Preapproval Policy and Procedures” in St. Mary’s definitive proxy
+statement for the 2010 annual meeting of stockholders to be filed within 120
+days from December 31, 2009. 
+PART
+IV 
+ITEM
+15. EXHIBITS
+AND FINANCIAL STATEMENT SCHEDULES 
+(a)(1)
+and (a) (2) Financial Statements and Financial Statement Schedules: 
+Report of Independent
+Registered Public Accounting Firm 
+F-1 
+Consolidated Balance
+Sheets 
+F-2 
+Consolidated Statements of
+Operations 
+F-3 
+Consolidated Statements of
+Stockholders’ Equity and Comprehensive Income 
+F-4 
+Consolidated Statements of Cash
+Flows 
+F-5 
+Notes to Consolidated Financial
+Statements 
+F-7 
+All
+schedules are omitted because the required information is not applicable or is
+not present in amounts sufficient to require submission of the schedule or
+because the information required is included in the Consolidated Financial
+Statements and Notes thereto. 
+(b) Exhibits. The
+following exhibits are filed or furnished with or incorporated by reference into
+this report on Form 10-K: 
+Exhibit 
+Number 
+Description 
+2.1 
+Purchase
+and Sale Agreement dated November 1, 2006, among Henry Petroleum LP, Henry
+Holding LP, Henry Group, Entre Energy Partners LP, and St. Mary Land &
+Exploration Company (filed as Exhibit 2.1 to the registrant’s Current
+Report on Form 8-K filed on December 18, 2006, and incorporated herein by
+reference) 
+2.2 
+Purchase
+and Sale Agreement dated August 2, 2007, among Rockford Energy Partners
+II, LLC and St. Mary Land & Exploration Company (filed as Exhibit 2.1
+to the registrant’s Current Report on Form 8-K filed on October 5, 2007,
+and incorporated herein by reference) 
+2.3 
+Purchase
+and Sale Agreement dated December 11, 2007, among St. Mary Land &
+Exploration Company, Ralph H. Smith Restated Revocable Trust Dated
+8/14/97, Ralph H. Smith Trustee, Kent. J. Harrell, Trustee of the Kent J.
+Harrell Revocable Trust Dated January 19, 1995, and Abraxas Operating LLC
+(filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed
+on February 1, 2008, and incorporated herein by
+reference) 
+2.4 
+Ratification
+and Joinder Agreement dated January 31, 2008, among St. Mary Land &
+Exploration Company, Ralph H. Smith, Kent J. Harrell, Abraxas Operating,
+LLC and Abraxas Petroleum Corporation (filed as Exhibit 2.2 to the
+registrant’s Current Report on Form 8-K filed on February 1, 2008, and
+incorporated herein by reference) 
+2.5* 
+Purchase
+and Sale Agreement dated December 17, 2009 and effective as of November 1,
+2009, between Legacy Reserves Operating LP and St. Mary Land and
+Exploration Company 
+2.6* 
+Purchase
+and Sale Agreement dated January 7, 2010 and effective as of November 1,
+2009, between Sequel Energy Partners LP, Bakken Energy Partners, LLC,
+Three Forks Energy Partners, LLC and St. Mary Land and Exploration
+Company 
+89 
+Exhibit 
+Number 
+Description 
+3.1 
+Restated
+Certificate of Incorporation of St. Mary Land & Exploration Company as
+amended on May 25, 2005 (filed as Exhibit 3.1 to the registrant’s
+Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and
+incorporated herein by reference) 
+3.2 
+Restated
+By-Laws of St. Mary Land & Exploration Company amended as of December
+18, 2008 (filed as Exhibit 3.1 to the registrant’s Current Report on Form
+8-K filed on December 23, 2008, and incorporated herein by
+reference) 
+4.1 
+Shareholder
+Rights Plan adopted on July 15, 1999 (filed as Exhibit 4.1 to the
+registrant’s Quarterly Report on Form 10-Q/A for the quarter ended June
+30, 1999 and incorporated herein by reference) 
+4.2 
+First
+Amendment to Shareholders Rights Plan dated March 15, 2002 as adopted by
+the Board of Directors on July 19, 2001 (filed as Exhibit 4.2 to the
+registrant’s Annual Report on Form 10-K for the year ended December 31,
+2001 and incorporated herein by reference) 
+4.3 
+Second
+Amendment to Shareholder Rights Plan dated April 24, 2006 (filed as
+Exhibit 4.1 to the registrant’s Quarterly Report on Form 10-Q for the
+quarter ended March 31, 2006 and incorporated herein by
+reference) 
+4.4 
+Indenture
+related to the 3.50% Senior Convertible Notes due 2027, dated as of April
+4, 2007, between St. Mary Land & Exploration Company and Wells Fargo
+Bank, National Association, as trustee (including the form of 3.50% Senior
+Convertible Note due 2027) (filed as Exhibit 4.1 to the registrant’s
+Current Report on Form 8-K filed on April 4, 2007, and incorporated herein
+by reference) 
+4.5 
+Registration
+Rights Agreement, dated as of April 4, 2007, among St. Mary Land &
+Exploration Company and Merrill Lynch, Pierce, Fenner & Smith
+Incorporated and Wachovia Capital Markets, LLC, for themselves and as
+representatives of the Initial Purchasers (filed Exhibit 4.2 to the
+registrant’s Current Report on Form 8-K filed on April 4, 2007, and
+incorporated herein by reference) 
+10.1† 
+Stock
+Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the
+registrant’s Registration Statement on Form S-8 (Registration No.
+333-106438) and incorporated herein by reference) 
+10.2† 
+Incentive
+Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.2 to
+the registrant’s Registration Statement on Form S-8 (Registration No.
+333-106438) and incorporated herein by reference) 
+10.3† 
+Cash
+Bonus Plan (filed as Exhibit 10.7 to the registrant’s Registration
+Statement on Form S-1 (Registration No. 333-53512) and incorporated herein
+by reference) 
+10.4† 
+Summary
+Plan Description/Pension Plan dated December 30, 1994 (filed as Exhibit
+10.35 to the registrant’s Annual Report on Form 10-K for the year ended
+December 31, 1994 and incorporated herein by reference) 
+10.5† 
+Non-qualified
+Unfunded Supplemental Retirement Plan, as amended (filed as Exhibit 10.10
+to the registrant’s Registration Statement on Form S-1 (Registration No.
+333-53512) and incorporated herein by reference) 
+10.6† 
+Employee
+Stock Purchase Plan (filed as Exhibit 10.50 for the registrant’s Annual
+Report on Form 10-K for the year ended December 31, 1997 and incorporated
+herein by reference) 
+10.7† 
+First
+Amendment to Employee Stock Purchase Plan dated February 27, 2001 (filed
+as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the
+quarter ended June 30, 2001 and incorporated herein by
+reference) 
+10.8† 
+Second
+Amendment to the Employee Stock Purchase Plan dated February 18, 2005
+(filed as Exhibit 10.48 to the registrant’s Annual Report on Form 10-K for
+the year ended December 31, 2004 and incorporated herein by
+reference) 
+10.9† 
+Form
+of Change of Control Severance Agreements (filed as Exhibit 10.1 to the
+registrant’s Quarterly Report on Form 10-Q for the quarter ended September
+30, 2001 and incorporated herein by
+reference) 
+90 
+Exhibit 
+Number 
+Description 
+10.10† 
+Amendment
+to Form of Change of Control Severance Agreement (filed as Exhibit 10.9 to
+the registrant’s Quarterly Report on Form 10-Q for the quarter ended June
+30, 2005 and incorporated herein by reference) 
+10.11 
+Amendment
+to an Extension of Office Lease dated as of December 14, 2001 (filed as
+Exhibit 10.45 to the registrant’s Annual Report on Form 10-K for the year
+ended December 31, 2002 and incorporated herein by
+reference) 
+10.12† 
+Non-Employee
+Director Stock Compensation Plan as adopted on March 27, 2003 (filed as
+Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the
+quarter ended June 30, 2003 and incorporated herein by
+reference) 
+10.13† 
+Restricted
+Stock Plan as adopted on April 18, 2004 (filed as Exhibit 10.1 to the
+registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
+2004 and incorporated herein by reference) 
+10.14† 
+Amendment
+to Restricted Stock Plan, dated December 15, 2005 (filed as Exhibit 10.2
+to the registrant’s Current Report on Form 8-K filed on December 19, 2005
+and incorporated herein by reference) 
+10.15† 
+Form
+of Restricted Stock Unit Award Agreement under the Restricted Stock Plan
+(filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K
+filed on March 15, 2005 and incorporated herein by
+reference) 
+10.16 
+Amended
+and Restated Credit Agreement dated as of April 7, 2005 among St. Mary
+Land & Exploration Company, Wachovia Bank, National Association, as
+Administrative Agent, and the lenders party thereto (filed as Exhibit 10.1
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+March 31, 2005 and incorporated herein by reference) 
+10.17† 
+2006
+Equity Incentive Compensation Plan (filed on May 17, 2006 as Exhibit 99.1
+to the registrant’s Registration Statement on Form S-8 (Registration No.
+333-134221) and incorporated herein by reference) 
+10.18† 
+Form
+of Non-Employee Director Restricted Stock Award Agreement (filed as
+Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on May
+18, 2006 and incorporated herein by reference) 
+10.19 
+Guaranty
+Agreement by St. Mary Energy Company in favor of Wachovia Bank, National
+Association, as Administrative Agent, dated April 7, 2005 (filed as
+Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the
+quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.20 
+Guaranty
+Agreement by Nance Petroleum Corporation in favor or Wachovia Bank,
+National Association, as Administrative Agent, dated April 7, 2005 (filed
+as Exhibit 10.3 to the registrant’s quarterly Report on Form 10-Q for the
+quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.21 
+Guaranty
+Agreement by NPC Inc. in favor of Wachovia Bank, National Association, as
+Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.4 to the
+registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31,
+2005 and incorporated herein by reference) 
+10.22 
+Pledge
+and Security Agreement between St. Mary Land & Exploration Company and
+Wachovia Bank, National Association, as Administrative Agent, dated April
+7, 2005 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on
+Form 10-Q for the quarter ended March 31, 2005 and incorporated herein by
+reference.) 
+10.23 
+Pledge
+and Security Agreement between Nance Petroleum Corporation and Wachovia
+Bank, National Association, as Administrative Agent, dated April 7, 2005
+(filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q
+for the quarter ended March 31, 2005 and incorporated herein by
+reference.) 
+91 
+Exhibit 
+Number 
+Description 
+10.24 
+First
+Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit,
+Assignment, Security Agreement, Fixture Filing and Financing Statement for
+the Benefit of Wachovia Bank, National Association, as Administrative
+Agent, dated effective as of April 7, 2005 (filed as Exhibit 10.7 to the
+registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31,
+2005 and incorporated herein by reference) 
+10.25 
+Deed
+of Trust – St. Mary Land & Exploration Company to Wachovia Bank,
+National Association, as Administrative Agent, dated effective as of April
+7, 2005 (filed as Exhibit 10.8 to the registrant’s Quarterly Report on
+Form 10-Q for the quarter ended March 31, 2005 and incorporated herein by
+reference) 
+10.26† 
+Net
+Profits Interest Bonus Plan, as Amended on December 15, 2005 (filed as
+Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on
+December 19, 2005 and incorporated herein by reference) 
+10.27† 
+Summary
+of Charitable Contributions in Honor of Thomas E. Congdon (filed as
+Exhibit 10.4 to the registrant’s Current Report on Form 8-K filed on
+December 19, 2005 and incorporated herein by reference) 
+10.28† 
+Summary
+of 2006 Base Salaries for Named Executive Officers (filed as Exhibit 10.5
+to the registrant’s Current Report on Form 8-K filed on December 19, 2005
+and incorporated herein by reference) 
+10.29† 
+Employment
+Agreement of A.J. Best dated May 1, 2006 (filed as Exhibit 10.1 to the
+registrant’s Current Report on Form 8-K filed on May 4, 2006 and
+incorporated herein by reference) 
+10.30*† 
+Summary
+of Compensation Arrangements for Non-Employee Directors 
+10.31 
+Purchase
+Agreement, dated March 29, 2007, among St. Mary Land & Exploration
+Company, Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner &
+Smith Incorporated, Wachovia Capital Markets, LLC, Bear Stearns & Co.
+Inc., BNP Paribas Securities Corp., and UBS Securities LLC (filed as
+Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on April
+4, 2007, and incorporated herein by reference) 
+10.32 
+First
+Amendment to Amended and Restated Credit Agreement, dated March 19, 2007,
+among St. Mary Land & Exploration Company, the lenders party thereto,
+Wachovia Bank, National Association, as issuing bank and administrative
+agent, Wells Fargo Bank, N.A., as syndication agent, and BNP Paribas,
+Comerica Bank-Texas and JPMorgan Chase Bank, N.A., as co-documentation
+agents (filed as Exhibit 10.2 to the registrant’s Current Report on Form
+8-K filed on April 4, 2007, and incorporated herein by
+reference) 
+10.33† 
+Net
+Profits Interest Bonus Plan, As Amended and Restated by the Board of
+Directors on July 19, 2007 (filed as Exhibit 10.1 to the registrant’s
+Current Report on Form 8-K filed on July 25, 2007, and incorporated herein
+by reference) 
+10.34† 
+Cash
+Bonus Plan as Amended on March 28, 2008 (filed as Exhibit 10.1 to the
+registrant’s Current Report on Form 8-K filed on April 3, 2008 and
+incorporated herein by reference) 
+10.35 
+Second
+Amended and Restated Credit Agreement dated April 10, 2008, among St. Mary
+Land & Exploration Company, the lenders party thereto, Wachovia Bank,
+National Association, as Administrative Agent, Wells Fargo Bank, N.A., as
+syndication agent, and BNP Paribas, Comerica Bank and JPMorgan Chase Bank,
+N.A., as co-documentation agents (filed as Exhibit 10.1 to the
+registrant’s Quarterly Report on Form 10-Q filed on May 5, 2008 and
+incorporated herein by reference) 
+10.36† 
+2006
+Equity Incentive Compensation Plan as Amended and Restated as of March 28,
+2008 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K
+filed on May 27, 2008 and incorporated herein by
+reference) 
+10.37† 
+Form
+of Performance Share Award Agreement (filed as Exhibit 10.4 to the
+registrant’s Quarterly Report on Form 10-Q filed on August 5, 2008 and
+incorporated herein by reference) 
+10.38† 
+Form
+of Performance Share Award Notice (filed as Exhibit 10.5 to the
+registrant’s Quarterly Report on Form 10-Q filed on August 5, 2008 and
+incorporated herein by reference) 
+92 
+Exhibit 
+Number 
+Description 
+10.39 
+Third
+Amended and Restated Credit Agreement dated April 14, 2009 among St. Mary
+Land & Exploration Company, Wachovia Bank, National Association, as
+Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1
+to the registrant’s Current Report on Form 8-K filed on April 20, 2009,
+and incorporated herein by reference) 
+10.40 
+Supplement
+and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage,
+Assignment, Security Agreement, Fixture Filing and Financing Statement for
+the benefit of Wachovia Bank, National Association, as Administrative
+Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.2 to the
+registrant’s Current Report on Form 8-K filed on April 20, 2009, and
+incorporated herein by reference) 
+10.41 
+Deed
+of Trust to Wachovia Bank, National Association, as Administrative Agent,
+dated effective as of April 14, 2009 (filed as Exhibit 10.3 to the
+registrant’s Current Report on Form 8-K filed on April 20, 2009, and
+incorporated herein by reference) 
+10.42† 
+Equity
+Incentive Compensation Plan as Amended and Restated as of March 26, 2009
+(filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K
+filed on May 27, 2009) 
+10.43† 
+St.
+Mary Land & Exploration Company Form of Performance Share and
+Restricted Stock Unit Award Agreement (filed as Exhibit 10.5 to the
+registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
+2009, and incorporated herein by reference) 
+10.44† 
+St.
+Mary Land & Exploration Company Form of Performance Share and
+Restricted Stock Unit Award Notice (filed as Exhibit 10.6 to the
+registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
+2009, and incorporated herein by reference) 
+10.45† 
+Third
+Amendment to St. Mary Land & Exploration Company Employee Stock
+Purchase Plan dated September 23, 2009 (filed as Exhibit 10.3 to the
+registrant’s Quarterly Report on Form 10-Q for the quarter ended September
+30, 2009, and incorporated herein by reference) 
+10.46*† 
+Fourth
+Amendment to St. Mary Land & Exploration Company Employee Stock
+Purchase Plan dated December 29, 2009 
+21.1* 
+Subsidiaries
+of Registrant 
+23.1* 
+Consent
+of Deloitte & Touche LLP 
+23.2* 
+Consent
+of Ryder Scott Company L.P. 
+23.3* 
+Consent
+of Netherland, Sewell & Associates, Inc. 
+24.1* 
+Power
+of Attorney 
+31.1* 
+Certification
+of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley
+Act of 2002 
+31.2* 
+Certification
+of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley
+Act of 2002 
+32.1** 
+Certification
+pursuant to U.S.C. Section 1350 as adopted pursuant to Section 906 of the
+Sarbanes- Oxley Act of 2002 
+99.1* 
+Ryder
+Scott Audit Letter 
+* Filed
+with this Form 10-K 
+** 
+Furnished with this Form 10-K 
+† Exhibit
+constitutes a management contract or compensatory plan or
+agreement. 
+(c) Financial Statement
+Schedules. See Item 15(a) above. 
+93 
+REPORT OF
+INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the
+Board of Directors and Stockholders of 
+St. Mary
+Land & Exploration Company and Subsidiaries 
+Denver,
+Colorado 
+We have
+audited the accompanying consolidated balance sheets of St. Mary Land &
+Exploration Company and subsidiaries (the “Company”) as of December 31, 2009 and
+2008, and the related consolidated statements of operations, stockholders’
+equity and comprehensive income (loss), and cash flows for each of the three
+years in the period ended December 31, 2009. These financial
+statements are the responsibility of the Company’s management. Our
+responsibility is to express an opinion on the financial statements based on our
+audits. 
+We
+conducted our audits in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). Those standards require
+that we plan and perform the audit to obtain reasonable assurance about whether
+the financial statements are free of material misstatement. An audit
+includes examining, on a test basis, evidence supporting the amounts and
+disclosures in the financial statements. An audit also includes
+assessing the accounting principles used and significant estimates made by
+management, as well as evaluating the overall financial statement
+presentation. We believe that our audits provide a reasonable basis
+for our opinion. 
+In our
+opinion, such consolidated financial statements present fairly, in all material
+respects, the financial position of St. Mary Land & Exploration Company and
+subsidiaries as of December 31, 2009 and 2008, and the results of their
+operations and their cash flows for each of the three years in the period ended
+December 31, 2009, in conformity with accounting principles generally accepted
+in the United States of America. 
+As
+discussed in Note 1 to the consolidated financial statements, the Company
+changed its method of oil and gas reserve estimation and related required
+disclosures in 2009 with the implementation of new accounting
+guidance. 
+As
+discussed in Note 5 to the consolidated financial statements, the Company
+changed its method of accounting for convertible debt in 2009 . 
+We have
+also audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), the Company’s internal control over financial
+reporting as of December 31, 2009, based on the criteria established in Internal Control – Integrated
+Framework issued by the Committee of Sponsoring Organizations of the
+Treadway Commission, and our report dated February 23, 2010, expressed an
+unqualified opinion on the Company’s internal control over financial
+reporting. 
+/s/
+DELOITTE & TOUCHE LLP 
+Denver,
+Colorado 
+February
+23, 2010 
+F-1 
+PART
+II. FINANCIAL INFORMATION 
+ITEM
+8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+ST.
+MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+CONSOLIDATED
+BALANCE SHEETS 
+(In
+thousands, except share amounts) 
+December
+31, 
+2009 
+2008 
+ASSETS 
+(As
+adjusted, Note 5) 
+Current
+assets: 
+Cash
+and cash equivalents 
+$ 
+10,649 
+$ 
+6,131 
+Short-term
+investments 
+- 
+1,002 
+Accounts
+receivable, net of allowance for doubtful accounts 
+of
+$- in 2009 and $16,788 in 2008 
+116,136 
+157,690 
+Refundable
+income taxes 
+32,773 
+13,161 
+Prepaid
+expenses and other 
+14,259 
+22,161 
+Derivative
+asset 
+30,295 
+111,649 
+Deferred
+income taxes 
+4,934 
+- 
+Total
+current assets 
+209,046 
+311,794 
+Property
+and equipment (successful efforts method), at cost: 
+Land 
+1,371 
+1,350 
+Proved
+oil and gas properties 
+2,797,341 
+2,969,722 
+Less
+- accumulated depletion, depreciation, and amortization 
+(1,053,518 
+) 
+(947,207 
+) 
+Unproved
+oil and gas properties, net of impairment allowance 
+of
+$66,570 in 2009 and $42,945 in 2008 
+132,370 
+168,817 
+Wells
+in progress 
+65,771 
+90,910 
+Materials
+inventory, at lower of cost or market 
+24,467 
+40,455 
+Oil
+and gas properties held for sale less accumulated
+depletion, 
+depreciation,
+and amortization 
+145,392 
+1,827 
+Other
+property and equipment, net of accumulated depreciation 
+of
+$14,550 in 2009 and $13,848 in 2008 
+14,404 
+13,458 
+2,127,598 
+2,339,332 
+Other
+noncurrent assets: 
+Derivative
+asset 
+8,251 
+21,541 
+Restricted
+cash subject to Section 1031 Exchange 
+- 
+14,398 
+Other
+noncurrent assets 
+16,041 
+10,182 
+Total
+other noncurrent assets 
+24,292 
+46,121 
+Total
+Assets 
+$ 
+2,360,936 
+$ 
+2,697,247 
+LIABILITIES
+AND STOCKHOLDERS' EQUITY 
+Current
+liabilities: 
+Accounts
+payable and accrued expenses 
+$ 
+236,242 
+$ 
+254,811 
+Derivative
+liability 
+53,929 
+501 
+Deposit
+associated with oil and gas properties held for sale 
+6,500 
+- 
+Deferred
+income taxes 
+- 
+41,289 
+Total
+current liabilities 
+296,671 
+296,601 
+Noncurrent
+liabilities: 
+Long-term
+credit facility 
+188,000 
+300,000 
+Senior
+convertible notes, net of unamortized 
+discount
+of $20,598 in 2009, and $28,787 in 2008 
+266,902 
+258,713 
+Asset
+retirement obligation 
+60,289 
+108,755 
+Asset
+retirement obligation associated with oil and gas properties held for
+sale 
+18,126 
+238 
+Net
+Profits Plan liability 
+170,291 
+177,366 
+Deferred
+income taxes 
+308,189 
+354,328 
+Derivative
+liability 
+65,499 
+27,419 
+Other
+noncurrent liabilities 
+13,399 
+11,318 
+Total
+noncurrent liabilities 
+1,090,695 
+1,238,137 
+Commitments
+and contingencies 
+Stockholders'
+equity: 
+Common
+stock, $0.01 par value: authorized - 200,000,000
+shares; 
+issued: 62,899,122
+shares in 2009 and 62,465,572 shares in 2008; 
+outstanding,
+net of treasury shares: 62,772,229 shares in 2009 
+and
+62,288,585 shares in 2008 
+629 
+625 
+Additional
+paid-in capital 
+160,516 
+141,283 
+Treasury
+stock, at cost: 126,893 shares in 2009 and 176,987 shares in
+2008 
+(1,204 
+) 
+(1,892 
+) 
+Retained
+earnings 
+851,583 
+957,200 
+Accumulated
+other comprehensive income (loss) 
+(37,954 
+) 
+65,293 
+Total
+stockholders' equity 
+973,570 
+1,162,509 
+Total
+Liabilities and Stockholders' Equity 
+$ 
+2,360,936 
+$ 
+2,697,247 
+The accompanying notes are an integral part of
+these consolidated financial statements. 
+F-2 
+ST.
+MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF OPERATIONS 
+(In
+thousands, except per share amounts) 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(As
+adjusted, Note 5) 
+Operating
+revenues and other income: 
+Oil
+and gas production revenue 
+$ 
+615,953 
+$ 
+1,259,400 
+$ 
+912,093 
+Realized
+oil and gas hedge gain (loss) 
+140,648 
+(101,096 
+) 
+24,484 
+Marketed
+gas system revenue 
+58,459 
+77,350 
+45,149 
+Gain
+(loss) on divestiture activity (Note 3) 
+11,444 
+63,557 
+(367 
+) 
+Other
+revenue 
+5,697 
+2,090 
+8,735 
+Total
+operating revenues and other income 
+832,201 
+1,301,301 
+990,094 
+Operating
+expenses: 
+Oil
+and gas production expense 
+206,800 
+271,355 
+218,208 
+Depletion,
+depreciation, amortization, 
+and
+asset retirement obligation liability accretion 
+304,201 
+314,330 
+227,596 
+Exploration 
+62,235 
+60,121 
+58,686 
+Impairment
+of proved properties 
+174,813 
+302,230 
+- 
+Abandonment
+and impairment of unproved properties 
+45,447 
+39,049 
+4,756 
+Impairment
+of materials inventory 
+14,223 
+- 
+- 
+Impairment
+of goodwill 
+- 
+9,452 
+- 
+General
+and administrative 
+76,036 
+79,503 
+60,149 
+Bad
+debt expense (recovery) 
+(5,189 
+) 
+16,735 
+- 
+Change
+in Net Profits Plan liability 
+(7,075 
+) 
+(34,040 
+) 
+50,823 
+Marketed
+gas system expense 
+57,587 
+72,159 
+42,485 
+Unrealized
+derivative (gain) loss 
+20,469 
+(11,209 
+) 
+5,458 
+Other
+expense 
+13,489 
+10,415 
+2,522 
+Total
+operating expenses 
+963,036 
+1,130,100 
+670,683 
+Income
+(loss) from operations 
+(130,835 
+) 
+171,201 
+319,411 
+Nonoperating
+income (expense): 
+Interest
+income 
+227 
+485 
+746 
+Interest
+expense 
+(28,856 
+) 
+(26,950 
+) 
+(24,046 
+) 
+Income
+(loss) before income taxes 
+(159,464 
+) 
+144,736 
+296,111 
+Income
+tax benefit (expense) 
+60,094 
+(57,388 
+) 
+(109,013 
+) 
+Net
+income (loss) 
+$ 
+(99,370 
+) 
+$ 
+87,348 
+$ 
+187,098 
+Basic
+weighted-average common shares outstanding 
+62,457 
+62,243 
+61,852 
+Diluted
+weighted-average common shares outstanding 
+62,457 
+63,133 
+64,850 
+Basic
+net income (loss) per common share 
+$ 
+(1.59 
+) 
+$ 
+1.40 
+$ 
+3.02 
+Diluted
+net income (loss) per common share 
+$ 
+(1.59 
+) 
+$ 
+1.38 
+$ 
+2.90 
+The accompanying notes are an integral part of
+these consolidated financial statements. 
+F-3 
+ST.
+MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
+(LOSS) 
+(In
+thousands, except share amounts) 
+Accumulated 
+Additional 
+Other 
+Total 
+Common
+Stock 
+Paid-in 
+Treasury
+Stock 
+Retained 
+Comprehensive 
+Stockholders' 
+Shares 
+Amount 
+Capital 
+Shares 
+Amount 
+Earnings 
+Income
+(Loss) 
+Equity 
+Balances,
+December 31, 2006 
+55,251,733 
+$ 
+553 
+$ 
+38,940 
+(250,000 
+) 
+$ 
+(4,272 
+) 
+$ 
+695,224 
+$ 
+12,929 
+$ 
+743,374 
+Comprehensive
+income, net of tax: 
+Net
+income (As adjusted, Note 5) 
+- 
+- 
+- 
+- 
+- 
+187,098 
+- 
+187,098 
+Change
+in derivative instrument fair value 
+- 
+- 
+- 
+- 
+- 
+- 
+(154,497 
+) 
+(154,497 
+) 
+Reclassification
+to earnings 
+- 
+- 
+- 
+- 
+- 
+- 
+(15,470 
+) 
+(15,470 
+) 
+Minimum
+pension liability adjustment 
+- 
+- 
+- 
+- 
+- 
+- 
+70 
+70 
+Total
+comprehensive income 
+17,201 
+Cash
+dividends, $ 0.10 per share 
+- 
+- 
+- 
+- 
+- 
+(6,284 
+) 
+- 
+(6,284 
+) 
+Treasury
+stock purchases 
+- 
+- 
+- 
+(792,216 
+) 
+(25,957 
+) 
+- 
+- 
+(25,957 
+) 
+Issuance
+of common stock under Employee 
+Stock
+Purchase Plan 
+29,534 
+- 
+919 
+- 
+- 
+- 
+- 
+919 
+Conversion
+of 5.75% Senior Convertible Notes 
+due
+2022 to common stock, including income 
+tax
+benefit of conversion 
+7,692,295 
+77 
+106,854 
+- 
+- 
+- 
+- 
+106,931 
+Issuance
+of common stock upon settlement of 
+RSUs
+following expiration of restriction period, 
+net
+of shares used for tax withholdings 
+302,370 
+3 
+(4,569 
+) 
+- 
+- 
+- 
+- 
+(4,566 
+) 
+Sale
+of common stock, including income 
+tax
+benefit of stock option exercises 
+733,650 
+7 
+19,011 
+- 
+- 
+- 
+- 
+19,018 
+3.50%
+Senior Convertible Notes conversion feature 
+- 
+- 
+41,843 
+- 
+- 
+- 
+- 
+41,843 
+Stock-based
+compensation expense 
+1,250 
+- 
+8,915 
+32,504 
+1,180 
+- 
+- 
+10,095 
+Balances,
+December 31, 2007 (As adjusted, Note 5) 
+64,010,832 
+$ 
+640 
+$ 
+211,913 
+(1,009,712 
+) 
+$ 
+(29,049 
+) 
+$ 
+876,038 
+$ 
+(156,968 
+) 
+$ 
+902,574 
+Comprehensive
+income, net of tax: 
+Net
+income (As adjusted, Note 5) 
+- 
+- 
+- 
+- 
+- 
+87,348 
+- 
+87,348 
+Change
+in derivative instrument fair value 
+- 
+- 
+- 
+- 
+- 
+- 
+177,005 
+177,005 
+Reclassification
+to earnings 
+- 
+- 
+- 
+- 
+- 
+- 
+46,463 
+46,463 
+Minimum
+pension liability adjustment 
+- 
+- 
+- 
+- 
+- 
+- 
+(1,207 
+) 
+(1,207 
+) 
+Total
+comprehensive income 
+309,609 
+Cash
+dividends, $ 0.10 per share 
+- 
+- 
+- 
+- 
+- 
+(6,186 
+) 
+- 
+(6,186 
+) 
+Treasury
+stock purchases 
+- 
+- 
+- 
+(2,135,600 
+) 
+(77,150 
+) 
+- 
+- 
+(77,150 
+) 
+Retirement
+of treasury stock 
+(2,945,212 
+) 
+(29 
+) 
+(103,237 
+) 
+2,945,212 
+103,266 
+- 
+- 
+- 
+Issuance
+of common stock under Employee 
+Stock
+Purchase Plan 
+45,228 
+- 
+1,055 
+- 
+- 
+- 
+- 
+1,055 
+Issuance
+of common stock upon settlement of 
+RSUs
+following expiration of restriction period, 
+net
+of shares used for tax withholdings 
+482,602 
+5 
+(6,910 
+) 
+- 
+- 
+- 
+- 
+(6,905 
+) 
+Sale
+of common stock, including income 
+tax
+benefit of stock option exercises 
+868,372 
+9 
+24,691 
+- 
+- 
+- 
+- 
+24,700 
+Stock-based
+compensation expense 
+3,750 
+- 
+13,771 
+23,113 
+1,041 
+- 
+- 
+14,812 
+Balances,
+December 31, 2008 (As adjusted, Note 5) 
+62,465,572 
+$ 
+625 
+$ 
+141,283 
+(176,987 
+) 
+$ 
+(1,892 
+) 
+$ 
+957,200 
+$ 
+65,293 
+$ 
+1,162,509 
+Comprehensive
+loss, net of tax: 
+Net
+loss 
+- 
+- 
+- 
+- 
+- 
+(99,370 
+) 
+- 
+(99,370 
+) 
+Change
+in derivative instrument fair value 
+- 
+- 
+- 
+- 
+- 
+- 
+(35,977 
+) 
+(35,977 
+) 
+Reclassification
+to earnings 
+- 
+- 
+- 
+- 
+- 
+- 
+(67,344 
+) 
+(67,344 
+) 
+Minimum
+pension liability adjustment 
+- 
+- 
+- 
+- 
+- 
+- 
+74 
+74 
+Total
+comprehensive loss 
+(202,617 
+) 
+Cash
+dividends, $ 0.10 per share 
+- 
+- 
+- 
+- 
+- 
+(6,247 
+) 
+- 
+(6,247 
+) 
+Issuance
+of common stock under Employee 
+Stock
+Purchase Plan 
+86,308 
+1 
+1,515 
+- 
+- 
+- 
+- 
+1,516 
+Issuance
+of common stock upon settlement of 
+RSUs
+following expiration of restriction period, 
+net
+of shares used for tax withholdings, 
+including
+income tax cost of RSUs 
+156,252 
+1 
+(1,951 
+) 
+- 
+- 
+- 
+- 
+(1,950 
+) 
+Sale
+of common stock, including income 
+tax
+benefit of stock option exercises 
+189,740 
+2 
+1,592 
+- 
+- 
+- 
+- 
+1,594 
+Stock-based
+compensation expense 
+1,250 
+- 
+18,077 
+50,094 
+688 
+- 
+- 
+18,765 
+Balances,
+December 31, 2009 
+62,899,122 
+$ 
+629 
+$ 
+160,516 
+(126,893 
+) 
+$ 
+(1,204 
+) 
+$ 
+851,583 
+$ 
+(37,954 
+) 
+$ 
+973,570 
+The accompanying notes are an integral part of
+these consolidated financial statements. 
+F-4 
+ST.
+MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF CASH FLOWS 
+(In
+thousands) 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(As
+adjusted, Note 5) 
+Cash
+flows from operating activities: 
+Net
+income (loss) 
+$ 
+(99,370 
+) 
+$ 
+87,348 
+$ 
+187,098 
+Adjustments
+to reconcile net income (loss) to net cash 
+provided
+by operating activities: 
+(Gain)
+loss on divestiture activities 
+(11,444 
+) 
+(63,557 
+) 
+367 
+Depletion,
+depreciation, amortization, 
+and
+asset retirement obligation liability accretion 
+304,201 
+314,330 
+227,596 
+Exploratory
+dry hole expense 
+7,810 
+6,823 
+14,365 
+Impairment
+of proved properties 
+174,813 
+302,230 
+- 
+Abandonment
+and impairment of unproved properties 
+45,447 
+39,049 
+4,756 
+Impairment
+of materials inventory 
+14,223 
+- 
+- 
+Impairment
+of goodwill 
+- 
+9,452 
+- 
+Stock-based
+compensation expense* 
+18,765 
+14,812 
+10,095 
+Bad
+debt expense (recovery) 
+(5,189 
+) 
+16,735 
+- 
+Change
+in Net Profits Plan liability 
+(7,075 
+) 
+(34,040 
+) 
+50,823 
+Unrealized
+derivative (gain) loss 
+20,469 
+(11,209 
+) 
+5,458 
+Loss
+related to hurricanes 
+8,301 
+6,980 
+- 
+(Gain)
+loss on insurance settlement 
+- 
+2,296 
+(5,243 
+) 
+Amortization
+of debt discount and deferred financing costs 
+12,213 
+9,344 
+5,413 
+Deferred
+income taxes 
+(39,735 
+) 
+38,164 
+91,418 
+Plugging
+and abandonment 
+(26,396 
+) 
+(9,168 
+) 
+(12,393 
+) 
+Other 
+3,382 
+3,875 
+1,896 
+Changes
+in current assets and liabilities: 
+Accounts
+receivable 
+46,743 
+(14,327 
+) 
+(6,557 
+) 
+Refundable
+income taxes 
+(19,612 
+) 
+(12,228 
+) 
+6,751 
+Prepaid
+expenses and other 
+(6,626 
+) 
+(1,504 
+) 
+19,375 
+Accounts
+payable and accrued expenses 
+(4,814 
+) 
+(12,348 
+) 
+40,769 
+Excess
+income tax benefit associated with stock awards 
+- 
+(13,867 
+) 
+(9,933 
+) 
+Net
+cash provided by operating activities 
+436,106 
+679,190 
+632,054 
+Cash
+flows from investing activities: 
+Proceeds
+from insurance settlement 
+16,789 
+- 
+5,948 
+Proceeds
+from sale of oil and gas properties 
+39,898 
+178,867 
+495 
+Capital
+expenditures 
+(379,253 
+) 
+(746,586 
+) 
+(639,010 
+) 
+Acquisition
+of oil and gas properties 
+(76 
+) 
+(81,823 
+) 
+(182,883 
+) 
+Receipts
+from restricted cash 
+14,398 
+- 
+- 
+Deposits
+to restricted cash 
+- 
+(14,398 
+) 
+- 
+Receipts
+from short-term investments 
+1,002 
+170 
+1,450 
+Deposits
+to short-term investments 
+- 
+- 
+(1,168 
+) 
+Other 
+3,150 
+(9,984 
+) 
+10,034 
+Net
+cash used in investing activities 
+(304,092 
+) 
+(673,754 
+) 
+(805,134 
+) 
+Cash
+flows from financing activities: 
+Proceeds
+from credit facility 
+2,072,500 
+2,571,500 
+822,000 
+Repayment
+of credit facility 
+(2,184,500 
+) 
+(2,556,500 
+) 
+(871,000 
+) 
+Repayment
+of short-term note payable 
+- 
+- 
+(4,469 
+) 
+Debt
+issuance costs related to credit facility 
+(11,074 
+) 
+- 
+- 
+Excess
+income tax benefit associated with stock awards 
+- 
+13,867 
+9,933 
+Proceeds
+from issuance of senior convertible debt, net of 
+deferred
+financing cost 
+- 
+- 
+280,657 
+Proceeds
+from sale of common stock 
+3,110 
+11,888 
+10,007 
+Repurchase
+of common stock 
+- 
+(77,202 
+) 
+(25,904 
+) 
+Dividends
+paid 
+(6,247 
+) 
+(6,186 
+) 
+(6,284 
+) 
+Other 
+(1,285 
+) 
+(182 
+) 
+186 
+Net
+cash (used in) provided by financing activities 
+(127,496 
+) 
+(42,815 
+) 
+215,126 
+Net
+change in cash and cash equivalents 
+4,518 
+(37,379 
+) 
+42,046 
+Cash
+and cash equivalents at beginning of period 
+6,131 
+43,510 
+1,464 
+Cash
+and cash equivalents at end of period 
+$ 
+10,649 
+$ 
+6,131 
+$ 
+43,510 
+*
+Stock-based compensation expense is a component of exploration expense and
+general and administrative expense on 
+the
+consolidated statements of operations. For the years ended December
+31, 2009, 2008, and 2007, respectively, 
+$6.3
+million, $5.8 million, and $3.2 million of stock-based compensation
+expense was included in exploration expense. 
+For
+the years ended December 31, 2009, 2008, and 2007, respectively, $12.5
+million, $9.0 million, and $6.9 million of 
+stock-based
+compensation expense was included in general and administrative
+expense. 
+The accompanying notes are an integral part of
+these consolidated financial statements. 
+F-5 
+ST.
+MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+CONSOLIDATED
+STATEMENTS OF CASH FLOWS (Continued) 
+Supplemental
+schedule of additional cash flow information and noncash investing and
+financing activities: 
+For
+the Years Ended December 31 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Cash
+paid for interest 
+$ 
+17,884 
+$ 
+21,976 
+$ 
+22,816 
+Cash
+paid (refunded) for income taxes 
+$ 
+(9,857 
+) 
+$ 
+17,326 
+$ 
+(1,156 
+) 
+In
+August 2009 and 2008, the Company granted 725,092 and 465,751 Performance
+Share Awards to 
+employees
+as equity-based compensation pursuant to the Company's Equity Incentive
+Compensation 
+Plan. The
+total fair value of the issuances equaled $25.8 million and $12.3 million,
+respectively. 
+The
+Company did not grant any Performance Share Awards in
+2007. 
+As
+of December 31, 2009, 2008, and 2007, the Company issued
+241,745, 428,407, and 102,634 
+restricted
+stock units, respectively, to employees as equity-based compensation,
+pursuant to the 
+Company's
+Equity Incentive Compensation Plan. The total fair value of the
+issuances was $5.8 million, $23.4 
+million,
+and $3.3 million, respectively. 
+As
+of December 31, 2009, 2008, and 2007, $109.0 million, $116.5 million, and
+$116.9 million, 
+respectively,
+are included as additions to oil and gas properties and accounts payable
+and accrued 
+expenses. These
+oil and gas property additions are reflected in cash used in investing
+activities in the 
+periods
+that the payables are settled. 
+For
+the years ended December 31, 2009, 2008, and 2007, the Company issued
+50,094, 23,113, and 32,504 
+shares,
+respectively, of common stock from treasury to its non-employee directors
+pursuant to the 
+Company's
+Equity Incentive Compensation Plan. The Company recorded compensation
+expense related 
+to
+these issuances of approximately $688,000, $1,041,000, and $983,500 for
+the years ended December 31, 
+2009,
+2008, and 2007, respectively. 
+For
+the years ended December 31, 2009, 2008 and 2007, the Company converted
+215,700, 678,197, and 427,059 
+RSU's
+relating to awards granted in previous years. The Company and a
+majority of grant participants 
+mutually
+agreed to net share settle the awards to cover income and payroll tax
+withholding as provided 
+for
+in the plan documents and award agreements. As a result, the Company
+issued 156,252, 482,602, and 
+302,370
+net shares of common stock associated with these grants for the years
+ended December 31, 2009, 2008, 
+and
+2007, respectively. The remaining 59,448, 195,595, and 124,689,
+shares were withheld to satisfy income and 
+payroll
+tax withholding obligations that occurred upon the delivery of the
+shares underlying those RSU's. 
+In
+December 2008 the Company closed a transaction whereby it exchanged
+non-core oil and gas properties 
+located
+in Coupee Parish, Louisiana fair valued at $30.4 million for an increased
+interest in properties 
+located
+in Upton and Midland Counties, Texas and $17.6 million in
+cash. 
+In
+September 2008 the Company hired a new senior executive. Upon
+commencement of employment, the 
+Company
+issued 15,496 shares of restricted stock awards to the senior executive,
+of which half vested 
+on
+December 15, 2009 and the remaining half will vest on December 15, 2010,
+provided that on such 
+vesting
+dates the executive is employed by the Company. The total fair value
+of the issuance was 
+$600,005. 
+In
+March 2007 the Company called the 5.75% Senior Convertible Notes for
+redemption. All of the note 
+holders
+elected to convert the 5.75% Senior Convertible Notes to common
+stock. As a result, the 
+Company
+issued 7,692,295 shares of common stock on March 16, 2007, in exchange for
+the $100 million 
+of
+5.75% Senior Convertible Notes then outstanding. The conversion was
+executed in accordance with 
+the
+conversion provisions of the original indenture. Additionally, the
+conversion resulted in a $7.0 
+million
+decrease in non-current deferred income taxes payable and a corresponding
+increase in 
+additional
+paid-in capital that resulted from the recognition of the cumulative
+excess tax benefit earned 
+by
+the Company associated with the contingent interest feature of the
+notes. 
+The accompanying notes are an integral part of
+these consolidated financial statements. 
+F-6 
+ST.
+MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER
+31, 2009 
+Note
+1 – Summary of Significant Accounting Policies 
+Description
+of Operations 
+St. Mary
+Land & Exploration Company (“St. Mary” or the “Company”) is an independent
+energy company engaged in the exploration, exploitation, development,
+acquisition, and production of natural gas and crude oil. The
+Company’s operations are conducted entirely in the continental United
+States. 
+Basis
+of Presentation 
+The
+accompanying consolidated financial statements include the accounts of the
+Company and its wholly-owned subsidiaries and have been prepared in accordance
+with accounting principles generally accepted in the United States and the
+instructions to Form 10-K and regulation S-X. Subsidiaries that are
+not wholly-owned are accounted for using full consolidation by the equity or
+cost methods as appropriate. Equity method investments are included
+in other noncurrent assets in the accompanying consolidated balance
+sheets. Intercompany accounts and transactions have been
+eliminated. In connection with the preparation of the consolidated
+financial statements of St. Mary and in accordance with Financial Accounting
+Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 855,
+“Subsequent Events” (“ASC Topic 855”) the Company evaluated subsequent events
+after the balance sheet date of December 31, 2009, through the filing of this
+report, February 23, 2010. For additional information regarding ASC,
+please refer to the section titled Recently Issued Accounting Standards
+within Note 1 – Summary of Significant Accounting Policies . 
+On
+January 1, 2009, the adoption of new authoritative accounting guidance
+under FASB ASC Topic 470, “Debt” (“ASC Topic 470”) required retrospective
+application. As a result, prior period balances presented have been
+adjusted to reflect the period-specific effects of applying ASC Topic
+470. Please refer to Note 5 – Long-term Debt for additional
+information regarding adoption. 
+Use
+of Estimates in the Preparation of Financial Statements 
+The
+preparation of financial statements in conformity with accounting principles
+generally accepted in the United States requires management to make estimates
+and assumptions that affect the reported amounts of oil and gas reserves, assets
+and liabilities, disclosure of contingent assets and liabilities at the date of
+the financial statements, and the reported amounts of revenues and expenses
+during the reporting period. Actual results could differ from those
+estimates. Estimates of proved oil and gas reserve quantities provide
+the basis for the calculation of depletion, depreciation, and amortization
+(“DD&A”), impairment of proved properties, and the Net Profits Interest
+Bonus Plan (“Net Profits Plan”) liability, each of which represents a
+significant component of the accompanying consolidated financial
+statements. 
+Cash and Cash
+Equivalents 
+The
+Company considers all liquid investments purchased with an initial maturity of
+three months or less to be cash equivalents. The carrying value of
+cash and cash equivalents approximates fair value due to the short-term nature
+of these instruments. 
+Short-term
+Investments 
+As of
+December 31, 2008, the Company held $1.0 million of short-term investments,
+which consists of a certificate of deposit. Securities
+categorized as held-to-maturity are stated at amortized cost whereas
+available-for-sale securities are marked-to-market. As of December
+31, 2009, the Company held no short-term investments. 
+F-7 
+Accounts
+Receivable and Concentration of Credit Risk 
+The
+Company’s accounts receivables consist mainly of receivables from oil and gas
+purchasers and from partners with interests in common properties operated by the
+Company. Although diversified among many companies, collectability is
+dependent upon the financial wherewithal of each individual company and is
+influenced by the general economic conditions of the industry. The
+Company records an allowance for doubtful accounts on a case by case basis once
+there is evidence that collection is not probable. Receivables are
+not collateralized. As of December 31, 2009, the Company had no
+allowance for doubtful accounts recorded. As of December 31, 2008,
+the Company had $16.8 million recorded as allowance for doubtful
+accounts. For additional discussion on allowance for doubtful
+accounts, please refer to Note 14 – SemGroup Bankruptcy. 
+The
+Company has accounts with separate banks in Denver, Colorado; Shreveport,
+Louisiana; Franklin, Louisiana; Tulsa, Oklahoma; and Billings,
+Montana. At December 31, 2009, and 2008, the Company had
+$2.3 million and $4.8 million, respectively, invested in money market funds
+and overnight investment sweep accounts. The difference between the
+investment amount and the cash and cash equivalents amount on the accompanying
+consolidated balance sheets represents uncleared disbursements and
+non-interest-bearing checking accounts. The Company’s policy is to
+invest in highly-rated instruments and to limit the amount of credit exposure at
+each individual institution. 
+The
+Company currently uses 6 separate counterparties for its oil and gas commodity
+derivatives. The counterparties to the Company’s derivative
+instruments are highly-rated entities with corporate credit ratings at or
+exceeding BBB + and
+Baa1 classifications by Standard & Poor’s and Moody’s,
+respectively. Ratings represent minimum investment grade
+ratings. 
+Oil and Gas Producing
+Activities 
+The
+Company follows the successful efforts method of accounting for its oil and gas
+properties. Under this method of accounting, all property acquisition
+costs and costs of exploratory and development wells are capitalized when
+incurred, pending determination of whether the well found proved
+reserves. If an exploratory well does not find proved reserves, the
+costs of drilling the well are charged to expense. Exploratory dry
+hole costs are included in cash flows from investing activities as part of
+capital expenditures within the accompanying consolidated statements of cash
+flows. The costs of development wells are capitalized whether those
+wells are successful or unsuccessful. 
+Geological
+and geophysical costs and the costs of carrying and retaining unproved
+properties are expensed as incurred. DD&A of capitalized costs
+related to proved oil and gas properties is calculated on a pool-by-pool basis
+using the units-of-production method based upon proved reserves. The
+computation of DD&A takes into consideration restoration, dismantlement, and
+abandonment costs as well as the anticipated proceeds from salvaging
+equipment. As of December 31, 2009, and 2008, the Company’s
+capitalized proved oil and gas properties included $77.8 million and $102.3
+million, respectively, of estimated salvage value. 
+The
+Company follows guidance under FASB ASC Topic 932, “Extractive Activities – Oil
+and Gas” (“ASC Topic 932”) when accounting for suspended well
+costs. For additional discussion, please see the heading Suspended Well Costs in Note
+15 –Oil and Gas Activities . 
+Impairment
+of Proved and Unproved Properties 
+Producing
+oil and gas property costs are evaluated for impairment and reduced to fair
+value, which is expected future discounted cash flows, if the sum of
+expected undiscounted future cash flows is less than net book value pursuant to
+FASB ASC Topic 360, “Property, Plant, and Equipment” (“ASC Topic
+360”). Expected future cash flows are calculated on all proved
+reserves using a discount rate and price forecasts selected by the Company’s
+management. The discount rate is a rate that management believes is
+representative of current market conditions. The price forecast is
+based on NYMEX strip pricing for the first five years, adjusted for basis
+differentials. At the end of the first five years a flat terminal
+price is used. Future operating costs are also 
+F-8 
+adjusted
+as deemed appropriate for these estimates. An impairment write down
+is recorded on unproved property when the Company determines that either the
+property will not be developed or the carrying value is not
+realizable. 
+For the
+years ended December 31, 2009, and 2008, the Company recorded proved
+property impairment expense of $174.8 million and $302.2 million,
+respectively. The Company did not incur any proved property
+impairment write-downs during 2007. In the first quarter of 2009, the
+Company incurred impairment on proved properties of $97.3 million related to
+assets located in the Mid-Continent region due to a significant decrease in the
+market price for natural gas and wider than normal differentials. In
+the fourth quarter of 2009, the Company incurred impairment on proved properties
+of $20.4 million related to assets located in the ArkaLaTex region due to
+decreased natural gas prices and engineering revisions. The Company
+incurred an additional impairment on proved properties of $14.0 million during
+the year related to the write-down of certain assets located in the Gulf of
+Mexico in which the Company is relinquishing its ownership interests in order to
+satisfy its abandonment obligations. Approximately $154.0 million of
+the 2008 impairment write-down relates to the Olmos assets in South Texas that
+were acquired as part of the 2007 Rockford and Catarina
+acquisitions. The remaining 2008 impairment came from proved
+properties in the Gulf of Mexico, the Greater Green River Basin in Wyoming, and
+the Company’s Hanging Women Basin coalbed methane project. 
+For the
+years ended December 31, 2009, 2008, and 2007, the Company recorded
+expense related to the abandonment and impairment of unproved properties of
+$45.4 million, $39.0 million, and $4.8 million, respectively. The
+largest specific components of the 2009 impairment related to the Floyd Shale
+acreage located in Mississippi and acreage in Oklahoma. The largest
+specific component of the 2008 impairment related to acreage within the Olmos
+shallow gas formation in South Texas. 
+Sales
+of Proved and Unproved Properties 
+The sale
+of a partial interest in a proved oil and gas property is accounted for as
+normal retirement, and no gain or loss is recognized as long as the treatment
+does not significantly affect the units-of-production depletion
+rate. A gain or loss is recognized for all other sales of producing
+properties and is included in the accompanying consolidated statements of
+operations. 
+The sale
+of a partial interest in an unproved property is accounted for as a recovery of
+cost when substantial uncertainty exists as to the ultimate recovery of the cost
+applicable to the interest retained. A gain on the sale is recognized
+to the extent that the sales price exceeds the carrying amount of the unproved
+property. A gain or loss is recognized for all other sales of
+nonproducing properties and is included in the accompanying consolidated
+statements of operations. 
+Materials Inventory 
+The
+Company’s materials inventory is primarily comprised of tubular goods to be used
+in future drilling or repair operations. Materials inventory is
+valued at the lower of cost or market and totaled $24.5 million and $40.5
+million at December 31, 2009, and 2008, respectively. The
+Company incurred net materials inventory write-downs for year ended December
+31, 2009, of $14.2 million as a result of the decrease in value of
+tubular goods. There were no materials inventory write-downs for the
+years ended December 31, 2008, and 2007. 
+Assets
+Held for Sale 
+In
+accordance with ASC Topic 360, any properties held for sale as of the date of
+presentation of a balance sheet have been classified as assets held for sale and
+are separately presented on the accompanying consolidated balance sheets at the
+lower of net book value or fair value less the cost to sell. The
+asset retirement obligation liabilities related to such properties have been
+reclassified to asset retirement obligations associated with oil and gas
+properties held for sale in the consolidated balance sheets. For
+additional discussion on assets held for sale, please refer to Note 3 –
+Acquisitions, Divestitures, and Assets Held for Sale. 
+F-9 
+Other
+Property and Equipment 
+Other
+property and equipment such as office furniture and equipment, buildings, and
+computer hardware and software are recorded at cost. Costs of
+renewals and improvements that substantially extend the useful lives of the
+assets are capitalized. Maintenance and repair costs are expensed
+when incurred. Depreciation is calculated using the straight-line
+method over the estimated useful lives of the assets which range from three to
+thirty years. When other property and equipment is sold or retired,
+the capitalized costs and related accumulated depreciation are removed from the
+accounts. 
+Goodwill 
+Goodwill
+is measured as the excess of the acquisition costs over the sum of the amounts
+assigned to the identifiable assets acquired less liabilities
+assumed. Goodwill was recorded as a result of the acquisition of
+Agate Petroleum, Inc. in January 2005. The Company conducted an
+impairment review annually or more frequently if impairment indicators
+arose. The Company fully impaired its goodwill at December 31,
+2008. 
+Restricted
+Cash 
+Proceeds
+from certain sales of oil and gas properties are held in escrow and restricted
+for future acquisitions under tax-free exchange agreements. These
+funds are invested in money market funds consisting of corporate commercial
+paper, repurchase agreements, and U.S. Treasury obligations and are carried at
+cost, which approximates fair market value. 
+Intangible
+Assets 
+As of
+December 31, 2009, and 2008, the Company’s other noncurrent assets in the
+accompanying consolidated balance sheets include $380,000 and $1.4 million,
+respectively, of intangible assets. These assets arise from acquired
+oil and gas sale contracts with favorable pricing terms. They do not
+qualify as derivatives or hedges. Intangible assets of the Company
+are amortized using the units-of-production method and are evaluated for
+impairment if such indicators arise. 
+Cash
+Settlement Balancing 
+The
+Company uses the sales method of accounting for gas revenue whereby sales
+revenue is recognized on all gas sold to purchasers, regardless of whether the
+sales are proportionate to the Company’s ownership in the
+property. An asset or liability is recognized to the extent that
+there is an imbalance in excess of the remaining gas reserves on the underlying
+properties. The Company’s gas imbalance position at December 31,
+2009, and 2008, respectively, resulted in the recording of $1.8 million to
+accounts receivable as of both dates and $1.2 million and $1.1 million,
+respectively, to accounts payable. 
+Derivative
+Financial Instruments 
+The
+Company seeks to manage or reduce commodity price risk on acquisitions of
+producing properties and other production by hedging cash flows. The
+Company intends for derivative instruments used for this purpose to qualify as
+and to be designated as cash flow hedges. The Company seeks to
+minimize its basis risk and indexes the majority of its oil hedges to NYMEX
+prices and the majority of its gas hedges to various regional index prices
+associated with pipelines in proximity to the Company’s areas of gas
+production. For additional discussion on derivatives, please see Note
+10 – Derivative Financial Instruments. 
+F-10 
+Net Profits Plan 
+The
+Company records the estimated fair value of future payments under the Net
+Profits Plan as a noncurrent liability in the accompanying consolidated balance
+sheets. The estimated liability is a discounted calculation and has
+underlying assumptions including estimates of oil and gas reserves, recurring
+and workover lease operating expense, production and ad valorem tax rates,
+present value discount factors, and pricing assumptions. The
+estimates the Company uses in calculating the long-term liability are
+adjusted from period-to-period based on the most current information
+attributable to the underlying assumptions. Changes in the estimated
+liability of future payments associated with the Net Profits Plan are recorded
+as increases or decreases to expense in the current period as a separate line
+item in the accompanying consolidated statements of operations as these changes
+are considered changes in estimates. 
+The
+distribution amounts due to participants and payable in each period under the
+Net Profits Plan as cash compensation related to periodic operations are
+recognized as compensation expense and are included within general and
+administrative expense and exploration expense in the accompanying consolidated
+statements of operations. The corresponding current liability is
+included in accounts payable and accrued expenses in the accompanying
+consolidated balance sheets. This treatment provides for a consistent
+matching of cash expense with net cash flows from the oil and gas properties in
+each respective pool of the Net Profits Plan. For additional
+discussion, please refer to the heading Net Profits Plan in Note 7 –
+Compensation Plans. 
+Asset
+Retirement Obligations 
+The
+Company recognizes an estimated liability for future costs associated with the
+abandonment of its oil and gas properties. A liability for the fair
+value of an asset retirement obligation and corresponding increase to the
+carrying value of the related long-lived asset are recorded at the time a well
+is completed or acquired. The increase in carrying value is included
+in proved oil and gas properties in the accompanying consolidated balance
+sheets. The Company depletes the amount added to proved oil and gas
+property costs and recognizes expense in connection with the accretion of the
+discounted liability over the remaining estimated economic lives of the
+respective oil and gas properties. For additional discussion, please
+refer to Note 9 – Asset Retirement Obligations. 
+Revenue
+Recognition 
+The
+Company derives revenue primarily from the sale of produced natural gas and
+crude oil. The Company reports revenue as the gross amount received
+before taking into account production taxes and transportation costs, which are
+reported as separate expenses. Revenue is recorded in the month the
+Company’s production is delivered to the purchaser, but payment is generally
+received between 30 and 90 days after the date of production. No
+revenue is recognized unless it is determined that title to the product has
+transferred to the purchaser. At the end of each month, the Company
+estimates the amount of production delivered to the purchaser and the price the
+Company will receive. The Company uses its knowledge of its
+properties, their historical performance, New York Mercantile Exchange (“NYMEX”)
+and local spot market prices, quality and transportation differentials, and
+other factors as the basis for these estimates. 
+Major
+Customers 
+During
+2009 the Company had one customer individually account for 12 percent of the
+Company’s total oil and gas production revenue. During 2008 and 2007
+no customer individually accounted for more than ten percent of the Company’s
+total oil and gas production revenue. 
+F-11 
+Stock
+Based Compensation 
+At
+December 31, 2009, the Company had stock-based employee compensation plans that
+included RSUs, PSAs, stock awards, and stock options issued to employees and
+non-employee directors as more fully described in Note 7- Compensation
+Plans. Stock options were last issued in December 2004 and were fully
+vested as of December 31, 2008. The Company records expense
+associated with the fair value of stock-based compensation in accordance with
+FASB ASC Topic 718, “Compensation – Stock Compensation” (“ASC
+718”). The Company used the modified-prospective method to record
+compensation expense associated with stock options that were outstanding and
+unvested as of January 1, 2006. The Company records compensation
+expense associated with the issuance of RSUs and PSAs based on the estimated
+fair value of these grants as determined at the time of
+grant. 
+Income
+Taxes 
+The
+Company accounts for deferred income taxes whereby deferred tax assets and
+liabilities are recognized based on the tax effects of temporary differences
+between the carrying amount on the financial statements and the tax basis of
+assets and liabilities, as measured using current enacted tax
+rates. These differences will result in taxable income or deductions
+in future years when the reported amount of the asset or liabilities are
+recorded or settled, respectively. When appropriate the Company
+records a valuation allowance to reduce deferred tax assets. 
+Earnings
+per Share 
+Basic net
+income per common share is calculated by dividing net income available to common
+stockholders by the weighted-average basic common shares outstanding for the
+respective period. The weighted-average basic common shares
+outstanding include vested RSUs. The basic earnings per share
+calculations reflect the impact of any repurchases of shares of common stock
+made by the Company. 
+Diluted
+net income per common share of stock is calculated by dividing adjusted net
+income by the weighted-average diluted common shares outstanding, which includes
+the effect of potentially dilutive securities. Potentially dilutive
+securities for the diluted earnings per share calculation consist of unvested
+RSUs, in-the-money outstanding stock options to purchase the Company’s common
+stock, contingent PSAs, and shares into which the 3.50% Senior Convertible Notes
+are convertible. 
+The
+treasury stock method is used to measure the dilutive impact of stock options,
+RSUs, 3.50% Senior Convertible Notes, and PSAs. In accordance with
+FASB ASC Topic 260, “Earnings Per Share,” when there is a loss from continuing
+operations, all potentially dilutive shares will be anti-dilutive. As
+such, there were no dilutive shares for the year ended December 31,
+2009. The following table details the weighted-average dilutive and
+anti-dilutive securities related to stock options, RSUs, and PSAs for the years
+presented: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+Dilutive 
+- 
+890,189 
+1,441,556 
+Anti-dilutive 
+1,152,127 
+330,231 
+- 
+The
+Company’s 3.50% Senior Convertible Notes, which were issued on April 4, 2007,
+have a net-share settlement right whereby each $1,000 principal amount of notes
+may be surrendered for conversion to cash in an amount equal to the principal
+amount and, if applicable, shares of common stock for the amount in excess of
+the principal amount. The 3.50% Senior Convertible Notes have not
+been dilutive for any reporting period that they have been outstanding and
+therefore do not impact the diluted earnings per share calculation for the
+periods ended December 31, 2009, 2008, and 2007. 
+F-12 
+On August
+1, 2009, and 2008, the Company granted 725,092 and 465,751 PSAs,
+respectively, for the three-year performance periods ending
+June 30, 2012, and 2011. At the end of each grant’s
+three-year performance period, a multiplier will be applied to all vested PSAs
+to determine the number of common shares issued. The number of common
+shares issued is determined based on the Company’s absolute stock price
+performance and a comparison of the Company’s stock price performance to an
+index of its peers. The number of potentially dilutive shares related
+to the PSAs is based on the number of shares, if any, which would be issuable if
+the end of the reporting period was the end of the contingency
+period. Based on the Company’s cumulative total shareholder return
+(“TSR”) and the relative measure of the Company’s TSR compared with the
+cumulative TSR of the index of its peers, there would have been potentially
+dilutive shares related to PSAs as of December 31, 2009. However, no
+dilutive shares related to PSAs were included in the diluted earnings per share
+calculation for the year ended December 31, 2009, because the Company recorded a
+loss for the period. There were no potentially dilutive shares
+related to PSAs included in the diluted earnings per share calculation for the
+years ended December 31, 2008, and 2007. For additional discussion on
+PSAs, please see the heading Performance Share Awards Under the
+Equity Incentive Compensation Plan in Note 7 – Compensation
+Plans. 
+The
+following table sets forth the calculations of basic and diluted earnings per
+share. 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands, except per share amounts) 
+Net
+income (loss) 
+$ 
+(99,370 
+) 
+$ 
+87,348 
+$ 
+187,098 
+Adjustments
+to net income (loss) for dilution: 
+Add:
+interest expense not incurred if 5.75% Senior Convertible Notes
+converted 
+- 
+- 
+1,285 
+Less:
+other adjustments 
+- 
+- 
+(13 
+) 
+Less:
+income tax effect of adjustment items 
+- 
+- 
+(469 
+) 
+Net
+income (loss) adjusted for the effect of dilution 
+$ 
+(99,370 
+) 
+$ 
+87,348 
+$ 
+187,901 
+Basic
+weighted-average common shares outstanding 
+62,457 
+62,243 
+61,852 
+Add:
+dilutive effect of stock options, unvested RSUs, and PSAs 
+- 
+890 
+1,441 
+Add:
+dilutive effect of 5.75% Senior Convertible Notes using the if-converted
+method 
+- 
+- 
+1,557 
+Add:
+dilutive effect of 3.50% Senior Convertible Notes 
+- 
+- 
+- 
+Diluted
+weighted-average common shares outstanding 
+62,457 
+63,133 
+64,850 
+Basic
+net income (loss) per common share 
+$ 
+(1.59 
+) 
+$ 
+1.40 
+$ 
+3.02 
+Diluted
+net income (loss) per common share 
+$ 
+(1.59 
+) 
+$ 
+1.38 
+$ 
+2.90 
+Comprehensive
+Income 
+Comprehensive
+income consists of net income, the unrealized gain or loss for the effective
+portion of derivative instruments classified as cash flow hedges, and the
+minimum pension liability adjustment that was recognized as a component of net
+periodic benefit cost. Comprehensive income is presented net of
+income taxes in the accompanying consolidated statements of stockholders’ equity
+and comprehensive income (loss). 
+F-13 
+The
+changes in the balances of components comprising other comprehensive income and
+loss are presented in the following table: 
+Pension 
+Other 
+Derivative 
+Liability 
+Comprehensive 
+Instruments 
+Adjustments 
+Income
+(Loss) 
+(In
+thousands) 
+For
+the year ended December 31, 2007 
+Before
+tax income (loss) 
+$ 
+(272,655 
+) 
+$ 
+119 
+$ 
+(272,536 
+) 
+Tax
+benefit (expense) 
+102,688 
+(49 
+) 
+102,639 
+After
+deferred tax income (loss) 
+$ 
+(169,967 
+) 
+$ 
+70 
+$ 
+(169,897 
+) 
+For
+the year ended December 31, 2008 
+Before
+tax income (loss) 
+$ 
+358,632 
+$ 
+(1,941 
+) 
+$ 
+356,691 
+Tax
+benefit (expense) 
+(135,164 
+) 
+734 
+(134,430 
+) 
+After
+deferred tax income (loss) 
+$ 
+223,468 
+$ 
+(1,207 
+) 
+$ 
+222,261 
+For
+the year ended December 31, 2009 
+Before
+tax income (loss) 
+$ 
+(165,684 
+) 
+$ 
+119 
+$ 
+(165, 565 
+) 
+Tax
+benefit (expense) 
+62,363 
+(45 
+) 
+62,318 
+After
+deferred tax income (loss) 
+$ 
+(103,321 
+) 
+$ 
+74 
+$ 
+(103,247 
+) 
+Fair
+Value of Financial Instruments 
+The
+Company’s financial instruments including cash and cash equivalents, accounts
+receivable, and accounts payable are carried at cost, which approximates fair
+value due to the short-term maturity of these instruments. The
+recorded value of the Company’s credit facility approximates its fair value as
+it bears interest at a floating rate. The Company had $188.0 million
+and $300.0 million in loans outstanding under its revolving credit agreement as
+of December 31, 2009, and 2008, respectively. The Company’s 3.50%
+Senior Convertible Notes due 2027 (the “3.50% Senior Convertible Notes”) are
+recorded at cost, and the fair value is disclosed in Note 5 – Long-Term
+Debt. The Company has derivative financial instruments that are
+recorded at fair value and changes in fair value run through accumulated other
+comprehensive income in the accompanying consolidated balance sheets to the
+extent they are effective. Considerable judgment is required to
+develop estimates of fair value. The estimates provided are not
+necessarily indicative of the amounts the Company would realize upon the sale or
+refinancing of such instruments. 
+Industry
+Segment and Geographic Information 
+The
+Company operates exclusively in the exploration and production
+segment. All of the Company’s operations are conducted in the
+continental United States. The Company reports as a single
+industry segment. The Company’s gas marketing department provides
+mostly internal services and acts as the first purchaser of natural gas and
+natural gas liquids produced by the Company in certain cases. We
+consider the Company’s marketing function as ancillary to the Company’s oil and
+gas producing activities. The amount of income these operations
+generate from marketing gas produced by third parties is not material to the
+Company’s financial position, and segmentation of such activity would not
+provide a better understanding of the Company’s performance. However,
+gross revenue and expense related to marketing activities for gas produced by
+third parties are presented discretely in the accompanying consolidated
+statements of operations. 
+F-14 
+Off-Balance
+Sheet Arrangements 
+As part
+of its ongoing business, the Company has not participated in transactions that
+generate relationships with unconsolidated entities or financial partnerships,
+such as entities often referred to as structured finance or special purpose
+entities (“SPEs”), which would have been established for the purpose of
+facilitating off-balance sheet arrangements or other contractually narrow or
+limited purposes. As of and up to December 31, 2009, the
+Company has not been involved in any unconsolidated SPE
+transactions. 
+The
+Company evaluates its transactions to determine if any variable interest
+entities exist. If it is determined that St. Mary is the primary
+beneficiary of a variable interest entity, that entity is consolidated into
+St. Mary. 
+Recently
+Issued Accounting Standards 
+New
+authoritative accounting guidance under FASB ASC Topic 105, “Generally Accepted
+Accounting Principles” (“ASC Topic 105”) established the FASB Accounting
+Standards Codification as the source of authoritative U.S. GAAP recognized by
+the FASB to be applied to nongovernmental entities. ASC Topic 105
+also states that rules and interpretive releases of the Securities and Exchange
+Commission (“SEC”) under federal securities laws are also sources of
+authoritative GAAP for SEC registrants. ASC Topic 105 supersedes
+existing FASB, American Institute of Certified Public Accountants, Emerging
+Issues Task Force, and related literature. All other accounting
+literature is considered non-authoritative. ASC Topic 105 changes the
+way the Company cites authoritative guidance within the Company’s financial
+statements and accounting policies. The new authoritative guidance
+under ASC Topic 105 became effective for periods ending on or after
+September 15, 2009, and did not have a material impact on the
+Company’s consolidated financial statements. 
+New
+authoritative accounting guidance under FASB ASC Topic 805, “Business
+Combinations” (“ASC Topic 805”) requires the acquiring entity in a business
+combination to recognize and measure all assets and liabilities assumed in the
+transaction and any non-controlling interest in the acquiree at fair value as of
+the acquisition date. ASC Topic 805 changes the way the Company
+accounts for acquisitions of proved oil and gas properties. Such
+acquisitions will now be treated as business combinations, which will require
+transaction costs to be expensed as incurred, may generate gains or losses due
+to fair value changes between the effective and closing dates of acquisitions,
+and will require possible recognition of goodwill given differences between the
+purchase price and fair value of acquired assets. ASC Topic 805
+further amends the initial recognition and measurement, subsequent measurement
+and accounting, and disclosures of assets and liabilities arising from
+contingencies in a business combination. The new authoritative
+guidance under ASC Topic 805 became effective for the Company on
+January 1, 2009, and the impact on the Company’s consolidated
+financial statements will largely be dependent on the size and nature of the
+business combinations completed. The Company has not made any
+significant acquisitions of oil and gas properties since adoption. 
+New
+authoritative accounting guidance under FASB ASC Topic 810, “Consolidation”
+(“ASC Topic 810”) established accounting and reporting standards that
+require non-controlling interests to be reported as a component of equity along
+with any changes in the parent’s ownership interest. The new
+authoritative guidance under ASC Topic 810 became effective for the Company on
+January 1, 2009, and did not have a material impact on the Company’s
+consolidated financial statements. 
+New
+authoritative accounting guidance under FASB ASC Topic 825, “Financial
+Instruments” (“ASC Topic 825”) requires the Company to include disclosures about
+the fair value of its financial instruments whenever it issues financial
+information for interim reporting periods and annual reporting periods, whether
+recognized or not recognized in the consolidated balance sheets. The
+new authoritative guidance under ASC Topic 825 became effective for the Company
+on April 1, 2009, and did not have a material impact on the Company’s
+consolidated financial statements. 
+F-15 
+New
+authoritative accounting guidance under ASC Topic 855 established general
+standards of accounting for and disclosures of events that occur after the
+balance sheet date but before financial statements are issued or are available
+to be issued. ASC Topic 855 requires companies to disclose the date
+through which the Company evaluated subsequent events, the basis for that date,
+and whether that date represents the date the financial statements were
+issued. The new authoritative guidance under ASC Topic 855 became
+effective for the Company on April 1, 2009, and did not have a
+material impact on the Company’s consolidated financial statements. 
+In
+December 2008 the SEC published the final rules and interpretations updating its
+oil and gas reporting requirements. Many of the revisions are updates
+to definitions in the existing oil and gas rules to make them consistent with
+the Petroleum Resource Management System, which was developed by several
+petroleum industry organizations and is a widely accepted standard for the
+management of petroleum resources. Key revisions include a
+requirement to use 12-month average pricing determined by averaging the first of
+the month prices for the preceding 12 months rather than year-end pricing for
+estimating proved reserves, the ability to include nontraditional resources in
+reserves, the ability to use new technology for determining proved reserves, and
+permitting disclosure of probable and possible reserves. The Company
+adopted these new rules and interpretations as of December 31,
+2009. 
+The FASB
+aligned ASC Topic 932, with all of the aforementioned SEC requirements by
+issuing ASC Update 2010-03. The new authoritative guidance became
+effective for the Company’s 2009 Annual Report on Form 10-K and has been fully
+adopted by the Company as of December 31, 2009. 
+In
+January 2010 the FASB issued ASC Update 2010-06, “Fair Value Measurements and
+Disclosures” (“ASC Update 2010-06”) that requires additional disclosures
+surrounding transfers in and out of Levels 1 and 2, inputs and valuation
+techniques used to value Level 2 and 3 measurements, and push down of previously
+prescribed fair value disclosures to each class of asset and liability for
+Levels 1, 2, and 3. This new authoritative guidance is effective for
+interim and annual reporting periods beginning after December 15,
+2009. The Company will apply the new authoritative guidance in the
+Company’s March 31, 2010, Quarterly Report on Form 10-Q. ASC Update
+2010-06 also requires that purchases, sales, issuances, and settlements for
+Level 3 measurements be disclosed. This portion of the new
+authoritative guidance is effective for interim and annual reporting periods
+beginning after December 15, 2010. The Company will apply this new
+authoritative guidance in the Company’s March 31, 2011, Quarterly Report on Form
+10-Q. The adoption of ASC Update 2010-06 will not have a material
+impact on the Company’s financial statements. 
+Please
+refer to Note 5 – Long-term Debt, Note 8 – Pension Benefits, Note 10 -
+Derivative Financial Instruments, Note 11 – Fair Value Measurements, and Note 16
+– Disclosures about Oil and Gas Producing Activities for additional information
+on the recent adoption of new authoritative accounting guidance. 
+Note
+2 – Accounts Receivable and Accounts Payable and Accrued Expenses 
+Accounts
+receivable are comprised of the following: 
+As
+of December 31, 
+2009 
+2008 
+(In
+thousands) 
+Accrued
+oil and gas sales 
+$ 
+80,085 
+$ 
+84,583 
+Due
+from joint interest owners 
+29,719 
+56,493 
+Settled
+hedge receivable 
+253 
+8,829 
+State
+severance tax refunds 
+4,638 
+5,049 
+Other 
+1,441 
+2,736 
+Total
+accounts receivable 
+$ 
+116,136 
+$ 
+157,690 
+F-16 
+Accounts
+payable and accrued expenses are comprised of the following: 
+As
+of December 31, 
+2009 
+2008 
+(In
+thousands) 
+Accrued
+drilling costs 
+$ 
+100,960 
+$ 
+111,397 
+Revenue
+and severance tax payable 
+33,370 
+42,520 
+Accrued
+lease operating expense 
+13,760 
+20,328 
+Accrued
+property taxes 
+4,747 
+4,889 
+Accrued
+interest 
+3,198 
+2,794 
+Accrued
+compensation 
+23,607 
+18,613 
+Trade
+payables 
+11,633 
+25,629 
+Plug
+and abandonment liability 
+23,665 
+7,281 
+Accrued
+marketed gas system expense 
+8,313 
+8,892 
+Settled
+hedge payable 
+1,637 
+- 
+Other 
+11,352 
+12,468 
+Total
+accounts payable and accrued expenses 
+$ 
+236,242 
+$ 
+254,811 
+Note
+3 – Acquisitions, Divestitures, and Assets Held for Sale 
+Hanging
+Woman Basin Divestiture 
+In
+December 2009 the Company completed the divestiture of certain non-strategic
+coalbed methane properties located in the Hanging Woman Basin in the Rocky
+Mountain region. The cash received at closing, including a $2.0
+million deposit, net of commission costs, was $23.3 million. The
+final sales price is subject to normal post-closing adjustments and is expected
+to be finalized during the second quarter of 2010. The estimated gain
+on sale related to the divestiture is approximately $12.9 million and may be
+impacted by the previously mentioned post-closing adjustments. The Company
+determined that this sale did not qualify for discontinued operations accounting
+under FASB ASC Topic 205, “Presentation of Financial Statements” (“ASC Topic
+205”). 
+Greater
+Green River Basin Divestiture 
+In June
+2008 the Company completed the divestiture of certain non-strategic gas
+properties located in the Greater Green River Basin in the Rocky Mountain region
+as the second step of a reverse 1031 exchange. The cash received at
+closing, net of commission costs, was $21.9 million. The final
+sales price is subject to normal post-closing adjustments and is expected to be
+finalized during 2010. The estimated gain on sale related to the
+divestiture is approximately $900,000, net of commission costs and Net Profit
+Plan payments, and may be impacted by the previously mentioned post-closing
+adjustments. The Company determined that this sale did not qualify
+for discontinued operations accounting under ASC Topic 205. 
+Abraxas
+Divestiture 
+In
+January 2008 the Company completed the divestiture of certain non-strategic oil
+and gas properties as the second step of a reverse 1031 exchange. The
+sold properties were located primarily in the Rocky Mountain and Mid-Continent
+regions, and were sold to Abraxas Petroleum Corporation and Abraxas Operating,
+LLC. The final sales price, net of commission costs, was $129.4
+million. The final gain on sale related to the divestiture was
+approximately $53.4 million, net of commission costs and Net Profit Plan
+payments. The Company determined that this sale did not qualify for
+discontinued operations accounting under ASC Topic 205. 
+F-17 
+Carthage
+Acquisition 
+In March
+2008, the Company acquired oil and gas properties as the first step of a reverse
+1031 exchange. These properties are located primarily in the Carthage
+Field in Panola County, Texas and were purchased for $49.2 million in
+cash. After normal purchase price adjustments, the Company allocated
+$29.0 million to proved oil and gas properties, $20.6 million to unproved
+oil and gas properties, and a net $215,000 to other liabilities. The
+Company also recorded a $165,000 asset retirement obligation liability
+associated with the acquired properties. The acquisition was funded
+with cash on hand and borrowings under the Company’s existing credit
+facility. During the second quarter of 2008, the Company acquired
+additional interests in the majority of these properties for $8.1
+million. 
+Assets
+Held for Sale 
+In
+accordance with ASC Topic 360, assets are classified as held for sale when the
+Company commits to a plan to sell the assets and there is reasonable certainty
+that the sale will take place within one year. Upon classification as
+held for sale, long-lived assets are no longer depreciated or depleted and a
+measurement for impairment is performed to expense any excess of carrying value
+over fair value less costs to sell. Subsequent changes to estimated
+fair value less the cost to sell will impact the measurement of assets held for
+sale for assets for which fair value is determined to be less than the carrying
+value of the assets. 
+As of
+December 31, 2009, the accompanying consolidated balance sheets includes $145.4
+million in book value of assets held for sale, net of accumulated depletion,
+depreciation, and amortization. The corresponding asset retirement
+obligation liability of $18.1 million is also separately
+presented. The above assets held for sale and asset retirement
+obligation liability amounts include certain non-core properties located
+primarily in the Rocky Mountain region that the Company began marketing in the
+third quarter of 2009, as well as a new package of properties located in our
+South Texas and Gulf Coast region. The Company determined that these
+sales do not qualify for discontinued operations accounting under ASC Topic
+205. 
+In
+December 2009, St Mary reached an agreement for the partial sale of its
+previously announced divestiture package, of certain non-strategic oil and gas
+properties located in the Rocky Mountain region to Legacy Reserves Operating
+LP. The transaction has an effective date of November 1,
+2009. Subsequent to year end, on February 17, 2010, the Company
+completed this divestiture. Total cash received, before commission
+costs, was $125.2 million, of which $6.5 million was received as a deposit in
+December 2009 and is separately presented on the accompanying consolidated
+balance sheets. The cash received is subject to normal post-closing
+adjustments and settlements. 
+Subsequent
+to year end, St Mary reached an agreement for the sale of the North Dakota
+portion of its previously announced divestiture package of certain non-strategic
+oil and gas properties located in the Rocky Mountain region to Sequel Energy
+Partners L.P. for $137.0 million in cash, subject to normal closing and
+post-closing adjustments. The agreement has an effective date of
+November 1, 2009, and is anticipated to close in March 2010, subject
+to customary closing conditions. 
+In the
+third quarter of 2009, St. Mary reclassified a portion of the assets previously
+classified as held for sale to assets held and used, as these assets were no
+longer being actively marketed. In accordance with ASC Topic 360, the
+Company must measure the assets at the lower of the assets carrying amount
+before the assets were classified as held for sale, adjusted for any
+depreciation and depletion expense that would have been recognized had the
+assets been continuously classified as held and used, or the assets fair value
+at the subsequent date that the decision not to actively market the assets was
+determined. As a result of this measurement the Company recognized a
+$9.8 million loss on unsuccessful sale of properties, which is included in
+gain (loss) on divestiture activity in the accompanying consolidated
+statements of operations. 
+F-18 
+Note
+4 – Income Taxes 
+The
+provision for income taxes consists of the following: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Current
+income tax (benefit) 
+Federal 
+$ 
+(21,926 
+) 
+$ 
+17,863 
+$ 
+15,136 
+State 
+1,567 
+1,361 
+2,459 
+Deferred
+income tax expense (benefit) 
+(39,735 
+) 
+38,164 
+91,418 
+Total
+income tax expense (benefit) 
+$ 
+(60,094 
+) 
+$ 
+57,388 
+$ 
+109,013 
+Effective
+tax rates 
+37.7% 
+39.7% 
+36.8% 
+As a
+result of the exercise of stock options, the Company reduced its income tax
+payable in 2008 and 2007. The excess income tax benefit to the
+Company associated with stock awards was $13.9 million in 2008 and
+$9.9 million in 2007. There was no income tax benefit associated
+with stock awards in 2009. 
+The
+components of the net deferred tax liabilities are as follows: 
+December
+31, 
+2009 
+2008 
+(In
+thousands) 
+Deferred
+tax liabilities: 
+Oil
+and gas properties 
+$ 
+419,585 
+$ 
+433,536 
+Unrealized
+derivative asset 
+- 
+42,407 
+Interest
+on Senior Convertible Notes 
+1,937 
+2,450 
+Other 
+1,378 
+3,635 
+Total
+deferred tax liabilities 
+422,900 
+482,028 
+Deferred
+tax assets: 
+Net
+Profits Plan liability 
+63,902 
+66,800 
+Unrealized
+derivative liability 
+21,107 
+1,072 
+State
+tax net operating loss carryforward or carryback 
+10,915 
+7,215 
+Stock
+compensation 
+9,647 
+7,291 
+Other
+long-term liabilities 
+17,277 
+7,179 
+Total
+deferred tax assets 
+122,848 
+89,557 
+Valuation
+allowance 
+(3,203 
+) 
+(3,146 
+) 
+Net
+deferred tax assets 
+119,645 
+86,411 
+Total
+net deferred tax liabilities 
+303,255 
+395,617 
+Less:
+current deferred income tax liabilities 
+(1,366 
+) 
+(42,766 
+) 
+Add:
+current deferred income tax assets 
+6,300 
+1,477 
+Non-current
+net deferred tax liabilities 
+$ 
+308,189 
+$ 
+354,328 
+Current
+federal income tax refundable 
+$ 
+32,773 
+$ 
+13,136 
+Current
+state income tax refundable (payable) 
+$ 
+(168 
+) 
+$ 
+25 
+At
+December 31, 2009, the Company had estimated state net operating loss
+carryforwards of approximately $259 million expiring between 2010 and
+2029. The Company has a federal AMT credit carry forward of $2.1
+million which will not expire, and other state tax credits of $285,000 which
+expire between 2010 and 2019. The majority of the Company’s valuation
+allowance relates to state net operating loss carryforwards, 
+F-19 
+state tax
+credits, and state and federal income tax benefit amounts which the Company
+anticipates will expire before they can be utilized. Permanent items
+included in the calculation of income tax for certain states are anticipated to
+impact the Company’s ability to deduct operating losses and realize federal
+income tax deduction benefits in certain states and the Company has adjusted its
+valuation allowances accordingly. A small portion of the valuation
+allowance relates to the Net Profits Plan liability and reflects an estimate of
+future executive compensation that may not be deductible for income tax purposes
+when future cash payments occur under the plan. 
+Federal
+income tax expense differs from the amount that would be provided by applying
+the statutory U.S. federal income tax rate to income before income taxes
+primarily due to the effect of state income taxes, percentage depletion, the
+estimated effect of the domestic production activities deduction, 2008
+impairment of goodwill, and other permanent differences, as
+follows: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Federal
+statutory tax (benefit) 
+$ 
+(55,812 
+) 
+$ 
+50,526 
+$ 
+103,555 
+Increase
+(decrease) in tax resulting from 
+State
+tax (benefit) (net of federal benefit) 
+(5,141 
+) 
+4,669 
+5,111 
+Goodwill 
+- 
+3,308 
+- 
+Change
+in valuation allowance 
+56 
+(409 
+) 
+896 
+Statutory
+depletion 
+(189 
+) 
+(294 
+) 
+(407 
+) 
+Domestic
+production activities deduction 
+- 
+(275 
+) 
+(384 
+) 
+Other 
+992 
+(137 
+) 
+242 
+Income
+tax expense (benefit) from operations 
+$ 
+(60,094 
+) 
+$ 
+57,388 
+$ 
+109,013 
+Acquisitions,
+drilling, and basis differentials impacting the prices received for crude oil
+and natural gas affect apportionment of taxable income to the states where the
+Company owns property. As its apportionment factors change, the
+Company’s blended state income tax rate changes. This change, when
+applied to the Company’s total temporary difference, impacts the total income
+tax reported in the current year and is reflected in state taxes in the table
+above. Items affecting state apportionment factors are evaluated
+after completion of the prior year income tax return and when significant
+acquisitions or dispositions are closed during the current year. 
+The
+Company and its subsidiaries file income tax returns in the U.S. federal
+jurisdiction and in various states. With few exceptions, the Company
+is no longer subject to U.S. federal or state income tax examinations by these
+tax authorities for years before 2006. The Internal Revenue Service
+initiated an audit of the Company’s 2005 tax year in 2008 and concluded the
+audit in the first quarter of 2009 with a refund to the Company of $278,000 plus
+interest of $41,000. Related amended state income tax returns were
+filed in the second quarter of 2009. There was no change to the
+provision for income tax expense as a result of the examination. In
+the fourth quarter of 2009 the Company received a refund of $5.0 million dollars
+related to its 2008 income tax return. At December 31, 2009 the
+Company is awaiting a $5.5 million dollar refund related to filing an amended
+return for its 2006 tax year reflecting a net operating loss carry back from the
+Company’s 2008 tax year. The Company’s remaining receivable balance
+reflects its intention to carry back a net operating loss generated in 2009 to
+prior years. 
+At
+December 31, 2008, the Company recognized an impairment of goodwill recorded as
+part of the Agate Petroleum, Inc. acquisition in 2005. The tax
+benefit is not calculated upon the recognition of this expense. For
+additional discussion please refer to the section titled Goodwill within Note 1 –
+Summary of Significant Accounting Policies. This resulted in a 2.2
+percent increase in the Company’s effective tax rate for the year ended December
+31, 2008. The Company received $1.0 million in the first quarter of
+2008 for income tax refunds and accrued interest resulting from a carry-over of
+minimum tax credits to its 2003 tax year. 
+F-20 
+The
+Company adopted the uncertainty provision of FASB ASC Topic 740, “Income Taxes”
+on January 1, 2007. There was no financial statement adjustment
+required as a result of adoption. At adoption, the Company had a
+long-term liability for an unrecognized tax benefit of $1.0 million and
+accumulated interest liability of $92,000. The entire amount of
+unrecognized tax benefit would affect the Company’s effective tax rate if
+recognized. Interest expense in the 2009 accompanying consolidated
+statements of operation includes a nominal $12,000 associated with income
+tax. Penalties associated with income tax are recorded in general and
+administrative expense in the accompanying consolidated statements of
+operations. There were no penalties associated with income tax
+recorded for the year ended December 31, 2009, 2008, and 2007. 
+The total
+amount recorded for unrecognized tax benefits is presented below: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Beginning
+balance 
+$ 
+994 
+$ 
+957 
+$ 
+1,112 
+Additions
+for tax positions of prior years 
+231 
+173 
+233 
+Reductions
+for lapse of statute of limitations 
+(341 
+) 
+(136 
+) 
+(388 
+) 
+Ending
+balance 
+$ 
+884 
+$ 
+994 
+$ 
+957 
+Note
+5 – Long-term Debt 
+Revolving
+Credit Facility 
+The
+Company executed a Third Amended and Restated Credit Agreement on April 14,
+2009. This amended revolving credit facility replaced the previous
+facility. The Company incurred $11.1 million of deferred financing
+costs in association with the amended credit facility. Borrowings
+under the facility are secured by a pledge, in favor of the lenders, of
+collateral that includes the majority of the Company’s oil and gas
+properties. The credit facility specifies a maximum loan amount of
+$1.0 billion and has a maturity date of July 31, 2012. The authorized
+borrowing base under the credit facility is subject to regular semi-annual
+redeterminations. The borrowing base redetermination process
+considers the value of St. Mary’s oil and gas properties and other assets, as
+determined by the bank syndicate. On September 29, 2009,
+the lending group redetermined and maintained the Company’s reserve-backed
+borrowing base under the credit facility at an amount of $900
+million. The Company has an aggregate commitment amount of $678
+million under the credit facility. The Company must comply with
+certain covenants under the terms of its credit facility agreement, including
+the limitation of the Company’s annual dividend rate to no more than $0.25 per
+share. The Company is in compliance with all covenants under the
+credit facility as of December 31, 2009, and through the date of this
+filing. Interest and commitment fees are accrued based on the
+borrowing base utilization grid below. Eurodollar loans accrue
+interest at the London Interbank Offered Rate (“LIBOR”) plus the applicable
+margin from the utilization table, and Alternative Base Rate (“ABR”) and
+swingline loans accrue interest at Prime plus the applicable margin from the
+utilization table. Commitment fees are accrued on the unused portion
+of the aggregate commitment amount and are included in interest expense in the
+accompanying consolidated statements of operations. 
+Borrowing
+Base Utilization Grid 
+Borrowing
+Base Utilization Percentage 
+<25% 
+> 25% <50% 
+> 50% <75% 
+> 75% 
+Eurodollar
+Loans 
+2.000% 
+2.250% 
+2.500% 
+2.750% 
+ABR
+Loans or Swingline Loans 
+1.000% 
+1.250% 
+1.500% 
+1.750% 
+Commitment
+Fee Rate 
+0.500% 
+0.500% 
+0.500% 
+0.500% 
+F-21 
+The
+Company had $211.0 million, $188.0 million, and $300.0 million in outstanding
+loans under its revolving credit agreement on February 16, 2010, December 31,
+2009, and 2008, respectively. The Company had $467.0 million, $489.4
+million, and $200.0 million of available borrowing capacity under this facility
+as of February 16, 2010, December 31, 2009, and 2008,
+respectively. The Company had a single letter of credit
+outstanding in the amount of $569,000 as of
+December 31, 2009. This letter of credit reduced the amount
+available under the commitment amount on a dollar-for-dollar
+basis. There was no letter of credit outstanding as of
+February 16, 2010. 
+3.50%
+Senior Convertible Notes Due 2027 
+On April
+4, 2007, the Company issued $287.5 million in aggregate principal amount of
+3.50% Senior Convertible Notes. The 3.50% Senior Convertible Notes
+mature on April 1, 2027, unless converted prior to maturity, redeemed, or
+purchased by the Company. The 3.50% Senior Convertible Notes are
+unsecured senior obligations and rank equal in right of payment with all of the
+Company’s existing and any future unsecured senior debt and are senior in right
+of payment to any future subordinated debt. 
+Holders
+may convert their notes based on a conversion rate of 18.3757 shares of the
+Company’s common stock per $1,000 principal amount of the 3.50% Senior
+Convertible Notes (which is equal to an initial conversion price of
+approximately $54.42 per share), subject to adjustment and contingent upon and
+only under the following circumstances: (1) if the closing price of the
+Company’s common stock reaches specified thresholds or the trading price of the
+notes falls below specified thresholds, (2) if the notes are called for
+redemption, (3) if specified distributions to holders of the Company’s common
+stock are made or specified corporate transactions occur, (4) if a fundamental
+change occurs, or (5) during the ten trading days prior to but excluding the
+maturity date. As of December 31, 2009, the notes and underlying
+shares had been registered under a shelf registration
+statement. Subsequent to year end the Company deregistered the shelf
+registration statement for the 3.50% Senior Convertible Notes. If the
+Company becomes involved in a material transaction or corporate development, it
+may suspend trading of the 3.50% Senior Convertible Notes under the
+prospectus. In the event the suspension period exceeds 45 days within
+any three-month period or 90 days within any twelve-month period, the Company
+will be required to pay additional interest to all holders of the 3.50% Senior
+Convertible Notes, not to exceed a rate per annum of 0.50 percent of the issue
+price of the 3.50% Senior Convertible Notes; provided that no such additional
+interest shall accrue after April 4, 2009. 
+Upon
+conversion of the 3.50% Senior Convertible Notes, holders will receive cash or
+common stock or any combination thereof as elected by the Company. At
+any time prior to the maturity date of the notes, the Company has the option to
+unilaterally and irrevocably elect to net share settle its obligations upon
+conversion of the notes in cash and, if applicable, shares of common
+stock. If the Company makes this election, then the Company will pay
+the following to holders for each $1,000 principal amount of notes converted in
+lieu of shares of common stock: (1) an amount in cash equal to the lesser of (i)
+$1,000 or (ii) the conversion value determined in the manner set forth in the
+indenture for the 3.50% Senior Convertible Notes, and (2) if the conversion
+value exceeds $1,000, the Company will also deliver, at its election, cash or
+common stock or a combination of cash and common stock with respect to the
+remaining value deliverable upon conversion. Currently, it is the
+Company’s intention to net share settle the 3.50% Senior Convertible
+Notes. However, the Company has not made this a formal legal
+irrevocable election and thereby reserves the right to settle the 3.50% Senior
+Convertible Notes in any manner allowed under the indenture as business
+conditions warrant. 
+If the
+holder elects to convert its notes in connection with certain events that
+constitute a change of control before April 1, 2012, the Company will pay, to
+the extent described in the related indenture, a make-whole premium by
+increasing the conversion rate applicable to the 3.50% Senior Convertible
+Notes. In addition, the Company will pay contingent interest in cash,
+commencing with any six-month period beginning on or after April 1, 2012,
+if the average trading price of a note for the five trading days ending on the
+third trading day immediately preceding the first day of the relevant six-month
+period equals 120 percent or more of the principal amount of the 3.50% Senior
+Convertible Notes. 
+F-22 
+On or
+after April 6, 2012, the Company may redeem for cash all or a portion of the
+3.50% Senior Convertible Notes at a redemption price equal to 100 percent of the
+principal amount of the notes to be redeemed plus accrued and unpaid interest,
+if any, up to but excluding the applicable redemption date. Holders
+of the 3.50% Senior Convertible Notes may require the Company to purchase all or
+a portion of their notes on each of April 1, 2012, April 1, 2017, and
+April 1, 2022, at a purchase price equal to 100 percent of the principal amount
+of the notes to be repurchased plus accrued and unpaid interest, if any,
+up to but excluding the applicable purchase date. On April 1, 2012,
+the Company may pay the purchase price in cash, in shares of common stock, or in
+any combination of cash and common stock. On April 1, 2017, and April
+1, 2022, the Company must pay the purchase price in cash. 
+New
+authoritative accounting guidance under FASB ASC Topic 470 
+Effective
+January 1, 2009, the new authoritative accounting guidance under ASC
+Topic 470 required issuers of convertible debt that may be settled fully or
+partially in cash upon conversion to account separately for the liability and
+equity components of the debt in a manner that reflects the entity’s
+nonconvertible debt borrowing rate when interest cost is recognized in
+subsequent periods. ASC Topic 470 applies to the Company’s 3.50%
+Senior Convertible Notes. Under the adoption provisions of ASC Topic
+470, the Company retrospectively applied its provisions and restated the
+Company’s consolidated financial statements for prior periods. 
+Under the
+provisions of ASC Topic 470, $42.0 million of the carrying value of the 3.50%
+Senior Convertible Notes was recorded as additional paid-in capital as of the
+April 4, 2007, issuance date. This amount represents the
+equity component of the proceeds from the 3.50% Senior Convertible Notes,
+calculated assuming a 7.0% discount rate, which is the estimate of what the
+Company’s borrowing rate for a similar debt instrument without the conversion
+feature would have been at the date of the issuance of the 3.50% Senior
+Convertible Notes. Upon retrospective application, the adoption
+resulted in a $6.8 million decrease in the Company’s retained earnings at
+December 31, 2008, which was comprised of non-cash interest expense of
+$10.8 million, net of capitalized interest of $2.2 million, less deferred taxes
+of $4.0 million, for the period from April 4, 2007, through
+December 31, 2008. The following table presents the
+December 31, 2008, consolidated balance sheet line items as adjusted
+and as originally reported: 
+As
+of December 31, 2008 
+As
+Adjusted 
+As
+Originally 
+Reported 
+(In
+thousands) 
+Proved
+oil and gas properties 
+$ 
+2,969,722 
+$ 
+2,967,491 
+Senior
+Convertible Notes 
+258,713 
+287,500 
+Noncurrent
+deferred income taxes 
+354,328 
+358,334 
+Additional
+paid-in capital 
+141,283 
+99,440 
+Retained
+earnings 
+957,200 
+964,019 
+F-23 
+As of
+December 31, 2009, and 2008, the carrying value of the equity
+component was $42.0 million. The principal amount of the 3.50%
+Senior Convertible Notes, the unamortized debt discount, and the net carrying
+amounts were as follows: 
+As
+of 
+December
+31, 2009 
+As
+of 
+December
+31, 2008 
+(As
+Adjusted) 
+(In
+thousands) 
+Senior
+Convertible Notes 
+$ 
+287,500 
+$ 
+287,500 
+Unamortized
+debt discount 
+(20,598 
+) 
+(28,787 
+) 
+Net
+carrying amount of the 3.50% Senior Convertible Notes 
+$ 
+266,902 
+$ 
+258,713 
+The
+Company amortized $8.2 million, $7.6 million, and $5.4 million of the debt
+discount for the years ended December 31, 2009, 2008, and 2007,
+respectively. Accumulated amortization related to the debt discount
+was $21.2 million and $13.0 million for the years ended December 31, 2009, and
+2008, respectively. The remaining unamortized debt discount
+will be amortized through March 2012 using the interest method. 
+The
+consolidated statements of operations were retrospectively adjusted compared to
+previously reported amounts as follows: 
+For
+the Year Ended 
+December
+31, 2008 
+For
+the Year Ended 
+December
+31, 2007 
+As
+Adjusted 
+As
+Originally 
+Reported 
+As
+Adjusted 
+As
+Originally 
+Reported 
+(In
+thousands, except per share amounts) 
+Interest
+expense 
+$ 
+26,950 
+$ 
+20,275 
+$ 
+24,046 
+$ 
+19,895 
+Income
+tax expense 
+57,388 
+59,858 
+109,013 
+110,550 
+Net
+income 
+87,348 
+91,553 
+187,098 
+189,712 
+Basic
+net income per common share 
+$ 
+1.40 
+$ 
+1.47 
+$ 
+3.02 
+$ 
+3.07 
+Diluted
+net income per common share 
+$ 
+1.38 
+$ 
+1.45 
+$ 
+2.90 
+$ 
+2.94 
+Weighted-Average
+Interest Rate Paid and Capitalized Interest 
+The
+weighted-average interest rate paid in 2009, 2008, and 2007, was 5.4 percent,
+5.8 percent, and 6.7 percent, respectively, including commitment fees paid
+on the unused portion of the credit facility aggregate commitment, amortization
+of deferred financing costs, amortization of debt discount, amortization of the
+contingent interest embedded derivative associated with the 5.75% Senior
+Convertible Notes for 2007, and the effect of interest rate
+swaps. The average outstanding loan balance in 2009 increased in
+comparison to the average outstanding loan balance in 2008, while the rates
+associated with the balances decreased. The decrease is attributed to
+significantly lower LIBOR and Prime rates in 2009 compared to
+2008. Capitalized interest costs for the Company for the years ended
+December 31, 2009, 2008, and 2007, were $1.9 million, $4.7 million, and
+$6.7 million, respectively. 
+F-24 
+Note
+6 – Commitments and Contingencies 
+The
+Company has entered into various operating leases, which include drilling rig
+contracts, of approximately $20.5 million, office space leases including
+maintenance of approximately $34.5 million, compressor contracts of
+approximately $2.7 million, and vehicle leases of approximately $2.3
+million. The annual minimum lease payments for the next five years
+and thereafter are presented below: 
+Years
+Ending December 31, 
+(In
+thousands) 
+2010 
+$ 
+27,779 
+2011 
+6,438 
+2012 
+3,249 
+2013 
+2,973 
+2014 
+2,367 
+Thereafter 
+18,275 
+Total 
+$ 
+61,081 
+The
+Company leases office space under various operating leases with terms extending
+as far as May 31, 2022. Rent expense, net of sublease
+income, was $2.3 million, $2.4 million, and $1.9 million in 2009, 2008, and
+2007, respectively. The Company also leases office equipment under various
+operating leases. As of December 31, 2009, the Company has a sublease
+through May 2012 with payments due to St. Mary of $185,000 per year
+through 2011 and $62,000 in 2012. This sublease was terminated
+on January 15, 2010. 
+The
+Company is subject to litigation and claims that have arisen in the ordinary
+course of business. The Company accrues for such items when a liability is both
+probable and the amount can be reasonably estimated. In the opinion
+of management, the results of such pending litigation and claims will not have a
+material effect on the results of operations, the financial position, or cash
+flows of the Company. 
+Note
+7 – Compensation Plans 
+Cash
+Bonus Plan 
+The
+Company has a cash bonus plan based on a performance measurement framework
+whereby selected eligible employee participants may be awarded an annual cash
+bonus. The plan document provides that no participant may receive an
+annual bonus under the plan of more than 200 percent of his or her base
+salary. As the plan is currently administered, any awards under the
+plan are based on Company and regional performance, and are then further refined
+by individual performance. The Company accrues cash bonus expense
+based upon the Company’s current year’s performance. Included
+in general and administrative and exploration expense in the
+accompanying consolidated statements of operations are $7.8 million, $6.4
+million, and $3.6 million of cash bonus expense related to the specific
+performance year for the years ended December 31, 2009, 2008, and
+2007, respectively. 
+Equity
+Incentive Compensation Plan 
+There are
+several components to the equity compensation plan that are described in this
+section. Various types of equity awards have been granted by the
+Company in different periods. These disclosures reflect the
+disclosure requirements for all equity awards still outstanding. 
+In May
+2006 the stockholders approved the 2006 Equity Incentive Compensation Plan,
+which was subsequently renamed the Equity Incentive Compensation Plan (the
+“Equity Plan”), to authorize the issuance of restricted stock, RSUs,
+non-qualified stock options, incentive stock options, stock appreciation rights,
+and stock-based awards to key employees, consultants, and members of the Board
+of Directors of St. Mary or any affiliate of St. Mary. The Equity
+Plan serves as the successor to the St. Mary Land & Exploration Company
+Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock
+Option Plan, the St. Mary Land & Exploration 
+F-25 
+Company
+Restricted Stock Plan, and the St. Mary Land & Exploration Company
+Non-Employee Director Stock Compensation Plan (collectively referred to as the
+“Predecessor Plans”). All grants of equity are now made pursuant to
+the Equity Plan, and no further grants will be made under the Predecessor
+Plans. Each outstanding award under the Predecessor Plans prior to
+the effective date of the Equity Plan continues to be governed solely by the
+terms and conditions of the instruments evidencing such grants or
+issuances. An amendment and restatement of the Equity Plan was
+approved by the Company’s stockholders at the 2008 annual stockholders’ meeting
+held on May 21, 2008. The Equity Plan was further amended at the
+2009 annual stockholders’ meeting held on May 20, 2009.
+As of
+December 31, 2009, 1.8 million shares of common stock remained available for
+grant under the Equity Plan. The issuance of a direct share benefit
+such as an outright grant of common stock, a grant of a restricted share, a RSU
+grant, or a PSA grant, counts as 1.43 shares against the number of shares
+available to be granted under the Equity Plan. At the end of a
+three-year performance period a final multiplier ranging between zero and two is
+applied to each PSA so that each performance share granted has the potential to
+result in the issuance of two shares of common stock. Consequently,
+each performance share granted counts as 2.86 shares against the number of
+shares available to be granted under the Equity Plan. Stock option
+grants count as one share for each instrument granted against the number of
+shares available to be granted under the Equity Plan. The Company has
+outstanding stock option awards under the Predecessor Plans. 
+Performance
+Share Awards Under the Equity Incentive Compensation Plan 
+In 2007,
+PSAs became the primary form of long-term equity incentive compensation
+replacing standalone RSU grants and awards of interest in pools under the Net
+Profits Plan. PSAs represent the right to receive a
+share of the Company’s common stock which can be multiplied by a
+factor ranging from zero to two times the number of PSAs granted on the award
+date depending on the Company’s performance after completion of a three-year
+performance period. The performance criteria for the PSAs are based
+on a combination of the Company’s cumulative TSR for the performance period and
+the relative measure of the Company’s TSR compared with the cumulative TSR of an
+index comprised of certain peer companies for the performance
+period. 
+On August
+1, 2009, the Company granted 725,092 PSAs with a performance period ending June
+30, 2012. The PSAs will vest 1/7 th on
+August 1, 2010, 2/7 ths on
+August 1, 2011, and 4/7 ths on
+August 1, 2012. The fair value of the Company’s PSAs granted on
+August 1, 2009, was $25.8 million and is being recognized as general and
+administrative and exploration expense over the vesting period of the
+award. 
+On August
+1, 2008, the Company granted 465,751 PSAs with a performance period ending June
+30, 2011. The PSAs will vest 1/7 th on
+August 1, 2009, 2/7 ths on
+August 1, 2010, and 4/7 ths on
+August 1, 2011. The fair value of the Company’s PSAs granted on
+August 1, 2008, was $12.3 million and is being recognized as general and
+administrative and exploration expense over the vesting period of the
+award. 
+In
+measuring compensation expense related to the grant of PSAs, the Company
+estimates the fair value of the award on the grant date. The fair
+value of PSAs is measured by a stochastic process method using the Geometric
+Brownian Motion Model (“GBM Model”). A stochastic process is a
+mathematically defined equation that can create a series of outcomes over
+time. These outcomes are not deterministic in nature, which means
+that by iterating the equations multiple times, different results will be
+obtained for those iterations. In the case of the Company’s PSAs, the
+Company cannot predict with certainty the path its stock price or the stock
+prices of its peers will take over the three-year performance
+period. By using a stochastic simulation the Company can create
+multiple prospective stock pathways, statistically analyze these simulations,
+and ultimately make inferences to the most likely path the stock price will
+take. As such, because future stock prices are stochastic, or
+probabilistic with some direction in nature, the stochastic method, specifically
+the GBM Model is deemed an appropriate method by which to determine the fair
+value of the PSAs. 
+F-26 
+A summary
+of the status and activity of PSAs for the years ending December 31, 2009, and
+2008, is presented in the following table: 
+2009 
+2008 
+PSAs 
+Weighted-Average
+Grant-Date Fair Value 
+PSAs 
+Weighted-Average
+Grant-Date Fair Value 
+Non-vested
+at beginning of year 
+464,333 
+$ 
+26.48 
+- 
+$ 
+- 
+Granted 
+725,092 
+$ 
+35.59 
+465,751 
+$ 
+26.48 
+Vested (1) 
+(76,781 
+) 
+$ 
+27.20 
+- 
+$ 
+- 
+Forfeited 
+(43,554 
+) 
+$ 
+28.62 
+(1,418 
+) 
+$ 
+26.48 
+Non-vested
+at end of year 
+1,069,090 
+$ 
+32.52 
+464,333 
+$ 
+26.48 
+(1) 
+The number of shares vested represents 1/7 th 
+of the August 1, 2008 , PSA grant
+assuming a one multiplier. The final number of shares vested
+may vary 
+depending
+on the ending three-year multiplier, which ranges from zero to
+two. 
+The total
+fair value of PSAs that vested during the year ended December 31, 2009, was $1.8
+million. General and administrative and exploration expense recorded
+for PSAs was $9.3 million and $2.5 million for the years ended December 31,
+2009, and 2008, respectively. As of December 31, 2009, there was
+$25.0 million of total unrecognized expense related to PSAs, which is being
+amortized through 2012. 
+Restricted
+Stock Incentive Program Under the Equity Incentive Compensation
+Plan 
+The
+Company historically had a long-term incentive program whereby grants of
+restricted stock or RSUs were awarded to eligible employees, consultants, and
+members of the Board of Directors. Restrictions and vesting
+periods for the awards were determined at the discretion of the Board of
+Directors and were set forth in the award agreements. Each RSU
+represents a right for one share of the Company’s common stock to be delivered
+upon settlement of the award at the end of a specified period. These
+grants were determined annually based on the same Company performance formula
+used to determine the annual cash bonus. RSUs were also issued in
+2008 as the Company transitioned to using PSAs as the primary long-term equity
+incentive compensation awards and again in 2009 as a component of the Company’s
+long-term equity incentive compensation program. 
+The
+Company issued 241,745 RSUs on August 1, 2009, with a weighted-average
+grant-date fair value of $23.87 with a total fair value of $5.8
+million. These RSUs vest 1/7 th on
+August 1, 2010, 2/7 ths on
+August 1, 2011, and 4/7 ths on
+August 1, 2012 and is being recognized as general and administrative
+and exploration expense over the vesting period of the award. 
+St. Mary issued 265,373 RSUs on June 30, 2008, as a transitional
+award to employees when the Company moved from the legacy equity incentive
+compensation plan to the new PSA program. The total fair value
+associated with this issuance was $17.2 million as measured on the grant
+date. The granted RSUs vest one third on each date of December
+15 th 
+2008, 2009, and 2010. General and administrative and exploration
+expense is recorded over the vesting period of the award. 
+The
+Company issued 158,744 RSUs on February 28, 2008, related to 2007 performance,
+and 78,657 RSUs on February 28, 2007, related to 2006
+performance. The total fair value associated with these issuances was
+$6.0 million for the 2008 grant and $2.5 million for the 2007 issuance as
+measured on the respective grant dates. These granted RSUs vested 25
+percent immediately upon grant and 25 percent on each of the first three
+anniversary dates of the grant. The fair values of these awards are
+being recognized as general and administrative and exploration expense over the
+vesting period of the awards. 
+The
+Company issued an additional 4,290 and 23,977 RSUs to certain employees during
+2008 and 2007, respectively. The total fair value associated with the
+2008 and 2007 issuances was $164,000 and $803,000, respectively, as measured on
+the respective grant dates. These grants have various vesting
+schedules. 
+F-27 
+For RSUs
+awarded prior to 2006, vested shares of common stock underlying the RSU grants
+were issued on the third anniversary of the grant, at which time the shares
+carried no further restrictions. On December 31, 2007 the Company
+eliminated the restriction period that extends beyond the vesting period so
+shares are now issued without restriction upon vesting, rather than on the third
+anniversary of the award for all awards granted after 2005. Therefore
+the fair value of a RSU award granted after December 31, 2007, is equal to the
+market value of the underlying stock on the date of the grant. This
+change fell within the safe harbor adoption provisions of the U.S. Treasury
+regulations interpreting IRC provisions governing deferred
+compensation. A mutual election of the employee and the Company was
+required to effect this change for each outstanding award. The
+majority of the awards were modified by mutual election, and as such, the
+incremental value associated with removal of this restriction period was
+$556,000 and is being amortized over the remaining respective service
+periods for these awards. 
+For
+grants made beginning with the 2006 grant period, the Company is using the
+accelerated amortization method whereby approximately 48 percent of the total
+estimated compensation expense is recognized in the first year of the vesting
+period. As of December 31, 2009, a total of 408,356 RSUs were
+outstanding, of which 1,233 were vested. The total general and
+administrative and exploration expense associated with RSUs for the years ended
+December 31, 2009, 2008, and 2007, was $7.9 million , 
+$11.0 million, and $8.4 million, respectively. As of December
+31, 2009, there was $10.0 million of total unrecognized expense related to
+unvested RSU awards and is being amortized through 2012 . 
+During
+2009, 2008, and 2007, the Company converted 215,700 , 678,197, and
+427,059 RSUs, respectively. The Company and the majority of grant
+participants mutually agreed to net share settle the awards to cover income and
+payroll tax withholdings as provided for in the plan document and award
+agreements. As a result, the Company issued net shares of common
+stock of 156,252; 482,602; and 302,370 for 2009, 2008, and 2007,
+respectively. The remaining 59,448, 195,595, and 124,689 shares were
+withheld to satisfy income and payroll tax withholding obligations that occurred
+upon the delivery of the shares underlying those RSUs for 2009, 2008, and 2007,
+respectively. 
+In
+accordance with ASC Topic 718, when measuring compensation expense related to
+the grant of RSUs the Company estimates the fair value of the award on the grant
+date. For grants prior to January 1, 2008, the Company had a
+restriction period beyond vesting. Therefore, the fair value of the
+RSUs was inherently less than the market value of an unrestricted share of St.
+Mary’s common stock. The fair value of RSUs with restriction periods
+beyond the vesting dates were measured using the Black-Sholes option-pricing
+model. The Company’s computation of expected volatility was based on
+the historic volatility of St. Mary’s common stock. The Company’s
+computation of expected life was determined based on historical experience of
+similar awards, giving consideration to the contractual terms of the awards,
+vesting schedules, and expectations of future employee behavior. The
+interest rate for periods within the contractual life of the award was based on
+the U.S. Treasury constant maturity yield at the time of the grant. 
+The fair
+values of RSU awards granted prior to January 1, 2008, were estimated using the
+following weighted-average assumptions: 
+For
+the Year Ended December 31, 2007 
+Risk
+free interest rate 
+4.5% 
+Dividend
+yield 
+0.3% 
+Volatility
+factor of the expected market 
+price
+of the Company’s common stock 
+32.0% 
+Expected
+life of the awards (in years) 
+3 
+F-28 
+Stock
+Awards Under the Equity Incentive Compensation Plan 
+As part
+of hiring a new senior executive in the second quarter of 2006, St. Mary granted
+a special common stock award of 20,000 shares that vested immediately upon
+commencement of employment. The fair value associated with this award
+was $727,600. In addition to this award, the employee will earn an
+additional 5,000 shares over a four-year period and an additional 15,000 shares
+contingent on the Company meeting certain net asset growth performance
+conditions over a four-year period. In 2009, 2008, and 2007 the
+Company issued 1,250, 3,750, and 1,250 worth of guaranteed and contingent shares
+with associated fair values of $45,000, $142,000, and $45,000,
+respectively. The fair value of these awards is being recorded as
+compensation expense over the vesting period. 
+As part
+of hiring a new senior executive in the third quarter of 2008, St. Mary granted
+a special restricted stock award of 15,496 shares that vested one half on
+December 15, 2009, and the other half will vest on December 15,
+2010. The fair value of this award was $600,005 and is being recorded
+as compensation expense over the vesting period. For the years ended
+December 31, 2009, and 2008, the Company recorded general and administrative and
+exploration expense of $358,000 and $115,000, respectively, related to this
+award. 
+A summary
+of the status and activity of non-vested stock awards and RSUs for the years
+ending December 31, 2009, 2008, and 2007, is presented
+below: 
+2009 
+2008 
+2007 
+Stock
+Awards and RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair
+Value 
+Stock
+Awards and RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair
+Value 
+Stock
+Awards and RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair
+Value 
+Non-vested
+at beginning of year 
+402,297 
+$ 
+48.24 
+289,385 
+$ 
+32.26 
+506,161 
+$ 
+28.92 
+Granted 
+241,745 
+$ 
+23.87 
+443,903 
+$ 
+53.81 
+102,634 
+$ 
+32.45 
+Vested 
+(211,092 
+) 
+$ 
+46.26 
+(291,659 
+) 
+22.92 
+(268,123 
+) 
+25.94 
+Forfeited 
+(25,827 
+) 
+$ 
+50.35 
+(39,332 
+) 
+$ 
+37.82 
+(51,287 
+) 
+$ 
+31.77 
+Non-vested
+at end of year 
+407,123 
+$ 
+34.67 
+402,297 
+$ 
+48.24 
+289,385 
+$ 
+32.26 
+The total
+fair value of RSUs that vested during the years ended December 31, 2009, 2008,
+and 2007, was $4.9 million, $9.4 million, and $9.8 million,
+respectively. 
+ASC Topic
+718 requires cash flows resulting from excess tax benefits to be classified as
+part of cash flows from financing activities. Excess tax benefits are
+realized tax benefits from tax deductions for vested RSUs and exercised options
+in excess of the deferred tax asset attributable to stock compensation costs for
+such RSUs and options. The Company has recorded $13.9 million and
+$9.9 million of excess tax benefits for the years ended
+December 31, 2008, and 2007, respectively, as cash inflows from
+financing activities. The Company recorded no excess tax benefits for
+the year ended December 31, 2009. Cash received from exercises under
+all share-based payment arrangements for the years ended December 31, 2009,
+2008, and 2007, was $1.6 million, $10.8 million, and $9.1 million,
+respectively. 
+F-29 
+Stock
+Option Grants Under the Equity Incentive Compensation Plan 
+The
+Company has previously granted stock options under the St. Mary Land &
+Exploration Company Stock Option Plan and the St. Mary Land & Exploration
+Company Incentive Stock Option Plan. The last issuance of stock
+options was December 31, 2004. Stock options to purchase shares of
+the Company’s common stock had been granted to eligible employees and members of
+the Board of Directors. All options granted to date under the option
+plans have been granted at exercise prices equal to the respective closing
+market price of the Company’s underlying common stock on the grant
+dates. All stock options granted under the option plans are
+exercisable for a period of up to ten years from the date of grant. 
+During
+the years ended December 31, 2008, and 2007, the Company recognized general and
+administrative and exploration expense of $17,000 and $437,000, respectively,
+related to stock options that were outstanding and unvested upon adoption of ASC
+Topic 718 on January 1, 2006. There was no expense associated with
+stock options or unvested stock options outstanding for the year ended December
+31, 2009. 
+A summary
+of activity associated with the Company’s Stock Option Plans during the last
+three years is presented in the following table: 
+Weighted
+- 
+Aggregate 
+Average 
+Intrinsic 
+Shares 
+Exercise
+Price 
+Value 
+For
+the year ended December 31, 2007 
+Outstanding,
+start of year 
+3,121,602 
+$ 
+12.56 
+Granted 
+- 
+- 
+Exercised 
+(733,650 
+) 
+$ 
+12.38 
+Forfeited 
+(2,452 
+) 
+$ 
+7.34 
+Outstanding,
+end of year 
+2,385,500 
+$ 
+12.62 
+$ 
+62,007,749 
+Vested,
+or expected to vest, end of year 
+2,385,500 
+$ 
+12.62 
+$ 
+62,007,749 
+Exercisable,
+end of year 
+2,378,000 
+$ 
+12.62 
+$ 
+61,814,737 
+For
+the year ended December 31, 2008 
+Outstanding,
+start of year 
+2,385,500 
+$ 
+12.62 
+Granted 
+- 
+- 
+Exercised 
+(868,372 
+) 
+$ 
+12.47 
+Forfeited 
+(7,418 
+) 
+$ 
+13.39 
+Outstanding,
+end of year 
+1,509,710 
+$ 
+12.69 
+$ 
+11,529,600 
+Vested,
+or expected to vest, end of year 
+1,509,710 
+$ 
+12.69 
+$ 
+11,529,600 
+Exercisable,
+end of year 
+1,509,710 
+$ 
+12.69 
+$ 
+11,529,600 
+For
+the year ended December 31, 2009 
+Outstanding,
+start of year 
+1,509,710 
+$ 
+12.69 
+Granted 
+- 
+- 
+Exercised 
+(189,740 
+) 
+$ 
+8.40 
+Forfeited 
+(45,050 
+) 
+$ 
+13.38 
+Outstanding,
+end of year 
+1,274,920 
+$ 
+13.31 
+$ 
+26,684,106 
+Vested,
+or expected to vest, end of year 
+1,274,920 
+$ 
+13.31 
+$ 
+26,684,106 
+Exercisable,
+end of year 
+1,274,920 
+$ 
+13.31 
+$ 
+26,684,106 
+F-30 
+A summary
+of additional information related to options outstanding as of December 31,
+2009, follows: 
+Options
+Outstanding and Exercisable 
+Number 
+Weighted- 
+Of
+Options 
+Average 
+Weighted- 
+Outstanding 
+Remaining 
+Average 
+Range
+of 
+and 
+Contractual 
+Exercise 
+Exercise
+Prices 
+Exercisable 
+Life 
+Price 
+$ 
+7.97 
+- 
+$ 
+10.86 
+192,230 
+2.0
+years 
+$ 
+10.05 
+11.95 
+- 
+12.03 
+176,035 
+2.6
+years 
+11.99 
+12.08 
+- 
+12.08 
+13,080 
+2.4
+years 
+12.08 
+12.50 
+- 
+12.50 
+143,378 
+3.0
+years 
+12.50 
+12.53 
+- 
+12.66 
+204,202 
+3.5
+years 
+12.58 
+13.39 
+- 
+13.39 
+30,593 
+3.8
+years 
+13.39 
+13.65 
+- 
+13.65 
+126,839 
+3.5
+years 
+13.65 
+14.25 
+- 
+14.25 
+188,531 
+4.0
+years 
+14.25 
+16.66 
+- 
+16.66 
+141,400 
+1.0
+years 
+16.66 
+20.87 
+- 
+20.87 
+58,632 
+5.0
+years 
+20.87 
+Total 
+1,274,920 
+The fair
+value of options was measured at the date of grant using the Black-Scholes
+option-pricing model. 
+Director
+Shares 
+In 2009,
+2008, and 2007, the Company issued 50,094 , 23,113, and
+32,504 shares, respectively, of restricted common stock from treasury to its
+non-employee directors pursuant to the Company’s Equity Plan. The
+Company recorded general and administrative and exploration expense related to
+the issuances of shares to non-employee directors of $688,000, $1.0 million, and
+$984,000 for the years ended December 31, 2009, 2008, and 2007,
+respectively. 
+Employee
+Stock Purchase Plan 
+Under the
+St. Mary Land & Exploration Company Employee Stock Purchase Plan (“the
+ESPP”), eligible employees may purchase shares of the Company’s common stock
+through payroll deductions of up to 15 percent of eligible
+compensation. The purchase price of the stock is 85 percent of the
+lower of the fair market value of the stock on the first or last day of the
+six-month offering period, and shares issued under the ESPP through December 31,
+2009, are restricted for a period of 18 months from the date
+issued. Effective January 1, 2010, shares issued under the ESPP will
+be restricted for a six month period from the date issued. The ESPP
+is intended to qualify under Section 423 of the IRC. The Company has
+set aside 2,000,000 shares of its common stock to be available for issuance
+under the ESPP, of which 1,468,275 shares are available for issuance as of
+December 31, 2009. Shares issued under the ESPP totaled 86,308 in
+2009, 45,228 in 2008, and 29,534 in 2007. Total proceeds to the
+Company for the issuance of these shares was $1.5 million in 2009, $1.1
+million in 2008, and $919,000 in 2007. 
+F-31 
+The fair
+value of ESPP shares are measured at the date of grant using the Black-Scholes
+option-pricing model. The fair values of ESPP shares issued during
+the periods reported were estimated using the following weighted-average
+assumptions: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+Risk
+free interest rate 
+0.3% 
+1.2% 
+4.1% 
+Dividend
+yield 
+0.5% 
+0.2% 
+0.3% 
+Volatility
+factor of the expected market 
+price
+of the Company’s common stock 
+95.14% 
+81.5% 
+27.2% 
+Expected
+life (in years) 
+0.5 
+0.5 
+0.5 
+The
+Company expensed $848,000, $307,000, and $260,000 for the years ended December
+31, 2009, 2008, and 2007, respectively, based on the estimated fair
+value of grants on the respective grant dates. 
+401(k)
+Plan 
+The
+Company has a defined contribution pension plan (the “401(k) Plan”) that is
+subject to the Employee Retirement Income Security Act of 1974. The
+401(k) Plan allows eligible employees to contribute up to 60 percent of their
+base salaries. The Company matches each employee’s contribution up to
+six percent of the employee’s base salary and may make additional contributions
+at its discretion. The Company’s contributions to the 401(k) Plan
+were $2.5 million, $2.0 million, and $1.5 million for the years ended December
+31, 2009, 2008, and 2007, respectively. No discretionary
+contributions were made by the Company to the 401(k) Plan for any of these
+years. 
+Net
+Profits Plan 
+Under the
+Company’s Net Profits Plan, all oil and gas wells that were completed or
+acquired during a year were designated within a specific pool. Key
+employees recommended by senior management and designated as participants by the
+Company’s Compensation Committee of the Board of Directors and employed by the
+Company on the last day of that year became entitled to payments under the Net
+Profits Plan after the Company has received net cash flows returning
+100 percent of all costs associated with that pool. Thereafter,
+ten percent of future net cash flows generated by the pool are allocated
+among the participants and distributed at least annually. The portion
+of net cash flows from the pool to be allocated among the participants increases
+to 20 percent after the Company has recovered 200 percent of the total
+costs for the pool, including payments made under the Net Profits Plan at the
+ten percent level. In December 2007 the Board discontinued the
+creation of new pools under the Net Profits Plan. Consequently, the
+2007 Net Profits Plan pool was the last pool established by the
+Company. All pools are fully vested as of December 31,
+2009. 
+Cash
+payments made under the Net Profits Plan that have been recorded as either
+general and administrative expense or exploration expense are detailed in the
+table below: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+General
+and administrative expense 
+$ 
+18,399 
+$ 
+29,713 
+$ 
+25,030 
+Exploration
+expense 
+1,463 
+6,604 
+6,881 
+Total 
+$ 
+19,862 
+$ 
+36,317 
+$ 
+31,911 
+F-32 
+Additionally,
+the Company made cash payments under the Net Profits Plan of $724,000 for the
+year ended December 31, 2009, as a result of sales proceeds from properties sold
+during the fourth quarter of 2009. For the year ended December
+31, 2008, the Company made cash payments under the Net Profits Plan of $15.1
+million as a result of sales proceeds from the Abraxas and Greater Green River
+Basin divestitures. The cash payments are accounted for as a
+reduction in the gain (loss) on divestiture activity in the accompanying
+consolidated statements of operations. There were no significant cash
+payments made under the Net Profits Plan as the result of property divestitures
+during 2007. 
+The
+Company records changes in the present value of estimated future payments under
+the Net Profits Plan as a separate line item in the accompanying consolidated
+statements of operations. The change in the estimated liability is
+recorded as a non-cash expense or benefit in the current period. The
+amount recorded as an expense or benefit associated with the change in the
+estimated liability is not allocated to general and administrative expense or
+exploration expense because it is associated with the future net cash flows from
+oil and gas properties in the respective pools rather than results being
+realized through current period production. The table below presents
+the estimated allocation of the change in the liability if the Company did
+allocate the adjustment to these specific functional line items based on the
+current allocation of actual distributions made by the Company. As
+time progresses, less of the distributions relate to prospective exploration
+efforts as more of the distributions are made to employees that have terminated
+employment and do not provide ongoing exploration support to the
+Company. 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+General
+and administrative expense (benefit) 
+$ 
+(6,572 
+) 
+$ 
+(29,672 
+) 
+$ 
+39,866 
+Exploration
+expense (benefit) 
+(503 
+) 
+(4,368 
+) 
+10,957 
+Total 
+$ 
+(7,075 
+) 
+$ 
+(34,040 
+) 
+$ 
+50,823 
+Note
+8 – Pension Benefits 
+New
+authoritative accounting guidance under FASB ASC Topic 715 
+Effective
+January 1, 2009, new authoritative accounting guidance under FASB ASC Topic 715,
+“Compensation – Retirement Benefits” (“ASC Topic 715”) amends the disclosure
+requirements of plan assets for defined benefit pensions and other
+postretirement plans. The objective of ASC Topic 715 is to provide
+users of financial statements with an understanding of how investment allocation
+decisions are made, the major categories of plan assets held by the plans, the
+inputs and valuation techniques used to measure the fair value of plan assets,
+significant concentration of risk within a company’s plan assets, fair value
+measurements determined using significant unobservable inputs, and a
+reconciliation of changes between the beginning and ending balances for all
+level 3 inputs. 
+Pension
+Plans 
+The
+Company has a non-contributory defined benefit pension plan covering
+substantially all employees who meet age and service requirements (the
+“Qualified Pension Plan”). The Company also has a supplemental
+non-contributory pension plan covering certain management employees (the
+“Nonqualified Pension Plan”). 
+The
+Company recognizes the funded status (i.e., the difference between the fair
+value of plan assets and the projected benefit obligation) of the Company’s
+pension plan in the consolidated balance sheets as either an asset or a
+liability and recognizes a corresponding adjustment to accumulated other
+comprehensive income, net of tax. The projected benefit obligation is
+the actuarial present value of the benefits earned to date by plan participants
+based on employee service and compensation including the effect of assumed
+future salary increases. The accumulated benefit obligation uses the
+same factors as the projected benefit obligation but excludes the 
+F-33 
+effects
+of assumed future salary increases. The Company’s measurement date
+for plan assets and obligations is December 31. 
+Obligations
+and Funded Status for Both Pension Plans 
+For
+the Years Ended December 31, 
+2009 
+2008 
+(In
+thousands) 
+Change
+in benefit obligations 
+Projected
+benefit obligation at beginning of year 
+$ 
+14,786 
+$ 
+14,744 
+Service
+cost 
+2,500 
+2,229 
+Interest
+cost 
+934 
+889 
+Actuarial
+(gain) loss 
+1,275 
+(166 
+) 
+Benefits
+paid 
+(945 
+) 
+(2,910 
+) 
+Projected
+benefit obligation at end of year 
+$ 
+18,550 
+$ 
+14,786 
+Change
+in plan assets 
+Fair
+value of plan assets at beginning of year 
+$ 
+6,552 
+$ 
+8,755 
+Actual
+return on plan assets 
+1,466 
+(1,782 
+) 
+Employer
+contribution 
+2,028 
+2,489 
+Benefits
+paid 
+(945 
+) 
+(2,910 
+) 
+Fair
+value of plan assets at end of year 
+$ 
+9,101 
+$ 
+6,552 
+Funded
+status at end of year 
+$ 
+9,449 
+$ 
+8,234 
+The
+Company’s underfunded status for the Pension Plans for the years ended December
+31, 2009, and 2008, is $9.4 million and $8.2 million, respectively, and is
+recognized in the accompanying consolidated balance sheets as a portion of other
+noncurrent liabilities. No plan assets of the Qualified Pension Plan
+are expected to be returned to the Company during the fiscal year ended December
+31, 2009. There are no plan assets in the Nonqualified Pension
+Plan. 
+Information
+for Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets
+for Both Plans 
+As
+of December 31, 
+2009 
+2008 
+(In
+thousands) 
+Projected
+benefit obligation 
+$ 
+18,550 
+$ 
+14,786 
+Accumulated
+benefit obligation 
+$ 
+13,278 
+$ 
+9,922 
+Less:
+Fair value of plan assets 
+9,101 
+6,552 
+Underfunded
+accumulated benefit obligation 
+$ 
+4,177 
+$ 
+3,370 
+Pension
+expense is determined based upon the annual service cost of benefits (the
+actuarial cost of benefits earned during a period) and the interest cost on
+those liabilities, less the expected return on plan assets. The
+expected long-term rate on plan assets is applied to a calculated value of plan
+assets that recognizes changes in fair value over a five-year
+period. This practice is intended to reduce year-to-year volatility
+in pension expense, but it can have the effect of delaying recognition of
+differences between actual returns on assets and expected returns based on
+long-term rate of return assumptions. Amortization of unrecognized
+net gain or loss resulting from experience different from that assumed and from
+changes in assumptions (excluding asset gains and losses not yet reflected in
+market-related value) is included as a component of net periodic benefit cost
+for a year. If, as of the beginning of the year, that unrecognized
+net gain or loss exceeds ten percent of the greater of the projected
+benefit 
+F-34 
+obligation and the market-related value of plan assets, the
+amortization is that excess divided by the average remaining service period of
+participating employees expected to receive benefits under the plan. 
+Pre-tax
+amounts not yet recognized in net periodic pension costs, but rather recognized
+in accumulated other comprehensive income as of December 31, 2009, and 2008,
+consist of: 
+As
+of December 31, 
+2009 
+2008 
+(In
+thousands) 
+Unrecognized
+actuarial losses 
+$ 
+4,322 
+$ 
+4,441 
+Unrecognized
+prior service costs 
+- 
+- 
+Unrecognized
+transition obligation 
+- 
+- 
+Accumulated
+other comprehensive income 
+$ 
+4,322 
+$ 
+4,441 
+The estimated
+net loss that will be amortized from accumulated other comprehensive income
+into net periodic benefit cost over the next fiscal year is
+$267,000. 
+Other
+pre-tax changes recognized in other comprehensive income during 2009, 2008, and
+2007, were as follows: 
+As
+of December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Net
+actuarial gain (loss) 
+$ 
+(239 
+) 
+$ 
+(2,181 
+) 
+$ 
+(99 
+) 
+Less:
+Amortization of: 
+Prior
+service cost 
+- 
+- 
+- 
+Actuarial
+gain (loss) 
+(358 
+) 
+(240 
+) 
+(218 
+) 
+Total
+other comprehensive income 
+$ 
+119 
+$ 
+(1,941 
+) 
+$ 
+119 
+Components
+of Net Periodic Benefit Cost for Both Pension Plans 
+For
+the Year Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Components
+of net periodic benefit cost 
+Service
+cost 
+$ 
+2,500 
+$ 
+2,229 
+$ 
+1,911 
+Interest
+cost 
+934 
+889 
+793 
+Expected
+return on plan assets that reduces periodic pension cost 
+(430 
+) 
+(565 
+) 
+(540 
+) 
+Amortization
+of prior service cost 
+- 
+- 
+- 
+Amortization
+of net actuarial loss 
+372 
+248 
+218 
+Net
+periodic benefit cost 
+$ 
+3,376 
+$ 
+2,801 
+$ 
+2,382 
+Prior
+service costs are amortized on a straight-line basis over the average remaining
+service period of active participants. Gains and losses in excess of
+ten percent of the greater of the benefit obligation and the market-related
+value of assets are amortized over the average remaining service period of
+active participants. 
+F-35 
+Pension
+Plan Assumptions 
+Weighted-average
+assumptions to measure the Company’s projected benefit obligation and net
+periodic benefit cost are as follows: 
+As
+of December 31, 
+2009 
+2008 
+2007 
+Projected benefit
+obligation 
+Discount
+rate 
+6.1% 
+6.6% 
+6.1% 
+Rate
+of compensation increase 
+6.2% 
+6.2% 
+6.2% 
+Net periodic benefit cost 
+Discount
+rate 
+6.6% 
+6.1% 
+5.9% 
+Expected
+return on plan assets 
+7.5% 
+7.5% 
+7.5% 
+Rate
+of compensation increase 
+6.2% 
+6.2% 
+6.2% 
+The
+Company’s pension investment policy includes various guidelines and procedures
+designed to ensure that assets are prudently invested in a manner necessary to
+meet the future benefit obligation of the Pension Plans. The policy
+does not permit the direct investment of plan assets in the Company’s
+securities. The Company’s investment horizon is long-term and
+accordingly the target asset allocations encompass a strategic, long-term
+perspective of capital markets, expected risk and return behavior and perceived
+future economic conditions. The key investment principles of
+diversification, assessment of risk, and targeting the optimal expected returns
+for given levels of risk are applied. 
+The
+Company’s investment portfolio contains a diversified blend of common stocks and
+bonds, which may reflect varying rates of return. The investments are
+further diversified within each asset classification. The portfolio
+diversification provides protection against a single security or class of
+securities having a disproportionate impact on aggregate investment
+performance. The actual asset allocations are reviewed and rebalanced
+on a periodic basis to maintain the target allocations. The Company’s
+weighted-average asset allocation for the Qualified Pension Plan is as
+follows: 
+Target 
+As
+of December 31, 
+Asset
+Category 
+2010 
+2009 
+2008 
+Equity
+securities 
+60% 
+61.3% 
+52.0% 
+Debt
+securities 
+40% 
+38.7% 
+48.0% 
+Other 
+-% 
+-% 
+-% 
+Total 
+100.0% 
+100.0% 
+100.0% 
+There is
+no asset allocation of the Nonqualified Pension Plan since there are no plan
+assets in that plan. An expected return on plan assets of 7.5 percent
+was used to calculate the Company’s obligation under the Qualified Pension Plan
+for 2009 and 2008. Factors considered in determining the expected
+return include the 60 percent equity and 40 percent debt securities mix of
+investment of plan assets and the long-term historical rate of return provided
+by the equity and debt securities markets. The difference in
+investment income using the projected rate of return compared to the actual
+rates of return for the past two years was not material and will not have a
+material effect on the statements of operations or cash flows from operating
+activities in future years. 
+F-36 
+Fair
+Value Assumptions 
+The
+Company’s pension plan assets consist of funds that have quoted net asset values
+within active markets. The individual funds are derived from quoted
+equity and debt securities within active markets with no judgment
+involved. As such, the funds are deemed to be Level 1. The
+fair value of the Company’s pension plan assets as of December 31, 2009,
+utilizing the fair value hierarchy discussed in Note 11- Fair Value Measurements
+is as follows: 
+Assets: 
+Level
+1 
+Level
+2 
+Level
+3 
+(In
+thousands) 
+Cash
+and Money Market Funds 
+$ 
+4 
+$ 
+- 
+$ 
+- 
+Equity
+Securities 
+Foreign
+Large Blend (1) 
+1,365 
+- 
+- 
+U.S.
+Small Blend (2) 
+1,406 
+- 
+- 
+U.S
+Large Blend (3) 
+2,802 
+- 
+- 
+Fixed
+Income Securities 
+Intermediate
+Term Bond (4) 
+3,524 
+- 
+- 
+Total 
+$ 
+9,101 
+$ 
+- 
+$ 
+- 
+(1) 
+International
+equities are invested in companies that trade on active exchanges outside
+the U.S. and are well diversified among a dozen or more developed
+markets. Active and passive strategies are
+employed. 
+(2) 
+U.S.
+equities are invested in companies that are well diversified by industry
+sector and equity style, such as growth and value strategies, that trade
+on active exchanges within the U.S. Active and passive
+management strategies are employed. At least 80% of this fund
+is invested in equity securities of small
+companies. 
+(3) 
+U.S.
+equities include companies that are well diversified by industry sector
+and equity style, such as growth and value strategies, that trade on
+active exchanges within the U.S. Active and passive management
+strategies are employed. At least 80% of this fund is invested
+in equity securities designed to replicate the holdings and weightings of
+the stocks listed in the S&P 500
+index. 
+(4) 
+Intermediate
+term bonds seek total return. At least 80% of this fund is
+invested in a diversified portfolio of bonds, which include all types of
+securities. It invests primarily in bonds of corporate and
+governmental issues located in the U.S. and foreign countries, including
+emerging markets all of which trade on active
+exchanges. 
+Contributions 
+The
+Company contributed $2.0 million, $2.5 million, and $2.2 million, to the Pension
+Plans in the years ended December 31, 2009, 2008, and 2007,
+respectively. Under the Pension Protection Act of 2006, St. Mary is
+not required to make a minimum contribution to the Pension Plans in
+2010. 
+Benefit
+Payments 
+The
+Pension Plans made actual benefit payments of $945,000, $2.9 million, and $1.8
+million in the years ended December 31, 2009, 2008, and 2007,
+respectively. Expected benefit payments over the next ten years are
+as follows (in thousands): 
+Years
+Ended December 31, 
+2010 
+$ 
+610 
+2011 
+1,286 
+2012 
+1,305 
+2013 
+2,381 
+2014 
+2,840 
+2015
+through 2019 
+$ 
+15,872 
+Note
+9 – Asset Retirement Obligations 
+The
+Company recognizes an estimated liability for future costs associated with the
+abandonment of its oil and gas properties. A liability for the fair
+value of an asset retirement obligation and a corresponding increase to
+F-37 
+the
+carrying value of the related long-lived asset are recorded at the time a well
+is completed or acquired. The increase in carrying value is included
+in proved oil and gas properties in the accompanying consolidated balance
+sheets. The Company depletes the amount added to proved oil and gas
+property costs and recognizes expense in connection with the accretion of the
+discounted liability over the remaining estimated economic lives of the
+respective oil and gas properties. Cash paid to settle asset
+retirement obligations is included in the operating section of the Company’s
+accompanying consolidated statements of cash flows. 
+The
+Company’s estimated asset retirement obligation liability is based on historical
+experience in abandoning wells, estimated economic lives, estimates as to the
+cost to abandon the wells in the future, and federal and state regulatory
+requirements. The liability is discounted using the credit-adjusted
+risk-free rate estimated at the time the liability is incurred or
+revised. The credit-adjusted risk-free rates used to discount the
+Company’s abandonment liabilities range from 6.5 percent to 12.0
+percent. Revisions to the liability could occur due to changes in
+estimated abandonment costs or well economic lives, or if federal or state
+regulators enact new requirements regarding the abandonment of
+wells. 
+A
+reconciliation of the Company’s asset retirement obligation liability is as
+follows: 
+As
+of December 31, 
+2009 
+2008 
+(In
+thousands) 
+Beginning
+asset retirement obligation 
+$ 
+116,274 
+$ 
+108,284 
+Liabilities
+incurred 
+2,784 
+11,684 
+Liabilities
+settled 
+(28,958 
+) 
+(24,154 
+) 
+Accretion
+expense 
+8,673 
+7,486 
+Revision
+to estimated cash flows 
+3,307 
+12,974 
+Ending
+asset retirement obligation 
+$ 
+102,080 
+$ 
+116,274 
+Accounts
+payable and accrued expenses as of December 31, 2009, contain $23.7 million
+related to the Company’s asset retirement obligation. The amount
+relates to the estimated plugging and abandonment costs associated with one
+offshore platform that was destroyed during Hurricane Ike and multiple Gulf of
+Mexico platforms that are being relinquished or plugged. Accounts
+payable and accrued expenses contained $7.3 million related to the Company’s
+asset retirement obligation as of December 31, 2008. The amount
+relates to the estimated plugging and abandonment costs associated with one
+offshore platform that was destroyed during Hurricane Ike. Please
+refer to Note 13 – Hurricanes for additional details. 
+Note
+10 – Derivative Financial Instruments 
+New
+Authoritative Accounting Guidance under FASB ASC Topic 815 
+Effective
+January 1, 2009, new authoritative accounting guidance under FASB ASC Topic
+815 , “Derivatives and
+Hedging” (“ASC Topic 815”) requires entities to provide greater transparency
+about how and why an entity uses derivative instruments, how derivative
+instruments and related hedged items are accounted for, and how derivative
+instruments and related hedged items affect an entity’s financial position,
+results of operations, and cash flows. 
+Oil, Natural
+Gas and NGL Commodity Hedges 
+To
+mitigate a portion of the potential exposure to adverse market changes in oil
+and gas prices and the associated impact on cash flows, the Company has entered
+into various derivative contracts. The Company’s derivative contracts
+in place include swap and collar arrangements for oil, natural gas, and natural
+gas liquids (“NGLs”). As of December 31, 2009, the Company has
+hedge contracts in place through the end of 2012 for a total of approximately
+6 million Bbls of anticipated crude oil production, 63 million MMBtu
+of anticipated natural gas production, and 1 million Bbls of anticipated natural
+gas liquids production. 
+F-38 
+The
+Company attempts to qualify its oil, gas and NGL derivative instruments as cash
+flow hedges for accounting purposes under ASC Topic 815. The Company
+formally documents all relationships between the derivative instruments and the
+hedged production, as well as the Company’s risk management objective and
+strategy for the particular derivative contracts. This process
+includes linking all derivatives that are designated as cash flow hedges to the
+specific forecasted sale of oil, gas or NGL at its physical
+location. The Company also formally assesses (both at the
+derivative’s inception and on an ongoing basis) whether the derivatives being
+utilized have been highly effective in offsetting changes in the cash flows of
+hedged production and whether those derivatives may be expected to remain highly
+effective in future periods. If it is determined that a derivative
+has ceased to be highly effective as a hedge, the Company will discontinue hedge
+accounting for that derivative prospectively. If hedge accounting is
+discontinued and the derivative remains outstanding, the Company will recognize
+all subsequent changes in its fair value in the Company’s consolidated
+statements of operations for the period in which the change
+occurs. As of December 31, 2009, all oil, natural gas, and NGL
+derivative instruments qualified as cash flow hedges for accounting
+purposes. The Company anticipates that all forecasted transactions
+will occur by the end of their originally specified periods. All
+contracts are entered into for other than trading purposes. 
+The
+Company’s oil, gas and NGL hedges are measured at fair value and are included in
+the accompanying consolidated balance sheets as derivative assets and
+liabilities. The Company derives internal valuation estimates taking
+into consideration the counterparties’ credit worthiness, the Company’s credit
+worthiness, and the time value of money. Those internal valuations
+are then compared to the counterparties’ mark-to-market
+statements. The consideration of the factors results in an estimated
+exit-price for each derivative asset or liability under a market place
+participant’s view. Management believes that this approach provides a
+reasonable, non-biased, verifiable, and consistent methodology for valuing
+derivative instruments. The derivative instruments utilized by the
+Company are not considered by management to be complex, structured, or
+illiquid. The oil, gas and NGL derivative markets are highly
+active. The fair value of oil, gas and NGL derivative contracts
+designated and qualifying as cash flow hedges under ASC Topic 815 was a net
+liability of $80.9 million and a net asset of $105.3 million at December
+31, 2009, and 2008, respectively. 
+The
+following table details the fair value of derivatives recorded in the
+consolidated balance sheets, by category: 
+Location
+on Consolidated Balance Sheets 
+Fair
+Value at December 31, 2009 
+Fair
+Value at December 31, 2008 
+Derivative
+assets designated as cash flow hedges: 
+(In
+thousands) 
+Oil,
+natural gas, and NGL commodity 
+Current
+assets 
+$ 
+30,295 
+$ 
+111,649 
+Oil,
+natural gas, and NGL commodity 
+Other
+noncurrent assets 
+8,251 
+21,541 
+Total
+derivative assets designated as cash flow hedges under ASC Topic
+815 
+$ 
+38,546 
+$ 
+133,190 
+Derivative
+liabilities designated as cash flow hedges: 
+Oil,
+natural gas, and NGL commodity 
+Current
+liabilities 
+$ 
+(53,929 
+) 
+$ 
+(501 
+) 
+Oil,
+natural gas, and NGL commodity 
+Noncurrent
+liabilities 
+(65,499 
+) 
+(27,419 
+) 
+Total
+derivative liabilities designated as cash flow hedges under ASC Topic
+815 
+$ 
+(119,428 
+) 
+$ 
+(27,920 
+) 
+Realized
+gains or losses from the settlement of oil, gas and NGL derivative contracts are
+reported in the total operating revenues section of the accompanying
+consolidated statements of operations. The Company realized a net
+gain of $140.6 million, a net loss of $101.1 million, and a net gain of
+$24.5 million from its oil, gas, NGL and interest rate derivative contracts
+for the years ended December 31, 2009, 2008, and 2007,
+respectively. 
+F-39 
+After-tax
+changes in the fair value of derivative instruments designated as cash flow
+hedges, to the extent they are effective in offsetting cash flows attributed to
+the hedged risk, are recorded in accumulated other comprehensive income in the
+accompanying consolidated balance sheets until the hedged item is realized in
+earnings upon the sale of the associated hedged production. As of
+December 31, 2009, the amount of unrealized loss net of deferred income
+taxes to be reclassified from accumulated other comprehensive income to realized
+oil and gas hedge gain (loss) in the Company’s accompanying consolidated
+statements of operations in the next twelve months is $6.5 million. 
+The
+Company seeks to minimize ineffectiveness by entering into oil derivative
+contracts indexed to the New York Mercantile Exchange West Texas Intermediate
+(“NYMEX WTI”) index and natural gas derivative contracts indexed to regional
+index prices associated with pipelines in proximity to the Company’s areas of
+production. As the Company’s derivative contracts contain the same
+index as the Company’s sales contracts, this results in derivative contracts
+that are highly correlated with the underlying hedged item. 
+The
+following table details the effect of derivative instruments on other
+comprehensive income (loss) and the consolidated balance sheets (net of
+tax): 
+Derivatives
+Qualifying as Cash Flow Hedges 
+For
+the Years 
+Ended
+December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Amount
+of (Gain) Loss on Derivatives Recognized in OCI During the Period
+(Effective Portion) 
+Commodity
+hedges 
+$ 
+35,977 
+$ 
+(177,005 
+) 
+$ 
+154,497 
+Amount of (Gain) Loss
+Reclassified from AOCI to Realized Oil and Gas Hedge Gain (Loss)
+( Effective
+Portion ) 
+Commodity
+hedges 
+$ 
+(67,344 
+) 
+$ 
+46,463 
+$ 
+(15,470 
+) 
+Any
+change in fair value resulting from hedge ineffectiveness is recognized in
+unrealized derivative (gain) loss in the accompanying consolidated statements of
+operations. The
+following table details the effect of derivative instruments on the consolidated
+statements of operations: 
+Derivatives
+Qualifying as Cash Flow Hedges 
+Classification
+of (Gain) Loss Recognized in Earnings 
+(Gain)
+Loss Recognized in Earnings (Ineffective Portion) 
+For
+the Years 
+Ended
+December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Commodity
+Hedges 
+Unrealized
+derivative (gain) loss 
+$ 20,469 
+$(11,209) 
+$ 4,123 
+F-40 
+Derivatives
+Not Qualifying as Cash Flow Hedges 
+Classification
+of (Gain) Loss Recognized in Earnings 
+(Gain)
+Loss Recognized in Earnings (Ineffective Portion) 
+For
+the Years 
+Ended
+December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Commodity
+Hedges 
+Unrealized
+derivative (gain) loss 
+$ - 
+$ - 
+$ 1,335 
+Interest
+Rate Derivative Contracts 
+In
+September 2007, the Company entered into a one-year floating-to-fixed interest
+rate derivative contract for a notional amount of $75 million. Under
+the agreement, the Company paid a fixed rate of 4.90 percent and received a
+variable rate based on the one-month LIBOR rates. The interest rate
+derivative contract was measured at fair value using quoted prices in active
+markets. The interest rate swap was a straightforward, non-complex,
+non-structured instrument that was highly liquid. A mark-to-market
+valuation took into consideration anticipated cash flows from the transaction
+using quoted market prices, other economic data and assumptions, and pricing
+indications used by other market participants was used to value the
+swap. Given the degree of varying assumptions used to value the swap,
+it was deemed as having Level 2 inputs. This derivative qualified for
+cash flow hedge treatment under ASC Topic 815. The Company recorded a
+net derivative loss of $1.0 million in the accompanying consolidated statements
+of operations for the year ended December 31, 2008, related to this interest
+rate derivative contract. This contract was settled in the third
+quarter of 2008. 
+Convertible
+Note Derivative Instrument 
+The
+contingent interest provision of the 3.50% Senior Convertible Notes is a
+derivative instrument. As of December 31, 2009 and 2008, the value of
+this derivative was determined to be immaterial. 
+Note
+11 – Fair Value Measurements 
+On
+January 1, 2008, the Company applied new authoritative accounting guidance under
+FASB ASC Topic 820, “Fair Value Measurements and Disclosures” (“ASC Topic 820”)
+for all financial assets and liabilities measured at fair value on a recurring
+basis. The topic established a framework for measuring fair value and
+required enhanced disclosures about fair value measurements. ASC
+Topic 820 defined fair value as the price that would be received to sell an
+asset or paid to transfer a liability (an exit price) in an orderly transaction
+between market participants at the measurement date. The topic
+established market or observable inputs as the preferred sources of values,
+followed by assumptions based on hypothetical transactions in the absence of
+market inputs. The topic established a hierarchy for grouping these
+assets and liabilities based on the significance level of the following
+inputs: 
+· 
+Level
+1 – Quoted prices in active markets for identical assets or
+liabilities 
+· 
+Level
+2 – Quoted prices in active markets for similar assets and liabilities,
+quoted prices for identical or similar instruments in markets that are not
+active, and model-derived valuations whose inputs are observable or whose
+significant value drivers are
+observable 
+· 
+Level
+3 – Significant inputs to the valuation model are
+unobservable 
+On
+January 1, 2009, the Company applied ASC Topic 820 to all non-financial assets
+and liabilities measured at fair value on a nonrecurring basis, including
+long-lived assets and assets held for sale measured at fair value under ASC
+Topic 360 and asset retirement obligations initially measured at fair value
+under FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” (“ASC
+Topic 410”). The adoption of ASC Topic 820 for non-financial assets
+and liabilities did not have a material impact on the Company’s financial
+statements. 
+F-41 
+The
+following is a listing of the Company’s financial assets and liabilities that
+are measured at fair value on a recurring basis and where they are classified
+within the hierarchy as of December 31, 2009: 
+Level
+1 
+Level
+2 
+Level
+3 
+(In
+thousands) 
+Assets : 
+Derivatives (a) 
+$ 
+- 
+$ 
+38,546 
+$ 
+- 
+Proved
+oil and gas properties (b) 
+$ 
+- 
+$ 
+- 
+$ 
+11,740 
+Materials
+inventory (b) 
+$ 
+- 
+$ 
+13,882 
+$ 
+- 
+Liabilities : 
+Derivatives (a) 
+$ 
+- 
+$ 
+119,428 
+$ 
+- 
+Net
+Profits Plan (a) 
+$ 
+- 
+$ 
+- 
+$ 
+170,291 
+(a) 
+This
+represents a financial asset or liability that is measured at fair value
+on a recurring basis. 
+(b) 
+This
+represents a nonfinancial asset or liability that is measured at fair
+value on a nonrecurring basis effective January 1,
+2009. 
+The
+following is a listing of the Company’s financial assets and liabilities that
+are measured at fair value on a recurring basis and where they are classified
+within the hierarchy as of December 31, 2008: 
+Level
+1 
+Level
+2 
+Level
+3 
+(In
+thousands) 
+Assets: 
+Derivatives 
+$ 
+- 
+$ 
+133,190 
+$ 
+- 
+Liabilities: 
+Derivatives 
+$ 
+- 
+$ 
+27,920 
+$ 
+- 
+Net
+Profits Plan 
+$ 
+- 
+$ 
+- 
+$ 
+177,366 
+Both
+financial and non-financial assets and liabilities are categorized within the
+hierarchy based on the lowest level of input that is significant to the fair
+value measurement. The following is a description of the valuation
+methodologies used by the Company as well as the general classification of such
+instruments pursuant to the hierarchy. 
+Derivatives 
+The
+Company uses Level 2 inputs to measure the fair value of oil and gas
+hedges. Fair values are based upon interpolated data. The
+Company derives internal valuation estimates taking into consideration the
+counterparties’ credit ratings, the Company’s credit rating, and the time value
+of money. These valuations are then compared to the respective
+counterparties’ mark-to-market statements. The considered factors
+result in an estimated exit-price that management believes provides a reasonable
+and consistent methodology for valuing derivative instruments. 
+Generally,
+market quotes assume that all counterparties have near zero, or low, default
+rates and have equal credit quality. However, an adjustment may be
+necessary to reflect the credit quality of a specific counterparty to determine
+the fair value of the instrument. The Company monitors the credit
+ratings of its counterparties and may ask counterparties to post collateral if
+their ratings deteriorate. In some instances the Company will attempt
+to novate the trade to a more stable counterparty. 
+Valuation
+adjustments are necessary to reflect the effect of the Company’s credit quality
+on the fair value of any liability position with a counterparty. This
+adjustment takes into account any credit enhancements, such as collateral margin
+that the Company may have posted with a counterparty, as well as any letters of
+credit between the parties. The methodology to determine this
+adjustment is consistent with how the Company evaluates counterparty credit
+risk, taking into account the Company’s credit rating, current credit facility
+margins, and any 
+F-42 
+change in such margins since the last measurement
+date. The majority of the Company’s derivative counterparties are
+members of St. Mary’s credit facility bank syndicate. 
+The
+methods described above may result in a fair value estimate that may not be
+indicative of net realizable value or may not be reflective of future fair
+values and cash flows. While the Company believes that the valuation
+methods utilized are appropriate and consistent with the requirements of ASC
+Topic 820 and with other marketplace participants, the Company recognizes that
+third parties may use different methodologies or assumptions to determine the
+fair value of certain financial instruments that could result in a different
+estimate of fair value at the reporting date. 
+Net
+Profits Plan 
+The Net
+Profits Plan is a standalone liability for which there is no available market
+price, principal market, or market participants. The inputs available
+for this instrument are unobservable, and therefore classified as Level 3
+inputs. The Company employs the income approach, which converts
+expected future cash flow amounts to a single present value
+amount. This technique uses the estimate of future cash payments,
+expectations of possible variations in the amount and/or timing of cash flows,
+the risk premium, and nonperformance risk to calculate the fair
+value. There is a direct correlation between realized oil and gas
+commodity prices driving net cash flows and the Net Profits Plan
+liability. If commodity prices fall, the liability is reduced or
+eliminated. 
+The
+Company records the estimated fair value of the long-term liability for
+estimated future payments under the Net Profits Plan based on the discounted
+value of estimated future payments associated with each individual
+pool. The calculation of this liability is a significant management
+estimate. For a predominate number of the pools, a discount rate of
+12 percent is used to calculate this liability. This rate is intended
+to represent the best estimate of the present value of expected future payments
+under the Net Profits Plan. 
+The
+Company’s estimate of its liability is highly dependent on commodity price and
+cost assumptions and the discount rates used in the calculations. The
+Company continually evaluates the assumptions used in this calculation in order
+to consider the current market environment for oil and gas prices, costs,
+discount rates, and overall market conditions. For 2008 and prior the
+commodity price assumptions were formulated by applying a price that was derived
+from a rolling average of actual prices realized in the 24 months prior to the
+reporting date together with adjusted NYMEX strip prices for the ensuing 12
+months. This average price was adjusted to include the effect of
+hedge prices for the percentage of forecasted production hedged in the relevant
+periods. Due to significant fluctuations in commodity prices over the
+past two years the Company no longer believes this method for computing
+commodity price assumptions produces the best estimate of future
+prices. The December 31, 2009, Net Profits Plan liability was
+determined using price assumptions that were computed using five
+one-year strip prices with the fifth year’s pricing being carried out
+indefinitely. The Company’s management believes the change in
+accounting estimate is appropriate and provides a better estimation of the
+liability. The average price is still adjusted to include the effects
+of hedging. The non-cash expense associated with this significant
+management estimate is highly volatile from period to period due to fluctuations
+that occur in the crude oil and natural gas commodity markets. 
+If the
+commodity prices used in the calculation changed by five percent, the liability
+recorded at December 31, 2009, would differ by approximately $14
+million. A one percentage point decrease in the discount rate would
+result in an increase to the liability of approximately $9 million, while a one
+percentage point increase in the discount rate would result in a decrease to the
+liability of approximately $8 million. Actual cash payments to be
+made to participants in future periods are dependent on realized actual
+production, realized commodity prices, and costs associated with the properties
+in each individual pool of the Net Profits Plan. Consequently, actual
+cash payments are inherently different from the amounts estimated. 
+F-43 
+No
+published market quotes exist on which to base the Company’s estimate of fair
+value of the Net Profits Plan liability. As such, the recorded fair
+value is based entirely on management estimates that are described within this
+footnote. While some inputs to the Company’s calculation of fair
+value on the Net Profits Plan’s future payments are from published sources,
+others, such as the discount rate and the expected future cash flows, are
+derived from the Company’s own calculations and estimates. The
+following table reflects the activity for the liabilities measured at fair value
+using Level 3 inputs: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Beginning
+balance 
+$ 
+177,366 
+$ 
+211,406 
+$ 
+160,583 
+Net
+increase in liability (c) 
+13,511 
+17,421 
+82,734 
+Net
+settlements (c)
+(d) 
+(20,586 
+) 
+(51,461 
+) 
+(31,911 
+) 
+Transfers
+in (out) of Level 3 
+- 
+- 
+- 
+Ending
+balance 
+$ 
+170,291 
+$ 
+177,366 
+$ 
+211,406 
+(c) 
+Net
+changes in the Net Profits Plan liability are shown in the Change in Net
+Profits Plan liability line item of the accompanying consolidated
+statements of operations. 
+(d) 
+Settlements
+represent cash payments made or accrued for under the Net Profits
+Plan. 
+3.50%
+Senior Convertible Notes Due 2027 
+Based on
+the market price of the 3.50% Senior Convertible Notes, the estimated fair value
+of the notes was approximately $290.0 million and $204.0 million as of December
+31, 2009 and 2008, respectively. The fair value of the embedded
+contingent interest derivative as of December 31, 2009, and 2008, was
+zero. 
+Proved
+Oil and Gas Properties 
+Proved
+oil and gas property costs are evaluated for impairment and reduced to fair
+value if the sum of the expected undiscounted future cash flows is less than net
+book value pursuant to ASC Topic 360. The Company uses Level 3 inputs
+and the income valuation technique, which converts future amounts to a single
+present value amount, to measure the fair value of proved properties through an
+application of discount rates and price forecasts selected by the Company’s
+management. The calculation of the discount rate is a significant
+management estimate based on the best information available and computed to be
+12 percent for the year ended December 31, 2009. Management
+believes that the discount rate is representative of current market conditions
+and includes the following factors: estimate of future cash payments,
+expectations of possible variations in the amount and/or timing of cash flows,
+the risk premium, and nonperformance risk. The price forecast is
+based on NYMEX strip pricing, adjusted for basis differentials, for the first
+five years. Future operating costs are also adjusted as deemed
+appropriate for these estimates. 
+In
+accordance with ASC Topic 820, of the $2.1 billion worth of long-lived assets,
+excluding materials inventory, $11.7 million were measured at fair value at
+December 31, 2009. 
+Materials
+Inventory 
+Materials
+inventory is valued at the lower of cost or market. The Company uses
+Level 2 inputs to measure the fair value of materials inventory, which is
+primarily comprised of tubular goods. The Company uses third party
+market quotes and compares the quotes to the book value of the materials
+inventory. If the book value exceeds the quoted market price, the
+Company reduces the book value to the market price. The considered
+factors result in an estimated exit-price that management believes provides a
+reasonable and consistent methodology for valuing materials
+inventory. 
+In
+accordance with ASC Topic 820, of the $24.5 million of materials inventory,
+$13.9 million was measured at fair value at December 31, 2009. 
+F-44 
+Asset
+Retirement Obligations 
+The
+Company estimates asset retirement obligations pursuant to the provisions of ASC
+Topic 410. The income valuation technique is utilized by the Company
+to determine the fair value of the liability at the point of inception by
+applying a credit-adjusted risk-free rate, which takes into account the
+Company’s credit risk, the time value of money, and the current economic state,
+to the undiscounted expected abandonment cash flows. Given the
+unobservable nature of the inputs, the initial measurement of the asset
+retirement obligation liability is deemed to use Level 3
+inputs. There were no asset retirement obligations measured at fair
+value within the accompanying consolidated balance sheets at December
+31, 2009. 
+Please
+refer to Note 10 – Derivative Financial Instruments and Note 9 – Asset
+Retirement Obligations for more information regarding the Company’s hedging
+instruments and asset retirement obligations, as well as Note 8 - Pension
+Benefits for additional fair value discussion. 
+Note
+12 – Repurchase and Retirement of Common Stock 
+Stock
+Repurchase Program 
+In July
+2006 the Company’s Board of Directors approved an increase of 5,473,182 shares
+to the remaining authorized number of shares that can be repurchased under the
+Company’s original authorization approved in August 1998, for a total number of
+shares authorized to be repurchased under the plan of 6,000,000. As
+of the date of this filing, the Company has Board authorization to repurchase up
+to 3,072,184 shares of common stock. The shares may be repurchased
+from time to time in open market transactions or in privately negotiated
+transactions, subject to market conditions and other factors, including certain
+provisions of St. Mary’s existing credit facility agreement and compliance with
+securities laws. Stock repurchases may be funded with existing cash
+balances, internal cash flows, and borrowings under the credit
+facility. The details for shares repurchased and retired are
+summarized as follows: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+Number
+of shares repurchased 
+- 
+2,135,600 
+792,216 
+Total
+purchase price, including commissions 
+$ 
+- 
+$ 
+77,149,451 
+$ 
+25,956,847 
+Weighted-average
+price, including commissions 
+$ 
+- 
+$ 
+36.13 
+$ 
+32.76 
+Number
+of shares retired 
+- 
+2,945,212 
+- 
+Remaining
+shares authorized to be repurchased 
+3,072,184 
+3,072,184 
+5,207,784 
+Note
+13 – Hurricanes 
+In 2008
+assets in which the Company has an interest were impacted by Hurricanes Gustav
+and Ike. The Company incurred damage to two wells and to its
+production facilities located at Goat Island in Galveston Bay and minor damages
+to several other properties. The Vermilion 281 production platform
+was lost in Hurricane Ike. The Company made use of its insurance
+coverage with regards to the lost platform and damage to several other
+properties. Due to the severe damage caused by the hurricanes, the
+total storm related costs exceeded the maximum insurance policy
+limit. As a result, the Company recorded losses of $8.3 million and
+$7.0 million in other expense in the accompanying consolidated statements of
+operations for the years ended December 31, 2009 and 2008,
+respectively. To date, the Company has received $16.8 million in
+insurance proceeds. Any variation between actual and estimated storm
+related costs will impact the final determination of the loss. 
+In April
+2007 the Company reached a global insurance settlement for reimbursement of
+damages sustained during Hurricane Rita in 2005. St. Mary’s net cash
+received in the final settlement was approximately
+$33 million. The Company recorded a loss of $2.3 million and a
+gain of $5.2 million in other revenue in the accompanying consolidated
+statements of operations for the years ended December 31, 2008, and 2007,
+F-45 
+respectively,
+resulting in a total net gain of $2.9 million. The Company’s
+retirement efforts were complete as of December 31, 2008. 
+N ote 14 – SemGroup
+Bankruptcy 
+On July
+22, 2008, SemGroup, L.P. and certain of its North American subsidiaries
+(collectively referred to herein as “SemGroup”) filed voluntary petitions for
+reorganization under Chapter 11 of the United States Bankruptcy Code in the
+United States Bankruptcy Court for the District of Delaware. At that
+time, certain SemGroup entities purchased a portion of the Company’s crude oil
+production. As a result of the SemGroup bankruptcy filing the Company
+recorded an allowance for doubtful accounts and bad debt expense of
+$16.6 million as of December 31, 2008. 
+On
+October 27, 2009, the Company executed a Purchase and Sale Agreement whereby the
+Company sold a portion of its SemGroup administrative claim under Section
+503(b)(9) of the Bankruptcy Code. The Company recorded a recovery of
+bad debt expense within the accompanying consolidated statements of operations
+for the year ended December 31, 2009. The Company deemed the
+remaining accounts receivable balance relating to SemGroup to be
+uncollectible. As a result of this determination, the Company wrote
+off the allowance for doubtful accounts and the accounts receivable balance as
+of December 31, 2009. This matter is complete as of December 31,
+2009, and did not have a material adverse effect on the Company’s liquidity or
+overall financial position. 
+Note
+15 – Oil and Gas Activities 
+Costs
+Incurred in Oil and Gas Producing Activities 
+Costs
+incurred in oil and gas property acquisition, exploration and development
+activities, whether capitalized or expensed, are summarized as
+follows: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Development
+costs 
+$ 
+223,108 
+$ 
+587,548 
+$ 
+592,275 
+Exploration
+costs 
+154,122 
+92,199 
+111,470 
+Acquisitions 
+Proved
+properties 
+76 
+51,567 
+161,665 
+Unproved
+properties – acquisitions of 
+proved
+properties (1) 
+- 
+43,274 
+23,495 
+Unproved
+properties - other 
+41,677 
+83,078 
+38,436 
+Total,
+including asset retirement obligation (2)(3) 
+$ 
+418,983 
+$ 
+857,666 
+$ 
+927,341 
+(1) 
+Represents
+the allocated purchase price of unproved properties acquired as part of
+the acquisition of proved properties. Refer to Note 3 –
+Acquisitions, Divestitures, and Assets Held for Sale for additional
+information. 
+(2) 
+Includes
+capitalized interest of $1.9 million, $4.7 million, and $6.7 million for
+the years ended December 31, 2009, 2008, and 2007,
+respectively. 
+(3) 
+Includes
+amounts relating to estimated asset retirement obligations of $(805,000),
+$15.4 million, and $27.6 million for the years ended December 31, 2009,
+2008, and 2007, respectively. 
+F-46 
+Suspended
+Well Costs 
+The
+following table reflects the net changes in capitalized exploratory well costs
+during 2009, 2008, and 2007. The table does not include amounts that
+were capitalized and either subsequently expensed or reclassified to producing
+well costs in the same period: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Beginning
+balance on January 1, 
+$ 
+9,437 
+$ 
+42,930 
+$ 
+22,799 
+Additions
+to capitalized exploratory well costs pending the determination of proved
+reserves 
+34,384 
+9,437 
+29,551 
+Reclassifications
+to wells, facilities, and equipment based on the determination of proved
+reserves 
+(7,569 
+) 
+(36,842 
+) 
+(9,237 
+) 
+Capitalized
+exploratory well costs charged to expense 
+(1,868 
+) 
+(6,088 
+) 
+(183 
+) 
+Ending
+balance at December 31, 
+$ 
+34,384 
+$ 
+9,437 
+$ 
+42,930 
+The
+following table provides an aging of capitalized exploratory well costs based on
+the date the drilling was completed and the number of projects for which
+exploratory well costs have been capitalized for more than one year since the
+completion of drilling: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Exploratory
+well costs capitalized for one year or less 
+$ 
+34,384 
+$ 
+9,437 
+$ 
+29,368 
+Exploratory
+well costs capitalized for more than one year 
+- 
+- 
+13,562 
+Ending
+balance at December 31, 
+$ 
+34,384 
+$ 
+9,437 
+$ 
+42,930 
+Number
+of projects with exploratory well costs that have been capitalized more
+than a year 
+- 
+- 
+3 
+Note
+16 – Disclosures about Oil and Gas Producing Activities (Unaudited) 
+Recent
+SEC and FASB Guidance 
+In
+December 2008 the SEC published the final rules and interpretations updating its
+oil and gas reporting requirements. The Company adopted the rules
+effective December 31, 2009, and the rule changes, including those related to
+pricing and technology, are included in the Company’s reserve
+estimates. 
+In
+January 2010 the FASB aligned ASC Topic 932, with the aforementioned SEC
+requirements. Please refer to the section entitled Recently Issued Accounting
+Standard s under Note 1 – Summary of Significant Accounting Policies for
+additional discussion regarding both adoptions. 
+Application
+of the new rules resulted in the use of lower prices at December 31, 2009, for
+both oil and gas than would have resulted under the SEC’s previous
+methodology. Using 12-month average commodity prices the Company’s
+estimated proved reserves were 772.2 BCFE at December 31, 2009, compared to
+estimated proved reserves of 865.5 at December 31, 2008. Using
+year-end commodity prices, as required under the SEC’s previous methodology,
+would have resulted in estimated proved reserves of 897.2 BCFE at
+December 31, 2009. Therefore, the total impact of the new
+SEC price methodology was a negative 125 BCFE. 
+F-47 
+Third-party
+Reserves Audit 
+The
+Company engaged Ryder Scott Company, L.P. to review internal engineering
+estimates for at least 80 percent of the PV-10 value of our proven conventional
+oil and gas reserves in 2009, 2008, and 2007. For 2008 and 2007,
+Netherland, Sewell and Associates, Inc. prepared the reserve information
+for the Company’s coalbed methane projects at Hanging Woman Basin in the
+northern Powder River Basin and St. Mary’s non-operated coalbed methane interest
+in the Green River Basin. The Company divested of all Hanging Woman
+Basin properties in the fourth quarter of 2009. Please refer to the
+section entitled Third-party
+Reserves Audi t under the heading Reserves included in Part I,
+Items 1. and 2. Business and Properties. 
+Oil
+and Gas Reserve Quantities 
+Proved
+oil and gas reserves are the estimated quantities of crude oil, natural gas, and
+natural gas liquids, which, by analysis of geoscience and engineering data, can
+be estimated with reasonable certainty to be economically producible – from a
+given date forward, from known reservoirs, and under existing economic
+conditions, operating methods, and government regulations – prior to the time at
+which contracts providing the right to operate expire, unless evidence indicates
+that renewal is reasonably certain, regardless of whether deterministic or
+probabilistic methods are used for the estimation. Existing economic
+conditions include prices and costs at which economic producibility from a
+reservoir is to be determined, and the price to be used is the average
+price during the 12-month period prior to the ending date of the period covered
+by the report, determined as an unweighted arithmetic average of the
+first-day-of-the-month price for each month within such period, unless prices
+are defined by contractual arrangements, excluding escalations based upon future
+conditions. With respect to reserves as of dates prior to December
+31, 2009, the applicable SEC definition of proved reserves was the estimated
+quantities of crude oil, natural gas, and natural gas liquids which geological
+and engineering data demonstrate with reasonable certainty to be recoverable in
+future years from known reservoirs under existing economic and operating
+conditions, meaning prices and costs as of the date the estimate is
+made. All of the Company’s proved reserves are located in the
+continental United States. 
+The
+Company emphasizes that reserve estimates are inherently imprecise and that
+estimates of new discoveries and undeveloped locations are more imprecise than
+estimates of established producing oil and gas
+properties. Accordingly, these estimates are expected to change as
+future information becomes available. 
+F-48 
+Presented
+below is a summary of the changes in estimated proved reserves of the
+Company: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+Oil
+or 
+Oil
+or 
+Oil
+or 
+Condensate 
+Gas 
+Condensate 
+Gas 
+Condensate 
+Gas 
+(MBbl) 
+(MMcf) 
+(MBbl) 
+(MMcf) 
+(MBbl) 
+(MMcf) 
+Total
+Proved Reserves 
+Beginning
+of year 
+51,363 
+557,366 
+78,847 
+613,450 
+74,195 
+482,475 
+Revisions
+of previous estimate (a) 
+4,520 
+(76,767 
+) 
+(22,667 
+) 
+(108,163 
+) 
+5,238 
+9,489 
+Discoveries
+and extensions 
+3,389 
+51,964 
+677 
+41,077 
+1,166 
+28,483 
+Infill
+reserves in an existing proved field 
+1,241 
+29,855 
+5,424 
+92,389 
+4,592 
+69,090 
+Purchases
+of minerals in place 
+- 
+- 
+356 
+26,956 
+567 
+91,374 
+Sales
+of reserves (b) 
+(401 
+) 
+(41,767 
+) 
+(4,659 
+) 
+(33,433 
+) 
+(4 
+) 
+(1,400 
+) 
+Production 
+(6,328 
+) 
+(71,106 
+) 
+(6,615 
+) 
+(74,910 
+) 
+(6,907 
+) 
+(66,061 
+) 
+End
+of year (c) 
+53,784 
+449,545 
+51,363 
+557,366 
+78,847 
+613,450 
+Proved
+developed reserves 
+Beginning
+of year 
+47,106 
+433,210 
+68,277 
+426,627 
+61,519 
+358,477 
+End
+of year 
+48,045 
+342,044 
+47,106 
+433,210 
+68,277 
+426,627 
+Proved
+undeveloped reserves 
+Beginning
+of year 
+4,257 
+124,156 
+10,570 
+186,823 
+12,676 
+123,998 
+End
+of year 
+5,739 
+107,501 
+4,257 
+124,156 
+10,570 
+186,823 
+(a) 
+For
+the year ended December 31, 2009, of the 49.6 BCFE downward revision of
+previous estimate, 12.0 BCFE and (61.6) BCFE relate to price and
+performance revisions, respectively. The largest portion of the
+performance revision related to producing properties in the Company’s
+Wolfberry tight oil program in the Permian Basin in West
+Texas. Well performance data collected during 2009 at the
+Sweetie Peck and Halff East programs that target the Wolfberry interval
+indicate that these assets are underperforming for year-end 2008 decline
+forecasts. Accordingly, the Company removed 37 BCFE from proved
+reserves in the Permian region, primarily related to the Wolfberry tight
+oil program. The Company believes that a significant portion of
+these reserves, while not meeting the criteria to be booked as proved
+reserves at year-end, are likely to eventually be produced. The
+Company also saw a downward performance revision of 12 BCFE related to
+certain Cotton Valley assets in our ArkLaTex region. For the
+year ended December 31, 2008, of the 244.2 BCFE downward revision of
+previous estimate, 199.7 BCFE and 44.5 BCFE relate to price and
+performance revisions, respectively. For the year ended
+December 31, 2007, of the 40.9 BCFE upward revision of previous estimate,
+34.5 BCFE and 6.4 BCFE relate to price and performance revisions,
+respectively. 
+(b) 
+The
+Company divested of certain non-core assets during 2009, 2008, and
+2007. Please refer to Note 3 - Acquisitions, Divestitures, and
+Assets Held for Sale for additional
+information. 
+(c) 
+For
+the years ended December 31, 2009, 2008, and 2007, amounts included
+approximately 370, 659, and 316 MMcf respectively, representing the
+Company’s net underproduced gas balancing
+position. 
+Standardized
+Measure of Discounted Future Net Cash Flows 
+The
+Company follows the guidelines prescribed in ASC Topic 932 for computing a
+standardized measure of future net cash flows and changes therein relating to
+estimated proved reserves. Future cash inflows and future production and
+development costs are determined by applying prices and costs, including
+transportation, quality, and basis differentials, to the year-end estimated
+quantities of oil and gas to be produced in the future. Each property
+the Company operates is also charged with field-level overhead in the estimated
+reserve calculation. Estimated future income taxes are computed using
+the current statutory income tax rates, including consideration for estimated
+future statutory depletion. The resulting future net cash flows are
+reduced to present value amounts by applying a ten percent annual discount
+factor. 
+F-49 
+Future
+operating costs are determined based on estimates of expenditures to be incurred
+in developing and producing the proved oil and gas reserves in place at the end
+of the period using year-end costs and assuming continuation of existing
+economic conditions, plus Company overhead incurred by the central
+administrative office attributable to operating activities. 
+The assumptions used to compute the standardized measure are those
+prescribed by the FASB and the SEC. These assumptions do not
+necessarily reflect the Company’s expectations of actual revenues to be derived
+from those reserves, nor their present value. The limitations
+inherent in the reserve quantity estimation process, as discussed previously,
+are equally applicable to the standardized measure computations since these
+reserve quantity estimates are the basis for the valuation
+process. The following prices as adjusted for transportation,
+quality, and basis differentials were used in the calculation of the
+standardized measure: 
+2009 
+2008 
+2007 
+Gas
+(per Mcf) 
+$ 
+3.82 
+$ 
+4.88 
+$ 
+7.56 
+Oil
+(per Bbl) 
+$ 
+53.94 
+$ 
+33.91 
+$ 
+88.71 
+F-50 
+The
+following summary sets forth the Company’s future net cash flows relating to
+proved oil and gas reserves based on the standardized measure prescribed in ASC
+Topic 932: 
+As
+of December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Future
+cash inflows 
+$ 
+4,620,735 
+$ 
+4,463,894 
+$ 
+11,629,679 
+Future
+production costs 
+(1,968,096 
+) 
+(1,866,821 
+) 
+(3,672,857 
+) 
+Future
+development costs 
+(387,722 
+) 
+(393,620 
+) 
+(611,288 
+) 
+Future
+income taxes 
+(515,953 
+) 
+(419,544 
+) 
+(2,316,637 
+) 
+Future
+net cash flows 
+1,748,964 
+1,783,909 
+5,028,897 
+10
+percent annual discount 
+(732,997 
+) 
+(724,840 
+) 
+(2,321,983 
+) 
+Standardized
+measure of discounted future net cash flows 
+$ 
+1,015,967 
+$ 
+1,059,069 
+$ 
+2,706,914 
+The
+principle sources of change in the standardized measure of discounted future net
+cash flows are: 
+For
+the Years Ended December 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+Standard
+measure, beginning of year 
+$ 
+1,059,069 
+$ 
+2,706,914 
+$ 
+1,576,436 
+Sales
+of oil and gas produced, net of production costs 
+(409,153 
+) 
+(988,045 
+) 
+(693,885 
+) 
+Net
+changes in prices and production costs 
+154,008 
+(2,033,674 
+) 
+1,320,994 
+Extensions,
+discoveries and other including infill reserves in an existing proved
+field, net of production costs 
+166,666 
+288,162 
+462,952 
+Purchase
+of minerals in place 
+- 
+33,215 
+265,285 
+Development
+costs incurred during the year 
+33,742 
+105,031 
+123,630 
+Changes
+in estimated future development costs 
+75,134 
+213,554 
+(32,566 
+) 
+Revisions
+of previous quantity estimates 
+(96,354 
+) 
+(363,908 
+) 
+166,428 
+Accretion
+of discount 
+126,538 
+386,118 
+215,745 
+Sales
+of reserves in place 
+(44,823 
+) 
+(198,514 
+) 
+(1,915 
+) 
+Net
+change in income taxes 
+(61,801 
+) 
+947,955 
+(573,259 
+) 
+Changes
+in timing and other 
+12,941 
+(37,739 
+) 
+(122,931 
+) 
+Standardized
+measure, end of year 
+$ 
+1,015,967 
+$ 
+1,059,069 
+$ 
+2,706,914 
+F-51 
+Note
+17 – Quarterly Financial Information (Unaudited) 
+The
+Company’s quarterly financial information for fiscal 2009 and 2008 is as follows
+(in thousands, except per share amounts): 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+Year Ended December 31,
+2009 
+Total
+operating revenues 
+$ 
+199,220 
+$ 
+205,198 
+$ 
+185,787 
+$ 
+241,996 
+Total
+operating expenses 
+334,685 
+211,059 
+185,330 
+231,962 
+Income
+(loss) from operations 
+$ 
+(135,465 
+) 
+$ 
+(5,861 
+) 
+$ 
+457 
+$ 
+10,034 
+Income
+(loss) before income taxes 
+$ 
+(141,539 
+) 
+$ 
+(13,419 
+) 
+$ 
+(7,018 
+) 
+$ 
+2,512 
+Net
+income (loss) 
+$ 
+(87,623 
+) 
+$ 
+(8,322 
+) 
+$ 
+(4,415 
+) 
+$ 
+990 
+Basic
+net income (loss) per common share 
+$ 
+(1.41 
+) 
+$ 
+(0.13 
+) 
+$ 
+(0.07 
+) 
+$ 
+0.02 
+Diluted
+net income (loss) per common share 
+$ 
+(1.41 
+) 
+$ 
+(0.13 
+) 
+$ 
+(0.07 
+) 
+$ 
+0.02 
+Dividends
+declared per common share 
+$ 
+0.05 
+$ 
+- 
+$ 
+0.05 
+$ 
+- 
+Year Ended December 31, 2008 
+(1) 
+Total
+operating revenues 
+$ 
+362,102 
+$ 
+356,942 
+$ 
+324,088 
+$ 
+258,169 
+Total
+operating expenses 
+204,762 
+298,691 
+179,762 
+446,885 
+Income
+(loss) from operations 
+$ 
+157,340 
+$ 
+58,251 
+$ 
+144,326 
+$ 
+(188,716 
+) 
+Income
+(loss) before income taxes 
+$ 
+150,844 
+$ 
+51,067 
+$ 
+137,539 
+$ 
+(194,714 
+) 
+Net
+income (loss) 
+$ 
+94,974 
+$ 
+32,469 
+$ 
+86,997 
+$ 
+(127,092 
+) 
+Basic
+net income (loss) per common share 
+$ 
+1.51 
+$ 
+0.53 
+$ 
+1.40 
+$ 
+(2.04 
+) 
+Diluted
+net income (loss) per common share 
+$ 
+1.48 
+$ 
+0.52 
+$ 
+1.38 
+$ 
+(2.04 
+) 
+Dividends
+declared per common share 
+$ 
+0.05 
+$ 
+- 
+$ 
+0.05 
+$ 
+- 
+(1) 
+The
+2008 amounts have been adjusted for the application of guidance under ASC
+Topic 470. 
+F-52 
+SIGNATURES 
+Pursuant
+to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
+1934, the registrant has duly caused this report to be signed on its behalf by
+the undersigned, thereunto duly authorized. 
+ST. MARY LAND & EXPLORATION
+COMPANY 
+(Registrant) 
+Date:
+February 23, 2010 
+By: 
+/s/ ANTHONY J. BEST 
+Anthony
+J. Best 
+President,
+Chief Executive Officer, 
+and
+Director 
+GENERAL
+POWER OF ATTORNEY 
+KNOW ALL
+PERSONS BY THESE PRESENTS, that each person whose signature appears below
+constitutes and appoints each of Anthony J. Best and A. Wade Pursell his or her
+true and lawful attorney-in-fact and agent with full power of substitution and
+resubstitution, and each with full power to act alone, for the undersigned and
+in his or her name, place and stead, in any and all capacities, to sign any
+amendments to this Annual Report on Form 10-K for the fiscal year ended December
+31, 2009, and to file the same, with exhibits thereto and other documents in
+connection therewith, with the Securities and Exchange Commission, hereby
+ratifying and confirming all that each of said attorney-in-fact, or his
+substitute or substitutes, may do or cause to be done by virtue
+hereof. 
+Pursuant
+to the requirements of the Securities Exchange Act of 1934, this report has been
+signed below by the following persons on behalf of the registrant and in the
+capacities and on the dates indicated. 
+Signature 
+Title 
+Date 
+/s/ ANTHONY J.
+BEST 
+President,
+Chief Executive Officer, 
+February
+23, 2010 
+Anthony
+J. Best 
+and
+Director 
+/s/ A. WADE
+PURSELL 
+Executive
+Vice President and Chief Financial Officer 
+February
+23, 2010 
+A.
+Wade Pursell 
+/s/ MARK T.
+SOLOMON 
+Controller 
+February
+23, 2010 
+Mark
+T. Solomon 
+Signature 
+Title 
+Date 
+/s/ WILLIAM D.
+SULLIVAN 
+Chairman
+of the Board of Directors 
+February
+23, 2010 
+William
+D. Sullivan 
+/s/ BARBARA M.
+BAUMANN 
+Director 
+February
+23, 2010 
+Barbara
+M. Baumann 
+/s/ LARRY W.
+BICKLE 
+Director 
+February
+23, 2010 
+Larry
+W. Bickle 
+/s/ WILLIAM J.
+GARDINER 
+Director 
+February
+23, 2010 
+William
+J. Gardiner 
+/s/ JULIO M.
+QUINTANA 
+Director 
+February
+23, 2010 
+Julio
+M. Quintana 
+/s/ JOHN M.
+SEIDL 
+Director 
+February
+23, 2010 
+John.
+M. Seidl
\ No newline at end of file
diff --git a/raw/filings/0000893538/2009/0000893538-10-000011/filing_metadata.csv b/raw/filings/0000893538/2009/0000893538-10-000011/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..5acd769a8731045e0124c6c6078e516d86f7590f
--- /dev/null
+++ b/raw/filings/0000893538/2009/0000893538-10-000011/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000893538,SM,SM Energy Co,10-K,2010-02-24,2009-12-31,2010-02-23T23:49:58.000Z,0000893538-10-000011,form10k_123109.htm,12/31/09 FORM 10-K,5707355,0,0,https://www.sec.gov/Archives/edgar/data/893538/000089353810000011/form10k_123109.htm,https://www.sec.gov/Archives/edgar/data/893538/000089353810000011/,2009,2009,1
diff --git a/raw/filings/0000893538/2009/0000893538-10-000011/item1.txt b/raw/filings/0000893538/2009/0000893538-10-000011/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2009/0000893538-10-000011/item13.txt b/raw/filings/0000893538/2009/0000893538-10-000011/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2009/0000893538-10-000011/item9a.txt b/raw/filings/0000893538/2009/0000893538-10-000011/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2009/0000893538-10-000011/rp_note.txt b/raw/filings/0000893538/2009/0000893538-10-000011/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2009/0000893538-10-000011/rpt_disclosure.txt b/raw/filings/0000893538/2009/0000893538-10-000011/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..7e5a72e31030efc7104c7e8cb5288316fa7f424b
--- /dev/null
+++ b/raw/filings/0000893538/2009/0000893538-10-000011/rpt_disclosure.txt
@@ -0,0 +1,42 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+Policies and Procedures on Transactions with Related Persons 
+We have adopted a Policy and Procedures With Respect to Related Person Transactions (the "Related Person Policy"), which sets forth the
+policies and procedures for the Audit Committee's review of any transaction, arrangement, or relationship (including any indebtedness or guarantee of indebtedness) or series of similar transactions,
+arrangements, or relationships in which (1) we are a participant, (2) the aggregate amount involved will or may be expected to exceed $120,000, and (3) a related person has or
+will have a direct or indirect material interest. For purposes of the Related Person Policy, a "related person" means (1) any of our directors, executive officers, or nominees for director,
+(2) any stockholder that beneficially owns more than 5% of our outstanding shares of common stock, and (3) any immediate family member of any of the foregoing. The Audit
+Committee approves or ratifies only those transactions that it determines in good faith are in, or are not inconsistent with, the best interests of our company and its stockholders. 
+In
+determining whether to approve or ratify a transaction with a related person, the Audit Committee takes into account the factors it deems appropriate, which may include, among others,
+the benefits to us, the availability of other sources for comparable products or services, the impact on a director's independence in the event the related person is a director, and the extent of the
+related person's interest in the transaction. The policy also provides for the delegation of Audit Committee authority to the Chairman of the Audit Committee for any related person transaction
+requiring pre-approval or ratification between meetings of the Audit Committee. The Audit Committee reviews and assesses ongoing relationships with a related person on at least an annual
+basis to see that they are in compliance with the policy and remain appropriate. 
+In
+addition, our By-Laws provide that a director, officer, or employee of our company may not pursue for his or her own account a business or investment opportunity that he
+or she learned about through his or her affiliation with our company. Our By-Laws also provide that our officers or employees may not pursue for his or her own account an oil and gas
+opportunity that he or she independently learned about unless (1) with respect to an officer of our company, the officer's pursuit of the opportunity has been approved by the Board, and
+(2) with respect to a non-officer of our company, the employee's pursuit of the opportunity has been approved by a senior officer of our company with full knowledge of that
+opportunity. These restrictions do not apply to the acquisition of less than 1% of the publicly traded stock of another company. 
+Related Person Transactions 
+We recognize that transactions with related persons may raise questions among stockholders as to whether those transactions are
+consistent with our best interests and the interests of our stockholders. It is our policy to enter into or ratify such transactions only when the Board, acting through the Audit Committee or as
+otherwise described herein, determines that the transaction in question is in, or is not inconsistent with, the best interests of our company and its stockholders, including but not limited to
+situations where we may obtain products or services of a nature, quantity or quality, or on other terms, that are not readily available from alternative sources or when we provide products or services
+to related persons on an arm's length basis on terms comparable to those provided to unrelated third parties or on terms comparable to those provided to employees generally. Set forth below is a
+description of all transactions between our company and related persons since the beginning of January 1, 2010. 
+11 
+Table of Contents 
+Mr. Quintana
+is the President, Chief Executive Officer, and a director of TESCO Corporation, which designs, manufactures, and delivers technology based solutions for the upstream
+energy industry, including oilfield drilling technology, services, and equipment. We have an agreement with TESCO for the provision of services to us in connection with our drilling and completion
+operations. This agreement continues until canceled by either us or TESCO on 30 days advance written notice. Pursuant to this agreement, we are obligated to pay TESCO only for services actually
+performed. This agreement does not require us to make any other payments to TESCO. Prior to 2010, the services provided by TESCO and the amounts we paid did not exceed the threshold amount for review
+under our Related Person Policy. In May 2010, as part of its annual review of related party transactions, the Audit Committee reviewed the relationship between TESCO and our company and determined at
+such time that we had not paid any amounts to TESCO during 2010. During August 2010 through December 2010, TESCO provided services to us in our ArkLaTex region. In December 2010, the Audit Committee
+again reviewed the relationship between our company and TESCO, but the final 2010 amounts paid to or incurred to be paid to TESCO were not then available for review. Upon the later calculation of the
+final 2010 amounts paid to TESCO, we determined that we had paid TESCO $346,683 for services rendered after August 2010. In addition, as of March 31, 2011, we had paid TESCO $291,635 for
+services in 2011. Based upon these amounts, the Audit Committee reviewed the relationship between our company and TESCO and determined that the relationship is in the best interests of our company and
+its stockholders. 
+12 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000893538/2010/0001104659-11-010268/filing.txt b/raw/filings/0000893538/2010/0001104659-11-010268/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..887713b8f42922a81f8236f5a5a6f05539c66d82
--- /dev/null
+++ b/raw/filings/0000893538/2010/0001104659-11-010268/filing.txt
@@ -0,0 +1,7762 @@
+10-K
+1
+a11-3036_110k.htm
+10-K
+Table of Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+x 
+Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 
+For the fiscal year ended December 31, 2010 
+or 
+o 
+Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 
+Commission file number 001-31539 
+SM ENERGY COMPANY 
+(Exact name of registrant as specified in its charter) 
+Delaware 
+(State or other jurisdiction 
+of incorporation or organization) 
+41-0518430 
+(I.R.S. Employer Identification No.) 
+1775 Sherman Street, Suite 1200, Denver, Colorado 
+(Address of principal executive offices) 
+80203 
+(Zip Code) 
+(303) 861-8140 
+(Registrant’s telephone number, including area code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+Common stock, $.01 par value 
+New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 
+Yes x No o 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer x 
+Accelerated filer o 
+Non-accelerated filer o 
+(Do not check if a 
+smaller reporting company) 
+Smaller reporting company o 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x 
+The aggregate market value of the 62,549,910 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the Company’s common stock on June 30, 2010, the last business day of the registrant’s most recently completed second fiscal quarter, of $40.16 per share, as reported on the New York Stock Exchange; was $2,512,004,386. Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the Company to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes. 
+As of February 18, 2011, the registrant had 63,435,434 shares of common stock outstanding, which is net of 102,635 treasury shares held by the Company. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its 2011 annual meeting of stockholders to be filed within 120 days after December 31, 2010. 
+Table of Contents 
+TABLE OF CONTENTS 
+ITEM 
+PAGE 
+PART I 
+ITEMS 1. and 2. 
+BUSINESS and PROPERTIES 
+1 
+General 
+1 
+Strategy 
+1 
+Significant Developments in 2010 
+1 
+Outlook for 2011 
+3 
+Core Operational Areas 
+4 
+Reserves 
+7 
+Production 
+11 
+Productive Wells 
+11 
+Drilling Activity 
+12 
+Acreage 
+13 
+Delivery Commitments 
+13 
+Major Customers 
+14 
+Employees and Office Space 
+14 
+Title to Properties 
+14 
+Seasonality 
+14 
+Competition 
+14 
+Government Regulations 
+15 
+Cautionary Information about Forward-Looking Statements 
+16 
+Available Information 
+18 
+Glossary of Oil and Gas Terms 
+19 
+ITEM 1A. 
+RISK FACTORS 
+24 
+ITEM 1B. 
+UNRESOLVED STAFF COMMENTS 
+39 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+39 
+ITEM 4. 
+[REMOVED AND RESERVED] 
+39 
+EXECUTIVE OFFICERS OF THE REGISTRANT 
+40 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+43 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+48 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+50 
+Overview of the Company 
+50 
+Financial Results of Operations and Additional Comparative Data 
+59 
+Comparison of Financial Results and Trends between 2010 and 2009 
+63 
+Comparison of Financial Results and Trends between 2009 and 2008 
+67 
+Overview of Liquidity and Capital Resources 
+70 
+Critical Accounting Policies and Estimates 
+81 
+Accounting Matters 
+84 
+Environmental 
+84 
+Table of Contents 
+TABLE OF CONTENTS 
+(Continued) 
+ITEM 
+PAGE 
+ITEM 7A. 
+QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (included with the content of ITEM 7) 
+85 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+85 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+85 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+85 
+ITEM 9B. 
+OTHER INFORMATION 
+89 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+89 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+89 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+89 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+89 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+90 
+PART IV 
+ITEM 15. 
+EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
+90 
+Table of Contents 
+PART I 
+When we use the terms “SM Energy,” “the Company,” “we,” “us,” or “our,” we are referring to SM Energy Company, formerly named St. Mary Land & Exploration Company or referred to as St. Mary, and its subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business under “Glossary of Oil and Gas Terms.” Throughout this document we make statements that may be classified as “forward-looking.” Please refer to the “Cautionary Information about Forward-Looking Statements” section of this document for an explanation of these types of statements. 
+ITEMS 1. and 2. BUSINESS and PROPERTIES 
+General 
+We are an independent energy company engaged in the acquisition, exploration, exploitation, development and production of natural gas and crude oil in North America, with a focus on oil- and liquids-rich resource plays. We were founded in 1908 and incorporated in Delaware in 1915. Our initial public offering of common stock was in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.” 
+Our principal offices are located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is (303) 861-8140. 
+Strategy 
+Our business strategy is to increase net asset value through attractive oil and natural gas investment activity while maintaining a conservative capital structure and optimizing capital expenditures. We focus our efforts on the exploration for, and the development of, onshore, lower-risk resource plays in North America. We believe our inventory of drilling locations is ideally suited to growing reserves and production due to predictable geology and lower-risk profile. Furthermore, our assets produce significant volumes of oil and NGLs that limit our exposure to the current lower natural gas price environment. Our strategy is based on the following points: 
+· leveraging our core competencies in replicating resource play success in the drilling, completion, and development of oil and natural gas reserves; 
+· focusing on resource plays with low-risk geology and high liquids content; 
+· exploiting our legacy assets and optimizing our asset base; 
+· selectively acquiring leasehold positions in new and emerging resource plays; and 
+· maintaining a strong balance sheet while funding the growth of our business. 
+Significant Developments in 2010 
+· Focus on Resource Play Potential. We have meaningful acreage positions in attractive resource plays in North America. We have approximately 250,000 net acres in the Eagle Ford shale play in South Texas, two-thirds of which we operate with an approximate 100 percent working interest. In the North Dakota portion of the Williston Basin, we have approximately 81,000 net acres that are prospective in the Bakken/Three Forks formations. Throughout 2010, we worked to advance our understanding of these liquids-rich resource plays. In the second half of 2010, we began accelerating the development of these plays based on the positive results we were realizing. We believe these two programs are large enough to allow us to gain economies of scale and improve our operational efficiencies in these plays. In addition to the these plays, we have acreage positions in the Granite Wash play in western Oklahoma and the Texas Panhandle, the Haynesville shale in East Texas and northern Louisiana, and the Woodford shale in eastern Oklahoma that provide additional drilling 
+1 
+Table of Contents 
+inventory, particularly in a higher natural gas price environment. During 2010, we further developed our knowledge of each of these plays and formed an exploration team focused on identifying and evaluating other resource play opportunities. 
+· Increase in Year End Proved Reserve Estimates. Our estimated proved reserves increased 27 percent to 984.5 BCFE at December 31, 2010, from 772.2 BCFE at December 31, 2009. We added 384.2 BCFE from our drilling program, the majority of which related to our activity in the Eagle Ford shale in South Texas and the Woodford shale in eastern Oklahoma. We sold 86.8 BCFE of proved reserves during the year related to non-strategic assets located primarily in our Rocky Mountain and Permian regions. We added 42.6 BCFE of estimated proved reserves as a result of price revisions in 2010. The prices used in the calculation of proved reserve estimates as of December 31, 2010, were $79.43 per Bbl and $4.38 per MMBTU for oil and natural gas, respectively. These prices were 30 percent and 13 percent higher, respectively, than the prices used in 2009. Performance revisions in 2010 resulted in a net 11.2 BCFE decrease in our estimate of proved reserves. While we recognized positive performance revisions in every region on proved developed properties, we had approximately 19.3 BCFE of negative performance revisions related to estimated proved undeveloped reserves in primarily dry gas assets, resulting from lower gas prices and higher well costs on the economics of these assets. Lastly, we reduced estimated proved reserves by 6.7 BCFE by removing proved undeveloped reserves related to assets that reached aging limitations, as mandated by the Securities and Exchange Commission (“SEC”). Please refer to Core Operational Areas and Reserves later in this section for additional discussion concerning our 2010 proved reserves. 
+· Production . During 2010, our average daily production was 196.9 MMcf of gas and 17.4 MBbl of oil, for an average equivalent production rate of 301.4 MMCFE per day, which was up slightly compared with 298.8 MMCFE per day for 2009. Adjusting for production from properties sold during 2010 as part of our divestiture efforts over the last few years, production from retained properties has increased 12 percent from 262.3 MMCFE per day in 2009 to 294.0 MMCFE per day in 2010. Please refer to Core Operational Areas and Reserves later in this section for additional discussion concerning our 2010 production. 
+· Capital Investment. During 2010, we incurred costs of $877.4 million for drilling and exploration activities and acquisitions, compared with $419.0 million in 2009. The increase in capital investment reflects our increased confidence in our drilling inventory, particularly in plays with significant oil and rich-gas components. Please refer to Core Operational Areas later in this section for additional discussion concerning our 2010 capital investments. 
+· Volatility in Commodity Prices. Our financial condition and the results of our operations are significantly affected by the prices we receive for oil, natural gas, and NGLs, which can fluctuate dramatically. Oil prices gradually increased throughout 2010. The spot price for NYMEX crude oil hit a two-year high of $91.57 per Bbl during the last week of December. The spot price for NYMEX crude oil was at its lowest of $63.14 per Bbl in May. The average spot price for oil during 2010 was $79.51 per Bbl. 
+Natural gas prices continued to be volatile in 2010. The spot price for gas at Henry H ub, a widely-used industry measuring point, averaged $4.37 per MMBtu in 2010, with a high of $7.75 per MMBtu in January and a low of $3.10 per MMBtu in October. Natural gas prices continued to be under downward pressure in 2010 as a result of excess supply resulting from high levels of drilling activity across the United States, as well as tepid demand due to the economic recession in the United States. 
+· Divestiture of Non-Strategic Properties. We continuously look to high grade our portfolio of assets through the divestiture of non-strategic properties. The objective of these divestitures is to dispose of properties with high operating costs and/or limited future drilling or development potential to generate cash that can be used in the development of our resource plays and other general corporate purposes. During 2010, 
+2 
+Table of Contents 
+we sold 86.8 BCFE of reserves, the majority of which related to assets located in our Rocky Mountain and Permian regions. The following transactions represent the Company’s most significant divestitures during 2010: 
+o Legacy Divestiture. On February 17, 2010, we sold certain non-strategic properties in Wyoming to Legacy Reserves Operating LP. Total cash received, before marketing costs and Net Profits Interest Bonus Plan (“Net Profits Plan”) payments, was $125.3 million. The final gain on divestiture activity related to this divestiture was approximately $66.7 million. 
+o Sequel Divestiture. On March 12, 2010, we sold certain non-strategic properties located in North Dakota to Sequel Energy Partners, LP, Bakken Energy Partners, LLC, and Three Forks Energy Partners, LLC. Total cash received, before marketing costs and Net Profits Plan payments, was $129.1 million. The final gain on divestiture activity related to this divestiture was approximately $53.1 million. 
+o Permian Divestiture. On December 29, 2010, we sold certain non-strategic properties located in our Permian region. Total cash received, before marketing costs and Net Profits Plan payments, was $56.3 million. The final sale price is subject to normal post-closing adjustments and is expected to be finalized during the first half of 2011. The estimated gain on divestiture activity related to this divestiture is approximately $19.9 million and may be impacted by the forthcoming post-closing adjustments mentioned above. 
+o Rockies Divestiture. Subsequent to year end, we sold certain non-strategic oil and gas properties located in our Rocky Mountain region. Total cash received, before marketing costs and Net Profits Plan payments, was $44.4 million. The final sales price is subject to post-closing adjustments and is expected to be finalized during the first half of 2011. 
+Outlook for 2011 
+We enter 2011 with a capital budget of approximately $1.0 billion, of which approximately $830.0 million has been allocated to drilling activity focused on the development of our inventory of resource play opportunities. Please refer to Core Operational Areas below for detailed regional discussion of our 2011 capital budget and Outlook for 2011 under Part II, Item 7 of this report. 
+As we enter the year, we are well positioned both financially and operationally. We have no debt maturities until 2012, when our credit facility matures and our outstanding convertible notes can either be put to us by the note holders or be called by us. Given our debt and asset levels, credit standing, and relationship with our bank group, we believe we will be able to extend our existing facility or obtain a replacement credit facility before our current credit facility matures in 2012. Given the current trading level of our common stock and our liquidity, it is likely that we will call the convertible notes in 2012. We have the option of settling the convertible notes with cash, common stock, or a combination of cash and common stock, the mix of which is at our discretion. 
+Subsequent to year end, the Company issued $350.0 million in aggregate principal amount of 6.625% senior unsecured notes (the “6.625% Senior Notes”). The 6.625% Senior Notes mature on February 15, 2019. We used a portion of the proceeds from our 6.625% Senior Notes offering to repay our outstanding balance under our credit facility. The remaining proceeds will be used to help fund our 2011 capital program and for general corporate purposes. Please refer to Note 5 — Long-term Debt under Part IV, Item 15 of this report for additional discussion. 
+3 
+Table of Contents 
+Core Operational Areas 
+Our operations are currently concentrated onshore in five core operating areas in the United States. The following table summarizes the production, estimate of proved reserves, and PV-10 reserve value of our core operating areas as of December 31, 2010: 
+ArkLaTex 
+Mid- 
+Continent 
+South 
+Texas & 
+Gulf Coast 
+Permian 
+Rocky 
+Mountain 
+Total(1) (2) 
+Proved Reserves 
+Oil (MMBbl) 
+0.3 
+1.3 
+9.7 
+13.7 
+32.4 
+57.4 
+Gas (Bcf) 
+135.9 
+286.1 
+149.1 
+31.4 
+37.5 
+640.0 
+Equivalents (BCFE) 
+137.9 
+293.7 
+207.3 
+113.9 
+231.8 
+984.5 
+Relative percentage 
+14 
+% 
+30 
+% 
+21 
+% 
+12 
+% 
+24 
+% 
+100 
+% 
+Proved Developed % 
+64 
+% 
+68 
+% 
+47 
+% 
+87 
+% 
+88 
+% 
+70 
+% 
+PV-10 Values (in millions) 
+Proved Developed 
+$ 
+147.1 
+$ 
+400.5 
+$ 
+376.1 
+$ 
+428.0 
+$ 
+701.8 
+$ 
+2,053.5 
+Proved Undeveloped (3) 
+19.0 
+68.0 
+130.0 
+42.6 
+31.2 
+290.8 
+Total Proved 
+$ 
+166.1 
+$ 
+468.5 
+$ 
+506.1 
+$ 
+470.6 
+$ 
+733.0 
+$ 
+2,344.3 
+Relative percentage 
+7 
+% 
+20 
+% 
+22 
+% 
+20 
+% 
+31 
+% 
+100 
+% 
+Production 
+Oil (MMBbl) 
+0.1 
+0.2 
+1.0 
+1.7 
+3.3 
+6.4 
+Gas (Bcf) 
+13.9 
+32.1 
+16.4 
+4.3 
+5.2 
+71.9 
+Equivalent (BCFE) 
+14.4 
+33.4 
+22.7 
+14.7 
+24.9 
+110.0 
+Avg. Daily Equivalents (MMCFE/d) 
+39.3 
+91.5 
+62.1 
+40.2 
+68.3 
+301.4 
+Relative percentage 
+13 
+% 
+30 
+% 
+21 
+% 
+13 
+% 
+23 
+% 
+100 
+% 
+(1) Totals may not add due to rounding. 
+(2) Included in the total are approximately 11 BCFE related to non-strategic properties that we divested subsequent to December 31, 2010. 
+(3) We record estimates of proved undeveloped for locations with a negative PV-10 value if we have the intent to drill the location and believe it will generate positive undiscounted net cash flow and meet our economic criteria. 
+South Texas & Gulf Coast Region. Operations for the region are managed from our office in Houston, Texas. Our current operations in the South Texas & Gulf Coast region center on our Eagle Ford shale program. Since 2007 we have expanded our acreage position to approximately 250,000 net acres, of which roughly two-thirds is operated by us with a working interest of approximately 100 percent. Our acreage position covers a significant portion of the greater Eagle Ford play, including acreage in the oil, the rich-gas, and the dry gas windows of the play. During the first half of 2010, we worked to increase our understanding of the play and focused our efforts on mitigating risk in our drilling and development programs, particularly with respect to delineating the respective product windows. On our operated acreage position, we operated two drilling rigs throughout the year which tested a large amount of our acreage. As a result of the positive results we experienced in our operated program, we began making commitments in the second half of the year for takeaway capacity and to secure drilling and completion services that will enable us to increase our activity in 2011 and beyond. In our non-operated Eagle Ford program, which represents approximately one-third of our total acreage position, the operator of the program steadily increased its drilling rig count throughout 2010. In addition to participating in our non-operated drilling program, we also participate in the construction of midstream assets to service the development of the shared acreage position. Substantially all of our capital deployed in the South Texas & Gulf Coast region in 2010 targeted our Eagle Ford shale program. Our capital investment, production, and reserves all increased considerably in 2010 as a result of our focused efforts in our Eagle Ford shale program. Our capital expenditures for exploration, development, and acquisition activity in our South Texas & Gulf Coast region increased significantly from $115.1 million in 2009 to $456.2 million in 2010. 
+4 
+Table of Contents 
+Production in 2010 for the South Texas & Gulf Coast region was 22.7 BCFE, an increase of 134 percent from the 9.7 BCFE produced in 2009. Estimated proved reserves at the end of 2010 increased 290 percent to 207.3 BCFE, compared with 53.2 BCFE reported in the prior year. The increase in production and proved reserves reflect the significant increase in activity on both the operated and non-operated portions of our Eagle Ford shale program. Production from portions of our operated acreage was limited for much of the year as a result of insufficient natural gas takeaway capacity. By year end, we had reached an agreement to increase our takeaway capacity in the affected area. 
+Our plans for 2011 in the South Texas & Gulf Coast region are to continue focusing exclusively on the Eagle Ford shale. We begin 2011 operating two drilling rigs in Webb and LaSalle Counties in South Texas. Over the course of the year, we plan to increase our operated rig count to five or six drilling rigs, the vast majority of which will target portions of our acreage containing high BTU gas and condensate. Most of the wells planned for the year will be in the Briscoe and Galvan Ranch areas where we were active during 2010. A higher level of activity is also planned for LaSalle County, Texas in order to test and delineate our acreage in that area. In addition, a number of projects, such as retained energy fracture stimulations and reduced spacing pilots, are planned for next year across the play. 
+In the non-operated portion of our Eagle Ford shale position, seven rigs are currently operating. The operator has indicated it plans an increase to ten drilling rigs by the end of the first quarter of 2011. In addition, the operator is actively pursuing a partial sale or farm-down of its portion of the shared acreage, which could result in a further increase in drilling activity. 
+We have allocated approximately $500 million of our 2011 capital budget to our total Eagle Ford shale drilling program. Based on the activity levels contemplated above, capital expenditures net to us would be in excess of this amount. We have also initiated a marketing effort to sell down or joint venture a portion of our total Eagle Ford shale position. Although specifics related to the contemplated transaction are still being determined, we estimate that we could sell down or joint venture 20 to 30 percent of our total acreage position, resulting in a net investment by us in our Eagle Ford program in 2011 of approximately $500 million. 
+Rocky Mountain Region. Operations for the region are managed from our office in Billings, Montana. Our capital investments in 2010 were primarily focused on the Bakken/Three Forks formations in the Williston Basin in Montana and North Dakota. During 2010, we were successful in testing prospects further west of the bulk of the industry’s development activity in North Dakota. Our 2010 capital expenditures for exploration, development, and acquisition activity in the Rocky Mountain region increased from $51.2 million in 2009 to $158.5 million as a result of our continued focus on oil programs. 
+Estimated proved reserves for our Rocky Mountain region were 231.8 BCFE at year end compared with 260.3 BCFE as of the end of 2009. The decrease in proved reserves is the result of selling 71.7 BCFE of proved reserves in the region during the year. This decrease was partially offset by net positive price and engineering revisions of 16.7 BCFE and positive drillings adds of 51.3 BCFE. Our program targeting the Bakken/Three Forks formations contributed the majority of our drilling additions in this region. Total regional production for 2010 was 24.9 BCFE, which was down 25 percent from 33.3 BCFE in 2009 as a result of our Legacy and Sequel divestitures that closed in the first quarter of 2010. Adjusting for the effect of these divestitures, production in the region increased 1.4 BCFE, or six percent, year over year. 
+We plan to invest approximately $170 million in 2011 on drilling projects targeting the Bakken/Three Forks formations in the Williston Basin. We plan to operate two drilling rigs during the first half of 2011, with the planned addition of a third rig at mid-year. Substantially all of this activity is expected to occur in McKenzie and Divide Counties, North Dakota. Operations in McKenzie County will focus on the horizontal Bakken formation in our Raven prospect area in the western portion of the county. We will operate approximately two-thirds of this activity. Our activity in Divide County will target the Three Forks formation and will be entirely operated by us. We have also budgeted $25 million for drilling projects targeting the Niobrara formation in the northern portion of the DJ Basin in southeastern Wyoming, focusing on acreage near the Silo Field in Laramie County. 
+5 
+Table of Contents 
+Mid-Continent Region. Operations for the region are managed from our office in Tulsa, Oklahoma. Our current operations in the Mid-Continent region are focused on the horizontal development of the Woodford shale in the Arkoma Basin in eastern Oklahoma and horizontal development of the Granite Wash formation in western Oklahoma and the Texas Panhandle. The Mid-Continent region also manages our Marcellus shale activity in north central Pennsylvania. We continued our successful development of the Woodford shale throughout 2010, with a particular focus on multi-well (“simul-frac”) completions, where multiple wells are completed at the same time. We focused our activity in the Woodford shale on portions of our acreage position that contained richer gas. Our 2010 Granite Wash program was focused on assessing the horizontal potential of our approximately 34,000 net acres in the play. We tested several intervals with varying degrees of success during the year and also participated in a number of non-operated wells. Activity in our Marcellus program during the year involved the drilling and completion of two wells and the completion of associated pipeline infrastructure. Late in 2010, we began a marketing process to divest our entire Marcellus position. We continue to explore our options to monetize all or a portion of our Marcellus assets. In 2010 we incurred costs of $124.5 million in the Mid-Continent region for exploration, development, and acquisition activity, which is 17 percent more than the $106.8 million incurred in 2009. 
+Our Mid-Continent region production in 2010 was 33.4 BCFE, a slight decrease from the 36.0 BCFE produced in 2009. Proved reserves at the end of 2010 were 293.7 BCFE, a considerable increase of 31 percent from the 223.5 BCFE reported for the prior year. Our horizontal Woodford shale program, as well as our assets in the Anadarko Basin targeting the Granite Wash formation, contributed the majority of our 100.4 BCFE of reserve additions. 
+The Company plans to invest approximately $60 million in 2011 in horizontal wells targeting the Granite Wash formation. Two operated drilling rigs will be required next year to execute this drilling program. We will operate over 65 percent of this activity. The economics of these projects benefit from the contribution of higher BTU natural gas and condensate in the production stream. No meaningful activity is planned for our Woodford shale program in 2011 due to the current outlook for natural gas prices. However, an increase in natural gas prices or a decrease in the costs of drilling and completing these wells could result in increased activity in the play. 
+ArkLaTex Region. Our operations for the region are managed from our office in Shreveport, Louisiana. Our 2010 capital investments were primarily focused on the Haynesville shale in East Texas and North Louisiana. Our 2010 capital expenditures for exploration, development, and acquisition activity in our ArkLaTex region decreased from $65.7 million in 2009 to $47.6 million. Our activity level in the Haynesville did not change significantly from what we planned at the beginning of the year, because our capital requirements in this play were substantially reduced as a result of the carry and earning agreement we entered into in the second quarter of 2010. The region’s 2010 production was 14.4 BCFE, which was relatively flat when compared with 2009 production of 14.9 BCFE. Our 2010 year end proved reserves were 137.9 BCFE, which is 15 percent higher than the 2009 year end proved reserves of 120.0 BCFE. The increase in proved reserves is primarily the result of drilling additions in the Haynesville shale. 
+We have budgeted approximately $35 million for Haynesville shale activity in 2011 comprised of five gross operated horizontal wells. The majority of costs will be carried under the carry and earning agreement covering a portion of our acreage position in East Texas. We will also participate in approximately 20 gross (approximately two net) partner-operated horizontal wells in 2011. 
+We own approximately 22,000 net acres in the East Texas Shelby Trough that is prospective for both the Haynesville and Bossier shales, as well as other shallower productive zones. We are currently exploring a number of options for this acreage position which would allow us to drill or participate in enough wells in 2011 and early 2012 to hold substantially all of this acreage, while minimizing the amount of capital deployed by us. We would need to drill 12 gross wells in 2011, in addition to the operated wells discussed above, and eight gross wells in 2012 to hold all of this acreage. 
+Permian Region. Operations for the region are managed from our office in Midland, Texas. The Permian region area covers a significant portion of western Texas and eastern New Mexico and is one of the 
+6 
+Table of Contents 
+major producing basins in the United States. Our primary focus in this region is the Wolfberry tight oil play. We incurred costs of $85.4 million in the region in 2010 compared to $76.5 million in 2009 targeting the stacked carbonate Wolfcamp and Spraberry formations found in the basin. The region’s 2010 production was 14.7 BCFE, which was relatively flat when compared with 2009 production of 15.1 BCFE. Proved reserves in this region as of the end of 2010 were 113.9 BCFE, which was relatively flat when compared to 2009 year end reserves of 115.2 BCFE. 
+We plan to spend approximately $40 million in the Permian region, with approximately $20 million expected to be invested in Wolfberry wells in 2011. The majority of this program will be operated by an outside partner. The remaining Permian region budget will be allocated to various other plays in the basin. 
+Reserves 
+The table below presents summary information with respect to the estimates of our proved oil and gas reserves for each of the years in the three-year period ended December 31, 2010. We engaged Ryder Scott Company, L.P. (“Ryder Scott”) to audit internal engineering estimates for at least 80 percent of the PV-10 value of our proved reserves in 2010, 2009, and 2008, excluding our coalbed methane properties. For 2008, Netherland, Sewell and Associates, Inc. (“NSAI”) prepared the reserve information for our coalbed methane projects at Hanging Woman Basin in the northern Powder River Basin and our non-operated coalbed methane interest in the Green River Basin. We divested all of our Hanging Woman Basin properties in the fourth quarter of 2009. The prices used in the calculation of proved reserve estimates as of December 31, 2010, were $79.43 per Bbl and $4.38 per MMBTU for oil and natural gas, respectively. 
+We emphasize that reserve estimates are inherently imprecise and that estimates of all new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by us. Neither prices nor costs have been escalated. The following table should be read along with the section entitled “Risk Factors — Risks Related to Our Business - The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated.” No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year. 
+The ability to replace produced reserves is important to the sustainability of all exploration and production companies. Our 2010 corporate ratio of reserves replaced through drilling activity, excluding revisions, was 349 percent. There were no material acquisitions made in 2010. In 2010 all of our regions replaced their production for the year. This metric is calculated using information from the Oil and Gas Reserve Quantities section of Note 15 — Disclosures about Oil and Gas Producing Activities of Part IV, Item 15 of this report. The numerator consists of the sum of discoveries and extensions and infill reserves in an existing proved field, which is then divided by production. 
+7 
+Table of Contents 
+We believe the concept of reserve replacement as described above, as well as permutations which may include other captions of the Oil and Gas Reserve Quantities section of Note 15 — Disclosures about Oil and Gas Producing Activities of Part IV, Item 15 of this report, are widely understood by those who make investment decisions related to the oil and gas exploration business. For additional information about reserve replacement metrics, see the reserve replacement terms in the Glossary section of this report. 
+As of December 31, 
+2010 
+2009 
+2008 
+Reserve data: 
+Proved developed 
+Oil (MMBbl) 
+46.0 
+48.1 
+47.1 
+Gas (Bcf) 
+411.0 
+342.0 
+433.2 
+BCFE 
+687.3 
+630.3 
+715.8 
+Proved undeveloped 
+Oil (MMBbl) 
+11.4 
+5.7 
+4.3 
+Gas (Bcf) 
+229.0 
+107.5 
+124.2 
+BCFE 
+297.2 
+141.9 
+149.7 
+Total Proved 
+Oil (MMBbl) 
+57.4 
+53.8 
+51.4 
+Gas (Bcf) 
+640.0 
+449.5 
+557.4 
+BCFE 
+984.5 
+772.2 
+865.5 
+Proved developed reserves % 
+70 
+% 
+82 
+% 
+83 
+% 
+Proved undeveloped reserves % 
+30 
+% 
+18 
+% 
+17 
+% 
+Reserve value data (in thousands): 
+Proved developed PV-10 
+$ 
+2,053,556 
+$ 
+1,253,056 
+$ 
+1,214,380 
+Proved undeveloped PV-10 
+290,775 
+31,029 
+51,005 
+Total proved PV-10 
+$ 
+2,344,331 
+$ 
+1,284,085 
+$ 
+1,265,385 
+Standardized measure of discounted future cash flows 
+$ 
+1,666,367 
+$ 
+1,015,967 
+$ 
+1,059,069 
+Reserve replacement — drilling and acquisitions, excluding revisions 
+349 
+% 
+100 
+% 
+174 
+% 
+All in — including sales of reserves 
+293 
+% 
+14 
+% 
+(93 
+)% 
+All in — excluding sales of reserves 
+372 
+% 
+55 
+% 
+(39 
+)% 
+Reserve life (years)(1) 
+8.9 
+7.1 
+7.6 
+(1) Reserve life represents the estimated proved reserves at the dates indicated divided by actual production for the preceding 12-month period. 
+8 
+Table of Contents 
+The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 value (Non-GAAP). The difference has to do with the PV-10 value measure excluding the impact of income taxes. Please see the definitions of standardized measure of discounted future net cash flows and PV-10 value in the Glossary. 
+As of December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Standardized measure of discounted future net cash flows 
+$ 
+1,666,367 
+$ 
+1,015,967 
+$ 
+1,059,069 
+Add: 10 percent annual discount, net of income taxes 
+1,294,632 
+732,997 
+724,840 
+Add: future income taxes 
+1,335,576 
+515,953 
+419,544 
+Undiscounted future net cash flows 
+$ 
+4,296,575 
+$ 
+2,264,917 
+$ 
+2,203,453 
+Less: 10 percent annual discount without tax effect 
+(1,952,244 
+) 
+(980,832 
+) 
+(938,068 
+) 
+PV-10 value 
+$ 
+2,344,331 
+$ 
+1,284,085 
+$ 
+1,265,385 
+Proved Undeveloped Reserves 
+As of December 31, 2010, we had 297.2 BCFE of proved undeveloped reserves, which is an increase of 155.3 BCFE, or 109 percent, compared with 141.9 BCFE of proved undeveloped reserves at December 31, 2009. We added 203.0 BCFE of proved undeveloped reserves through our drilling program, 130.1 BCFE of which were extensions and discoveries, primarily in the Eagle Ford shale, the Bakken/Three Forks formations, and the Haynesville shale, as well as an additional 72.9 BCFE of infill proved undeveloped reserves that were mostly concentrated in our Woodford Shale properties in our Mid-Continent region and our Wolfberry properties in our Permian region. A positive revision of 4.8 BCFE was due to higher twelve-month average pricing primarily in the gas weighted regions, particularly in our ArkLaTex and Mid-Continent regions. We had a negative engineering revision of 19.3 BCFE due to increasing capital and operating costs in the less liquids-rich portions of our Woodford and Eagle Ford plays, causing those projects to no longer meet our internal investment hurdles. During the year, 9.9 BCFE were sold in divestitures primarily in our Rocky Mountain and Permian regions. We invested approximately $43.7 million to convert 16.6 BCFE of proved undeveloped reserves in 2010, mainly in our Wolfberry properties in the Permian region and Bakken/Three Forks properties in our Rocky Mountain region. We removed 6.7 BCFE of proved undeveloped reserves as a result of the five year limitation on the number of years that a proved undeveloped reserves may remain on the books without being developed. As of December 31, 2010, we have no material proved undeveloped reserves that have been on the books in excess of five years and we have recorded no material proved undeveloped locations that were more than one direct offset from an existing producing well. As of December 31, 2010, estimated future development costs relating to proved undeveloped reserves are projected to be approximately $123 million, $240 million, and $122 million in 2011, 2012, and 2013, respectively. 
+9 
+Table of Contents 
+Internal Controls Over Reserves Estimate 
+Our policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserve quantities and values in compliance with the SEC’s regulations. Responsibility for compliance in reserve bookings is delegated to our reservoir engineering group, which is led by our Vice President - Engineering and Evaluation. 
+Technical reviews are performed throughout the year by regional engineering and geologic staff who evaluate all available geological and engineering data. This data, in conjunction with economic data and ownership information, is used in making a determination of estimated proved reserve quantities. The reserve process is overseen by Dennis A. Zubieta, Vice President - Engineering and Evaluation. Mr. Zubieta joined us in June 2000 as a Corporate Acquisition & Divestiture Engineer, assumed the role of Reservoir Engineer in February 2003, and was appointed Reservoir Engineering Manager in August 2005. Mr. Zubieta was employed by Burlington Resources Oil and Gas Company (formerly known as Meridian Oil, Inc.) from June 1988 to May 2000 in various operations and reservoir engineering capacities. Mr. Zubieta received a Bachelor of Science degree in Petroleum Engineering from Montana Tech in May 1988. The regional technical staff does not report directly to Mr. Zubieta; they report to either regional technical managers or directly to the regional manager in their respective regions. This is intended to promote objective and independent analysis within the reserves estimation process. 
+Third-party Reserves Audit 
+An independent audit is performed by Ryder Scott using their own engineering assumptions and other economic data provided by us. A minimum of 80 percent of our total calculated proved reserve PV-10 value is audited by Ryder Scott. In the aggregate, the proved reserve values of the audited properties are required to be within 10 percent of our valuations for the total company as well as for each respective region. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world for over seventy years. The technical person at Ryder Scott primarily responsible for overseeing our reserve audit is a Senior Vice President and received a Bachelor of Science degree in Petroleum Engineering from the University of Missouri at Rolla in 1970 and is a registered Professional Engineer in the States of Colorado and Utah. He is also a member of the Society of Petroleum Engineers. The Ryder Scott report is included as Exhibit 99.1. 
+In addition to a third party audit, our reserves are reviewed by senior management and the Audit Committee of our Board of Directors. Senior management, which includes the President and Chief Executive Officer, the Executive Vice President and Chief Operating Officer, and the Executive Vice President and Chief Financial Officer, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews the final reserves estimate in conjunction with Ryder Scott’s audit letter. It may also meet with Ryder Scott representatives to discuss its processes and findings. 
+10 
+Table of Contents 
+Production 
+The following table summarizes the average volumes and realized prices, including and excluding the effects of hedging, of oil and gas produced from properties in which we held an interest during the periods indicated. Also presented is a production cost per MCFE summary: 
+Years Ended December 31, 
+2010 
+2009 
+2008 
+Net production(1) 
+Oil (MMBbl) 
+6.4 
+6.3 
+6.6 
+Gas (Bcf) 
+71.9 
+71.1 
+74.9 
+BCFE 
+110.0 
+109.1 
+114.6 
+Average net daily production(1) 
+Oil (MBbl) 
+17.4 
+17.3 
+18.1 
+Gas (MMcf) 
+196.9 
+194.8 
+204.7 
+MMCFE 
+301.4 
+298.8 
+313.1 
+Average realized sales price, excluding the effects of hedging 
+Oil (per Bbl) 
+$ 
+72.65 
+$ 
+54.40 
+$ 
+92.99 
+Gas (per Mcf) 
+$ 
+5.21 
+$ 
+3.82 
+$ 
+8.60 
+Per MCFE 
+$ 
+7.60 
+$ 
+5.65 
+$ 
+10.99 
+Average realized sales price, including the effects of hedging 
+Oil (per Bbl) 
+$ 
+66.85 
+$ 
+56.74 
+$ 
+75.59 
+Gas (per Mcf) 
+$ 
+6.05 
+$ 
+5.59 
+$ 
+8.79 
+Per MCFE 
+$ 
+7.82 
+$ 
+6.94 
+$ 
+10.11 
+Production costs per MCFE 
+Lease operating expense 
+$ 
+1.10 
+$ 
+1.33 
+$ 
+1.46 
+Transportation expense 
+$ 
+0.19 
+$ 
+0.19 
+$ 
+0.19 
+Production taxes 
+$ 
+0.48 
+$ 
+0.37 
+$ 
+0.71 
+(1) In 2010 total estimated proved reserves in our Eagle Ford shale properties contained greater than 15 percent of our total proved reserves expressed on an equivalent basis. During 2010 net production from the Eagle Ford shale was 13.0 Bcf of gas and 0.8 MMBbl of oil, or 17.6 BCFE on an equivalent basis. Our average daily production from the Eagle Ford shale was 35.6 MMcf of gas and 2.1 MBbl of oil, for an average equivalent production rate of 48.3 MMCFE per day. No fields contained 15 percent or greater of our total proved reserves expressed on an equivalent basis in 2009. The SEC rules requiring this disclosure were not effective for the 2008 fiscal year. 
+Productive Wells 
+As of December 31, 2010, we had working interests in 1,263 gross (725 net) productive oil wells and 2,861 gross (987 net) productive gas wells. Productive wells are either wells producing in commercial quantities or wells capable of commercial production although currently shut-in. Multiple completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production. 
+Subsequent to year end, we sold certain non-strategic properties in our Rocky Mountain region. Upon closing of this transaction, we divested of 39 gross (31 net) productive oil wells. 
+11 
+Table of Contents 
+Drilling Activity 
+All of our drilling activities are conducted on a contract basis with independent drilling contractors. We do not own any drilling equipment. The following table summarizes the number of wells drilled and recompleted in 2010, 2009, and 2008, excluding any wells with only a royalty interest ownership: 
+Years Ended December 31, 
+2010 
+2009 
+2008 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development: 
+Oil 
+191 
+36.48 
+103 
+29.64 
+221 
+81.46 
+Gas 
+72 
+16.96 
+74 
+18.15 
+559 
+205.18 
+Non-productive 
+4 
+1.10 
+3 
+1.29 
+25 
+13.70 
+267 
+54.54 
+180 
+49.08 
+805 
+300.34 
+Exploratory: 
+Oil 
+36 
+11.52 
+2 
+0.42 
+2 
+0.40 
+Gas 
+83 
+37.94 
+18 
+9.05 
+10 
+2.75 
+Non-productive 
+1 
+0.75 
+5 
+2.88 
+1 
+0.76 
+120 
+50.21 
+25 
+12.35 
+13 
+3.91 
+Farmout or non-consent 
+— 
+— 
+3 
+— 
+7 
+— 
+Total 
+387 
+104.75 
+208 
+61.43 
+825 
+304.25 
+A productive well is an exploratory, development or extension well that is not a dry well. A dry well (hole) is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. 
+As defined in the rules and regulations of the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is part of a development project, which is defined as the means by which petroleum resources are brought to the status of economically producible. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to the reporting to the appropriate authority that the well has been abandoned. 
+In addition to the wells drilled and completed in 2010 included in the table above, as of February 18, 2011, we were participating in the drilling of approximately 29 gross wells, all of which are located onshore in the continental United States. We operate nine of these wells with the remaining 20 wells being operated by others. On a net basis, at such date, we were drilling approximately four net operated wells and were participating in approximately three net non-operated wells. With respect to completion activity, at such date, there were approximately 94 wells in which we have an interest that were being completed. We operate 26 of these completion activities on a gross basis, approximately 18 net, and were participating in 68 gross, approximately 11 net, non-operated completion activities. The vast majority, if not all, of these operations relate to the drilling of wells for primary production. 
+12 
+Table of Contents 
+Acreage 
+The following table sets forth the gross and net acres of developed and undeveloped oil and gas leasehold, fee properties, mineral servitudes, and lease options held by us as of December 31, 2010. Undeveloped acreage includes leasehold interests that may already have been classified as containing proved undeveloped reserves. 
+Developed Acres (1) 
+Undeveloped Acres (2) 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Arkansas 
+1,394 
+163 
+152 
+65 
+1,546 
+228 
+Colorado 
+— 
+— 
+1,596 
+860 
+1,596 
+860 
+Kansas 
+— 
+— 
+2,240 
+560 
+2,240 
+560 
+Louisiana 
+76,404 
+27,969 
+13,917 
+2,694 
+90,321 
+30,663 
+Mississippi 
+835 
+199 
+99,744 
+41,978 
+100,579 
+42,177 
+Montana 
+60,311 
+41,145 
+328,400 
+222,550 
+388,711 
+263,695 
+Nevada 
+— 
+— 
+197,945 
+197,945 
+197,945 
+197,945 
+New Mexico 
+2,361 
+1,687 
+1,240 
+1,022 
+3,601 
+2,709 
+North Dakota 
+99,119 
+63,690 
+180,098 
+104,583 
+279,217 
+168,273 
+Oklahoma 
+258,598 
+82,595 
+43,586 
+19,233 
+302,184 
+101,828 
+Pennsylvania 
+282 
+282 
+31,435 
+27,655 
+31,717 
+27,937 
+Texas 
+146,648 
+106,737 
+624,065 
+295,817 
+770,713 
+402,554 
+Utah 
+— 
+— 
+2,568 
+561 
+2,568 
+561 
+Wyoming 
+61,608 
+28,237 
+245,194 
+132,560 
+306,802 
+160,797 
+707,560 
+352,704 
+1,772,180 
+1,048,083 
+2,479,740 
+1,400,787 
+Louisiana Fee Properties 
+10,499 
+10,499 
+14,415 
+14,415 
+24,914 
+24,914 
+Louisiana Mineral Servitudes 
+7,426 
+4,217 
+4,769 
+4,407 
+12,195 
+8,624 
+17,925 
+14,716 
+19,184 
+18,822 
+37,109 
+33,538 
+Total(3) 
+725,485 
+367,420 
+1,791,364 
+1,066,905 
+2,516,849 
+1,434,325 
+(1) Developed acreage is acreage assigned to producing wells for the state approved spacing unit of the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but have only been included as developed acreage in the presentation above. 
+(2) Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas, regardless of whether such acreage contains estimated reserves. 
+(3) Subsequent to December 31, 2010, we divested certain non-strategic properties, which included leases covering approximately 5,281 and 4,623 gross and net developed acres, respectively, and 6,859 and 5,092 gross and net undeveloped acres, respectively. 
+Delivery Commitments 
+During 2010, we entered into natural gas gathering through-put commitments with various parties that require us to deliver a fixed determinable quantity of product. We have an aggregate minimum commitment to deliver 607 Bcf by the end of 2021. We will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. If a shortfall in the minimum volume commitment is projected, we have certain rights to arrange for third party gas to be delivered into the gathering lines and such volume will be counted towards our minimum commitment. We expect to fulfill the delivery commitment with our production from our development of our proved reserves, as well as the development of resources not yet characterized as proved reserves, from our Eagle Ford shale and Haynesville shale resource plays. At the current time, we do not have enough proved developed reserves to offset this contractual liability, but we intend to develop reserves that will exceed the through-put commitment. Therefore, we currently do not expect any shortfalls. 
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+Major Customers 
+During 2010, the Company had one customer, Regency Gas Services LLC, individually account for approximately 11 percent of our total oil and gas production revenue. During 2009, the Company had one customer, Teppco Crude Oil LLC, individually account for approximately 12 percent of the Company’s total oil and gas production revenue. During 2008, no customer individually accounted for ten percent or more of our total oil and gas production revenue. 
+Employees and Office Space 
+As of February 18, 2011, we had 569 full-time employees. None of our employees are subject to a collective bargaining agreement and we consider our relations with our employees to be good. As of December 31, 2010, we leased approximately 76,000 square feet of office space in Denver, Colorado for our executive and administrative offices; approximately 22,000 square feet of office space in Tulsa, Oklahoma; approximately 25,000 square feet in Shreveport, Louisiana; approximately 30,000 square feet in Houston, Texas; approximately 17,000 square feet in Midland, Texas; approximately 34,000 square feet in Billings, Montana; approximately 6,000 square feet in Williston, North Dakota; and approximately 2,000 square feet in Casper, Wyoming. 
+Title to Properties 
+Substantially all of our interests are held pursuant to leases from third parties. A title opinion is usually obtained prior to the commencement of initial drilling operations. We have obtained title opinions or have conducted a title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. The majority of our producing properties are subject to mortgages securing indebtedness under our credit facility, royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. We typically perform only minimal title investigation before acquiring undeveloped leasehold acreage. 
+Seasonality 
+Generally, but not always, the demand and price levels for natural gas increase during colder winter months and decrease during warmer summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity has placed increased demand on storage volumes. Demand for crude oil and heating oil is also generally higher in the winter and the summer driving season — although oil prices are much more driven by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. The impact of seasonality on crude oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of production capacity in excess of existing worldwide demand for crude oil. 
+Competition 
+The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We believe our leasehold position provides a sound foundation for a solid drilling program and our future growth. Our competitive position also depends on our geological, geophysical, and engineering expertise, and our financial resources. We believe the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams enable us to compete effectively in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies, which, in some cases, have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs, and generate electricity. 
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+We also compete with other oil and gas companies in attempting to secure drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells. Consequently, we may face shortages or delays in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may also be affected by future new energy, climate-related, financial, and other policies, legislation, and regulations. 
+In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals. Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the number of talented people available is constrained. We are not insulated from this resource constraint, and we must compete effectively in this market in order to be successful. 
+Government Regulations 
+Our business is extensively regulated by numerous federal, state, and local laws and governmental regulations. These laws and regulations may be changed from time to time in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations increase our cost of doing business and, consequently, affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry. 
+Energy Regulations. Many of the states in which we conduct our operations have adopted laws and regulations governing the exploration for and production of crude oil and natural gas, including laws and regulations requiring permits for the drilling of wells, imposing bonding requirements in order to drill or operate wells, and governing the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to various state conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the unitization or pooling of crude oil and natural gas properties. In addition, state conservation laws sometimes establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. 
+Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of Land Management (BLM). These leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. 
+In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes may increase the amount of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM. 
+Our sales of natural gas are affected by the availability, terms, and cost of natural gas pipeline transportation. The Federal Energy Regulatory Commission (FERC) has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce. The FERC’s current regulatory framework generally provides for a competitive and open access market for sales and transportation of natural gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for natural gas production. In addition, the less stringent regulatory approach currently pursued by the FERC and the U.S. Congress may not continue indefinitely. 
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+Environmental, Health, and Safety Regulations. Our operations are subject to stringent federal, state, and local laws and regulations relating to the protection of the environment and human health and safety. Environmental laws and regulations may require that permits be obtained before drilling commences, restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities, govern the handling and disposal of waste material, and limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, including areas containing endangered animal species. As a result, these laws and regulations may substantially increase the costs of exploring for, developing, or producing oil and gas and may prevent or delay the commencement or continuation of certain projects. In addition, these laws and regulations may impose substantial clean-up, remediation, and other obligations in the event of any discharges or emissions in violation of these laws and regulations. Further, legislative and regulatory initiatives related to global warming or climate change could have an adverse effect on our operations and the demand for oil and natural gas. See “Risk Factors — Risks Related to Our Business — Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.” 
+Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. For additional information about hydraulic fracturing and related regulatory matters, see “Risk Factors — Risks Related to Our Business — Proposed federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” 
+Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released, or produced in our operations. Some of this information must be provided to our employees, state and local governmental authorities, and local citizens. We are also subject to the requirements and reporting framework set forth in the federal workplace standards. 
+To date we have not experienced any materially adverse effect on our operations from obligations under environmental, health, and safety laws and regulations. We believe that we are in substantial compliance with currently applicable environmental, health, and safety laws and regulations, and that continued compliance with existing requirements would not have a materially adverse impact on us. 
+Cautionary Information about Forward-Looking Statements 
+This Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear in a number of places in this Form 10-K, and include statements about such matters as: 
+· the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures; 
+· the drilling of wells and other exploration and development activities and plans, as well as possible future acquisitions; 
+· the possible divestiture or farm-down of, or joint venture relating to, certain properties; 
+· proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those proved reserve estimates; 
+· future oil and natural gas production estimates; 
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+· our outlook on future oil and natural gas prices, well costs, and service costs; 
+· cash flows, anticipated liquidity, and the future repayment of debt; 
+· business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and 
+· other similar matters such as those discussed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in Item 7 of this report. 
+Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. These risks are described in the “Risk Factors” section in Item 1A of this report, and include such factors as: 
+· the volatility of oil and natural gas prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow; 
+· the continued weakness in economic conditions and uncertainty in financial markets; 
+· our ability to replace reserves in order to sustain production; 
+· our ability to raise the substantial amount of capital that is required to replace our reserves; 
+· our ability to compete against competitors that have greater financial, technical, and human resources; 
+· the imprecise estimations of our actual quantities and present values of proved oil and natural gas reserves; 
+· the uncertainty in evaluating recoverable reserves and other expected benefits or liabilities; 
+· the possibility that exploration and development drilling may not result in commercially producible reserves; 
+· the possibility that our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production; 
+· the uncertainties associated with enhanced recovery methods; 
+· our hedging activities may result in financial losses or may limit the prices that we receive for oil and natural gas sales; 
+· the inability of one or more of our customers to meet their obligations; 
+· price declines or unsuccessful exploration efforts result in write-downs of our asset carrying values; 
+· the impact that lower oil or natural gas prices could have on our ability to borrow under our credit facility; 
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+· the possibility that our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt; 
+· operating and environmental risks and hazards that could result in substantial losses; 
+· complex laws and regulations, including environmental regulations, that result in substantial costs and other risks; 
+· the availability and capacity of gathering, transportation, processing, and/or refining facilities; 
+· our ability to sell and/or receive market prices for our oil and natural gas; 
+· new technologies may cause our current exploration and drilling methods to become obsolete; and 
+· litigation, environmental matters, the potential impact of government regulations, and the use of management estimates regarding such matters. 
+We caution you that forward-looking statements are not guarantees of future performance and that actual results or performance may be materially different from those expressed or implied in the forward-looking statements. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws. 
+Available Information 
+Our internet website address is www.sm-energy.com. We routinely post important information for investors on our website. Within our website’s investor relations section we make available free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. We also make available through our website’s corporate governance section our Corporate Governance Guidelines, Code of Business Conduct and Ethics, and the Charters for our Board of Directors’ Audit Committee, Compensation Committee, Executive Committee, and Nominating and Corporate Governance Committee. Information on our website is not incorporated by reference into this report and should not be considered part of this document. 
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+Glossary of Oil and Gas Terms 
+The oil and gas terms defined in this section are used throughout this report. The definitions of the terms developed reserves, exploratory well, field, proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under SEC Rule 4-10(a) of Regulation S-X, as amended effective for fiscal years ending on or after December 31, 2009. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located through the SEC’s website at www.sec.gov. 
+Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used in reference to oil or other liquid hydrocarbons. 
+Bcf . Billion cubic feet, used in reference to natural gas. 
+BCFE. Billion cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of oil. 
+BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of oil. 
+Btu. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit. 
+Developed reserves. Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. 
+Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+Dry hole. A well found to be incapable of producing either oil or natural gas in commercial quantities. 
+Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. 
+Farmout. An assignment of an interest in a drilling location and related acreage conditioned upon the drilling of a well on that location. 
+Fee land. The most extensive interest that can be owned in land, including surface and mineral (including oil and natural gas) rights. 
+Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. 
+Finding cost. Expressed in dollars per MCFE. Finding cost metrics provide information as to the cost of adding proved reserves from various activities, and are widely utilized within the exploration and production industry, as well as by investors. The information used to calculate these metrics is included in Note 14 — Oil and Gas Activities and Note 15 — Disclosures about Oil and Gas Producing Activities of the Notes to Consolidated Financial Statements included in this report. It should be noted that finding cost metrics have limitations. For example, exploration efforts related to a particular set of proved reserve additions may extend over several years. As a result, the exploration costs incurred in earlier periods are not included in the amount of exploration costs incurred during the period in which that set of proved reserves is added. In addition, consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred. Since the additional development costs that will need to be incurred in the future before the proved undeveloped reserves are ultimately produced are not included in the amount of costs incurred during the period in which those reserves 
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+Table of Contents 
+were added, those development costs in future periods will be reflected in the costs associated with adding a different set of reserves. The calculations of various finding cost metrics are explained below. 
+Finding cost —Drilling, excluding revisions. Calculated by dividing the amount of costs incurred for development and exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, and infill drilling, during the same period. 
+Finding cost —Drilling, including revisions. Calculated by dividing the amount of costs incurred for development and exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, and infill drilling, and revisions of previous estimates during the same period. 
+Finding cost —Drilling and acquisitions , excluding revisions. Calculated by dividing the amount of costs incurred for development, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, and acquisitions during the same period. 
+Finding cost —Drilling and acquisitions , including revisions. Calculated by dividing the amount of costs incurred for development, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries, extensions, and infill drilling, revisions of previous estimates, and acquisitions during the same period. 
+Finding cost—All in, including sales of reserves. Calculated by dividing the amount of total capital expenditures for oil and natural gas activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates less sales of reserves during the same period. 
+Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions. 
+Gross acre. An acre in which a working interest is owned. 
+Gross well. A well in which a working interest is owned. 
+Horizontal wells. Wells which are drilled at angles greater than 70 degrees from vertical. 
+Lease operating expenses. The expenses incurred in the lifting of oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs. 
+MBbl. One thousand barrels of oil or other liquid hydrocarbons. 
+MMBbl. One million barrels of oil or other liquid hydrocarbons. 
+MBOE. One thousand BOE. 
+MMBOE. One million BOE. 
+Mcf. One thousand cubic feet, used in reference to natural gas. 
+MCFE. One thousand cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of oil. 
+MMcf. One million cubic feet, used in reference to natural gas. 
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+MMCFE. One million cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of oil. 
+MMBtu. One million British thermal units. 
+Net acres or net wells. The sum of our fractional working interests owned in gross acres or gross wells. 
+Net asset value per share. The result of the fair market value of total assets less total liabilities, divided by the total number of outstanding shares of common stock. 
+NGLs. The combination of ethane, propane, butane, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressures and lower temperatures. 
+NYMEX. New York Mercantile Exchange. 
+PV-10 value. The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual discount rate of ten percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period. 
+Productive well. A well that is producing oil or natural gas or that is capable of commercial production. 
+Proved reserves. Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 
+Recompletion. The completion in an existing wellbore in a formation other than that in which the well has previously been completed. 
+Reserve life. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period. 
+Reserve replacement. Reserve replacement metrics are used as indicators of a company’s ability to replenish annual production volumes and grow its reserves, and provide information related to how successful a company is at growing its proved reserve base. These are believed to be useful non-GAAP measures that are widely utilized within the exploration and production industry, as well as by investors. They are easily calculable metrics, and the information used to calculate these metrics is included in Note 14 — Disclosures about Oil and Gas Producing Activities of the Notes to Consolidated Financial Statements included in this report. It should be noted that reserve replacement metrics have limitations. They are limited because they typically vary widely based on the extent and timing of new discoveries and property acquisitions. Their predictive and comparative value is also limited for the same reasons. In addition, since the metrics do not embed the cost or timing of future production of new reserves, they cannot be used as a measure of value creation. The calculations of various reserve replacement metrics are explained below. 
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+Reserve replacement—Drilling, excluding revisions. Calculated as a numerator comprised of the sum of reserve extensions and discoveries and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling activity. 
+Reserve replacement—Drilling, including revisions. Calculated as a numerator comprised of the sum of reserve extensions, discoveries, and infill reserves, and revisions and previous estimates in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling activity. 
+Reserve replacement—Drilling and acquisitions , excluding revisions. Calculated as a numerator comprised of the sum of reserve acquisitions and reserve extensions and discoveries and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities. 
+Reserve replacement—Drilling and acquisitions , including revisions. Calculated as a numerator comprised of the sum of reserve acquisitions and reserve extensions, discoveries, and infill reserves, and revisions and previous estimates in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities. 
+Reserve replacement percentage—All in, excluding sales of reserves. The sum of reserve extensions and discoveries, infill drilling, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period. 
+Reserve replacement percentage—All in, including sales of reserves. The sum of sales of reserves, infill drilling, reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period. 
+Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 
+Resource play. A term used to describe an accumulation of oil and/or natural gas resources known to exist over a large areal expanse, which when compared to a conventional play typically has a lower expected geological and/or commercial development risk. 
+Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well. 
+Royalty interest. An interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production free of costs of exploration, development, and production operations. 
+Seismic. An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape, and depth of subsurface rock formations. 
+Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock. 
+Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year end costs, and statutory tax rates, and a ten percent annual discount rate. The information for this calculation is included in the note regarding disclosures about oil and gas producing activities contained in the Notes to Consolidated Financial Statements included in this report. 
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+Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains estimated net proved reserves. 
+Undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. 
+Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share in the production, sales, and costs. 
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+ITEM 1A. RISK FACTORS 
+In addition to the other information included in this report, the following risk factors should be carefully considered when evaluating an investment in SM Energy. 
+Risks Related to Our Business 
+Oil and natural gas prices are volatile, and declines in prices adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow. 
+Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and natural gas properties depend heavily on the prices we receive for oil and natural gas sales. Oil and natural gas prices also affect our cash flows available for capital expenditures and other items, our borrowing capacity, and the amount and value of our oil and natural gas reserves. For example, the amount of our borrowing base under our credit facility is subject to periodic redeterminations based on oil and natural gas prices specified by our bank group at the time of redetermination. In addition, we may have oil and natural gas property impairments or downward revisions of estimates of proved reserves if prices fall significantly. 
+Historically, the markets for oil and natural gas have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil and natural gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and other factors that are beyond our control, including: 
+· global and domestic supplies of oil and natural gas, and the productive capacity of the industry as a whole; 
+· the level of consumer demand for oil and natural gas; 
+· overall global and domestic economic conditions; 
+· weather conditions; 
+· the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas that may affect the realized price for oil, NGLs, or natural gas; 
+· the price and level of foreign imports of crude oil, refined petroleum products, and liquefied natural gas; 
+· the price and availability of alternative fuels; 
+· technological advances affecting energy consumption; 
+· the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; 
+· political instability or armed conflict in oil or natural gas producing regions; 
+· strengthening and weakening of the U.S. dollar relative to other currencies; and 
+· governmental regulations and taxes. 
+These factors and the volatility of oil and natural gas markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil or natural gas prices would reduce our revenues and could also reduce the amount of oil and natural gas that we can produce economically, which could have a materially adverse effect on us. 
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+Continued weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict. 
+U.S. and global economies and financial systems have recently experienced turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, increased levels of unemployment, and an unprecedented level of intervention by the U.S. federal government and other governments. Although some portions of the economy appear to have stabilized and there have been signs of the beginning of recovery, the extent and timing of a recovery, and whether it can be sustained, are uncertain. Continued weakness in the U.S. or other large economies could materially adversely affect our business and financial condition. For example: 
+· the demand for oil and natural gas in the U.S. has declined and may remain at low levels or further decline if economic conditions remain weak, and continue to negatively impact our revenues, margins, profitability, operating cash flows, liquidity, and financial condition; 
+· the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables; 
+· our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for exploration and/or development of our reserves; and 
+· our commodity hedging arrangements could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection. 
+If we are unable to replace reserves, we will not be able to sustain production. 
+Our future operations depend on our ability to find, develop, or acquire oil and natural gas reserves that are economically producible. Our properties produce oil and natural gas at a declining rate over time. In order to maintain current production rates, we must locate and develop or acquire new oil and natural gas reserves to replace those being depleted by production. In addition, competition for the acquisition of producing oil and natural gas properties is intense and many of our competitors have financial, technical, human, and other resources needed to evaluate and integrate acquisitions that are substantially greater than those available to us. Therefore, we may not be able to acquire oil and natural gas properties that contain economically producible reserves, or we may not be able to acquire such properties at prices acceptable to us. Without successful drilling or acquisition activities, our reserves, production, and revenues will decline over time. 
+Substantial capital is required to replace our reserves. 
+We must make substantial capital expenditures to find, acquire, develop, and produce oil and natural gas reserves. Future cash flows and the availability of financing are subject to a number of factors, such as the level of production from existing wells, prices received for oil and natural gas sales, our success in locating and developing and acquiring new reserves, and the orderly functioning of credit and capital markets. If oil or natural gas prices decrease or if we encounter operating difficulties that result in our cash flows from operations being less than expected, we must reduce our capital expenditures unless we can raise additional funds through debt or equity financing or the divestment of assets. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms, and the proceeds offered to us for potential divestitures may not always be of acceptable value to us. 
+If our revenues decrease due to lower oil, natural gas, or NGL prices, decreased production, or other reasons, and if we cannot obtain capital through our credit facility, other acceptable debt or equity financing arrangements, or through the sale of assets, our ability to execute development plans, replace our reserves, maintain our acreage, or maintain production levels could be greatly limited. 
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+Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do. 
+We face intense competition from major oil and gas companies, independent oil and natural gas exploration and production companies, financial buyers, and institutional and individual investors who seek oil and natural gas property investments throughout the world, as well as the equipment, expertise, labor, and materials required to operate oil and natural gas properties. Many of our competitors have financial, technical, and other resources vastly exceeding those available to us, and many oil and natural gas properties are sold in a competitive bidding process in which our competitors may be able and willing to pay more for development prospects and productive properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for the properties. In addition, shortages of equipment, labor, or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. We may not be successful in acquiring and developing profitable properties in the face of this competition. 
+We also compete for human resources. Over the last few years, the need for talented people across all disciplines in the industry has grown, while the number of talented people available has been constrained. 
+The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated. 
+This report and other SEC filings by us contain estimates of our proved oil and natural gas reserves and the estimated future net revenues from those reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, timing of operations, and availability of funds. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent on many variables, and therefore changes often occur as these variables evolve. Therefore, these estimates are inherently imprecise. 
+Actual future production, oil and natural gas prices, revenues, production taxes, development expenditures, operating expenses, and quantities of producible oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities of and present values related to proved reserves disclosed by us, and the actual quantities and present values may be less than we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development activity, prevailing oil and natural gas prices, costs to develop and operate properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties. 
+As of December 31, 2010, approximately 30 percent, or 297.2 BCFE, of our estimated proved reserves were proved undeveloped, and approximately eight percent, or 75.4 BCFE, were proved developed non-producing. Estimates of proved undeveloped reserves and proved developed non-producing reserves are nearly always based on volumetric calculations rather than the performance data used to estimate producing reserves. In order to develop our proved undeveloped reserves, we estimate approximately $699 million of capital expenditures would be required. Production revenues from proved developed non-producing reserves will not be realized until sometime in the future and after some investment of capital. In order to bring production on-line for our proved developed non-producing reserves, we estimate capital expenditures of approximately $43 million will be deployed in future years. Although we have estimated our reserves and the costs associated with these reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated. The balance of our currently anticipated capital expenditures for 2011 is directed towards projects that are not yet classified within the construct of proved reserves as defined by Regulation S-X promulgated by the SEC. 
+You should not assume that the PV-10 value and standardized measure of discounted future net cash flows included in this report represent the current market value of our estimated proved oil and natural gas 
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+reserves. Management has based the estimated discounted future net cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. For example, values of our reserves as of December 31, 2010, were estimated using a calculated 12-month average sales price of $4.38 per MMBtu of natural gas (NYMEX Henry Hub spot price) and $79.43 per Bbl of oil (NYMEX West Texas Intermediate spot price). We then adjust these base prices to reflect appropriate basis, quality, and location differentials over that period in estimating our proved reserves. During 2010, our monthly average realized natural gas prices, excluding the effect of hedging, were as high as $6.43 per Mcf and as low as $4.37 per Mcf. For the same period, our monthly average realized oil prices before hedging were as high as $83.40 per Bbl and as low as $66.59 per Bbl. Many other factors will affect actual future net cash flows, including: 
+· amount and timing of actual production; 
+· supply and demand for oil and natural gas; 
+· curtailments or increases in consumption by oil purchasers and natural gas pipelines; and 
+· changes in government regulations or taxes. 
+The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing PV-10 values. In addition, the ten percent discount factor required by the SEC to be used to calculate PV-10 values for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and natural gas industry in general are subject. 
+Reserve estimates as of December 31, 2010 and 2009 have been prepared under the SEC’s new rules for oil and gas reporting that were effective for fiscal years ending on or after December 31, 2009. These new rules require SEC reporting companies to prepare their reserve estimates using, among other things, revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing, instead of the prior requirement to use pricing at the end of the period. The SEC has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules and may not issue further interpretive guidance on the new rules in the near future. The interpretation of these rules and their applicability in different situations remains unclear in many respects. Changing interpretations of the rules or disagreements with our interpretations could result in revisions to our reserve estimates, which could be significant. 
+Our property acquisitions may not be worth what we paid due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities. 
+Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include exploration potential, future oil and natural gas prices, operating costs, and potential environmental and other liabilities. These assessments are not precise and their accuracy is inherently uncertain. 
+In connection with our acquisitions, we typically perform a customary review of the acquired properties that will not necessarily reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. 
+In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent acquired properties are substantially different than our 
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+existing properties, our ability to efficiently realize the expected economic benefits of such acquisitions may be limited. 
+Integrating acquired properties and businesses involves a number of other special risks, including the risk that management may be distracted from normal business concerns by the need to integrate operations and systems as well as retain and assimilate additional employees. Therefore, we may not be able to realize all of the anticipated benefits of our acquisitions. 
+Exploration and development drilling may not result in commercially producible reserves. 
+Oil and natural gas drilling and production activities are subject to numerous risks, including the risk that no commercially producible oil or natural gas will be found. The cost of drilling and completing wells is often uncertain, and oil and natural gas drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors include: 
+· unexpected drilling conditions; 
+· title problems; 
+· pressure or geologic irregularities in formations; 
+· equipment failures or accidents; 
+· hurricanes or other adverse weather conditions; 
+· compliance with environmental and other governmental requirements; and 
+· shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, and supplies. 
+The prevailing prices of oil and natural gas affect the cost of and the demand for drilling rigs, completion and production equipment, and other related services. However, changes in costs may not occur simultaneously with corresponding changes in commodity prices. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region. In addition, the recent economic and financial downturn has adversely affected the financial condition of some drilling contractors, which may constrain the availability of drilling services in some areas. 
+Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays which jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a materially adverse effect on our ability to explore on or develop our properties. 
+The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well if oil or natural gas is present, or whether it can be produced economically. The cost of drilling, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling and completion costs. 
+Drilling results in our newer shale plays, such as the Eagle Ford and Haynesville shales, may be more uncertain than in shale plays that are more developed and have longer established production histories. For 
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+example, our experience with horizontal drilling in these shales, as well as the industry’s drilling and production history, is more limited than in the Woodford shale play, and we have less information with respect to the ultimate recoverable reserves and the production decline rates in these shales than we have in other areas in which we operate. Completion techniques that have proven to be successful in other shale formations to maximize recoveries are being used in the early development of these new shales; however, we can provide no assurance of the ultimate success of these drilling and completion techniques. As a result, we may face significant opposition to our operations in that area that may make it difficult to obtain permits and other needed authorizations to operate or otherwise make operating more costly or difficult than operating elsewhere. 
+In addition, a significant part of our strategy involves increasing our inventory of drilling locations. Such multi-year drilling inventories can be more susceptible to long-term horizon uncertainties that could materially alter the occurrence or timing of actual drilling. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled, although we have the present intent to do so, or if we will be able to produce oil or natural gas from these or any other potential drilling locations. 
+Our future drilling activities may not be successful. Our overall drilling success rate or our drilling success rate within a particular area may decline. In addition, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we may not be able to economically produce oil or natural gas from all of them. 
+Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful. 
+Many of our operations involve utilizing the latest drilling and completion techniques as developed by ourselves and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore, and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations, and successfully cleaning out the well bore after completion of the final fracture stimulation stage. 
+Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or natural gas and oil prices decline, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future. 
+Uncertainties associated with enhanced recovery methods may result in us not realizing an acceptable return on our investments in such projects. 
+We inject water into formations on some of our properties to increase the production of oil and natural gas. We may in the future expand these efforts to more of our properties or employ other enhanced recovery methods in our operations. The additional production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of oil and natural gas in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects. In addition, if proposed legislation and regulatory initiatives relating to hydraulic fracturing become law, the cost of some of these enhanced recovery methods could increase substantially. 
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+Our hedging activities may result in financial losses or may limit the prices that we receive for oil and natural gas sales. 
+To manage our exposure to price risks in the sale of our oil and natural gas production, we enter into commodity price risk management arrangements periodically with respect to a portion of our current or future production. We have hedged a portion of anticipated future production from our currently producing properties using zero-cost collars and swaps. As of December 31, 2010, we were in a net accrued liability position of approximately $52.3 million with respect to our oil and natural gas hedging activities. These activities may expose us to the risk of financial loss in certain circumstances, including instances in which: 
+· our production is less than expected; 
+· one or more counterparties to our hedge contracts default on their contractual obligations; or 
+· there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement. 
+The risk of one or more counterparties defaulting on their obligations is heightened by the recent global and domestic economic and financial downturn affecting many banks and other financial institutions, including our counterparties and their affiliates. These circumstances may adversely affect the ability of our counterparties to meet their obligations to us pursuant to hedge transactions, which could reduce our revenues and cash flows from realized hedge settlements. As a result, our financial condition, results of operations, and cash flows could be materially affected in an adverse way if our counterparties default on their contractual obligations under our hedge contracts. 
+In addition, commodity price hedging may limit the prices that we receive for our oil and natural gas sales if oil or natural gas prices rise substantially over the price established by the hedge. Some of our hedging transactions use derivative instruments that may involve basis risk. Basis risk in a hedging contract can occur when the change in the index upon which the hedge is based does not correlate well to the change in the index upon which the hedged production is valued, thereby making the hedge less effective. For example, a change in the NYMEX price used for hedging certain volumes of production may not correlate exactly to the change in the regional price used for the sale of that production. 
+The inability of one or more of our customers to meet their obligations may adversely affect our financial results. 
+Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by various economic and other conditions, including the recent global and domestic economic and financial downturn. 
+Future oil and natural gas price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values. 
+We follow the successful efforts method of accounting for our oil and natural gas properties. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed. 
+The capitalized costs of our oil and natural gas properties, on a field basis, cannot exceed the estimated undiscounted future net cash flows of that field. If net capitalized costs exceed undiscounted future net revenues, we generally must write down the costs of each such field to the estimated discounted future net cash flows of that field. Unproved properties are evaluated at the lower of cost or fair market value. As a result of significant oil and natural gas price declines in the second half of 2008, we incurred impairment of proved property write-downs, impairment of unproved properties, and goodwill impairment totaling $302.2 million, $39.0 million, and $9.5 million, respectively, during 2008. In addition, we incurred impairment of proved property write-downs and 
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+impairment of unproved properties totaling $174.8 million and $45.4 million, respectively, during 2009, and $6.1 million and $2.0 million, respectively, during 2010. Significant further declines in oil or natural gas prices in the future or unsuccessful exploration efforts could cause further impairment write-downs of capitalized costs. 
+We review quarterly the carrying value of our properties for indicators of impairment based on prices in effect as of the end of each quarter. Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date, even if oil or natural gas prices increase. 
+Lower oil or natural gas prices could limit our ability to borrow under our credit facility. 
+Our credit facility has a maximum commitment amount of $678.0 million, subject to a borrowing base that the lenders periodically redetermine based on the bank group’s assessment of the value of our oil and natural gas properties, which in turn is based in part on oil and natural gas prices. The current borrowing base under our credit facility is $1.0 billion. Pursuant to the terms of our credit facility, the borrowing base was reduced from the previous $1.1 billion borrowing base upon the issuance of our 6.625% Senior Notes, which occurred on February 7, 2011. Declines in oil or natural gas prices in the future could limit our borrowing base and reduce our ability to borrow under our credit facility. Additionally, divestitures of properties could result in a reduction of our borrowing base. 
+Our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt. 
+As of December 31, 2010, we had $275.7 million, net of debt discount, of total long-term senior unsecured debt outstanding under our 3.50% Senior Convertible Notes due 2027 (the “3.50% Senior Convertible Notes”), and $48.0 million of secured debt outstanding under our credit facility. We have a single letter of credit outstanding under our credit facility, in the amount of $483,000 as of February 18, 2011, which reduces the amount available under the commitment amount on a dollar-for-dollar basis. As of February 18, 2011, we had no outstanding borrowings under our credit facility, resulting in $677.5 million of available debt capacity under our credit facility assuming the borrowing conditions of this facility were met, and an additional $350.0 million of long-term senior unsecured debt outstanding related to our 6.625% Senior Notes that we issued on February 7, 2011. Our long-term debt represented 21 percent of our total book capitalization as of December 31, 2010. Adjusting for our 6.625% Senior Notes, our long-term debt would have represented 34 percent of our total book capitalization as of December 31, 2010. 
+Our amount of debt could have important consequences for our operations, including: 
+· making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements; 
+· requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to productive investments; 
+· limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends; 
+· placing us at a competitive disadvantage compared to our competitors that have less debt; and 
+· making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business. 
+Our ability to make payments on our debt and to refinance our debt and fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory, and other factors that are beyond our control. If our business does 
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+not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our credit facility or from other sources, we might not be able to service our debt or fund our other liquidity needs. If we are unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity securities, sell assets, or restructure or refinance our debt. We might not be able to sell our equity securities, sell our assets, or restructure or refinance our debt on a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our existing and future credit agreements, may prohibit us from pursuing any of these alternatives. Further, changes in the credit ratings of our debt may negatively affect the cost, terms, conditions, and availability of future financing. The indenture under our 3.50% Senior Convertible Notes provides that under certain circumstances we have the option to settle our obligations under these Notes through the issuance of shares of our common stock if we so elect. 
+Our debt agreements, including the agreement governing our credit facility and the indenture governing the 6.625% Senior Notes, also permit us to incur additional debt in the future, subject to compliance with restrictive covenants under those agreements. In addition, entities we may acquire in the future could have significant amounts of debt outstanding which we could be required to assume, and in some cases accelerate repayment thereof, in connection with the acquisition, or we may incur our own significant indebtedness to consummate an acquisition. 
+As discussed above, our credit facility is subject to periodic borrowing base redeterminations. We could be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowing base or arrange new financing, we may be forced to sell significant assets. 
+The agreements governing our debt contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the acceleration of our debt. 
+Our debt agreements contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under our credit facility is subject to compliance with certain financial covenants, including (i) maintenance of a quarterly ratio of total debt to consolidated earnings before interest, taxes, depreciation, and amortization of no greater than 3.5 to 1.0, and (ii) maintenance of a current ratio of no less than 1.0 to 1.0, each as defined in our credit facility. Our credit facility also requires us to comply with certain financial covenants, including requirements that we maintain certain levels of stockholders’ equity and limit our annual dividend rate to no more than $0.25 per share. These restrictions on our ability to operate our business could seriously harm our business by, among other things, limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate opportunities. 
+The indenture governing the 6.625% Senior Notes also contains covenants that, among other things, limit our ability and the ability, of our subsidiaries to: 
+· incur additional debt; 
+· make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire capital stock; 
+· sell assets, including capital stock of our subsidiaries; 
+· restrict dividends or other payments of our subsidiaries; 
+· create liens that secure debt; 
+· enter into transactions with affiliates; and 
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+· merge or consolidate with another company. 
+Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness. 
+We are subject to operating and environmental risks and hazards that could result in substantial losses. 
+Oil and natural gas operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas, or well fluids, fires, adverse weather such as hurricanes in the South Texas & Gulf Coast region, freezing conditions in the Williston Basin of our Rocky Mountain region, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas, and other environmental risks and hazards. If any of these types of events occurs, we could sustain substantial losses. 
+Under certain limited circumstances we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease, or operate. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur losses. 
+We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden environmental damages. We do not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damages or insurance coverage for environmental damage that occurs over time is available at a reasonable cost. In addition, pollution and environmental risks generally are not fully insurable. Further, we may elect not to obtain other insurance coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks to which we are subject. Accordingly, we may be subject to liability or may lose substantial assets in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer a material loss. 
+Following the severe Atlantic hurricanes in 2004, 2005, and 2008, the insurance markets suffered significant losses. As a result, insurance coverage for wind storms has become substantially more expensive, and future availability and costs of coverage are uncertain. 
+Our operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs and other risks. 
+Federal, state, and local authorities extensively regulate the oil and natural gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of oil and natural gas production. Noncompliance with statutes and regulations may lead to substantial penalties, and the overall regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability. 
+Governmental authorities regulate various aspects of oil and natural gas drilling and production, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of interests in oil and natural gas properties, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging and abandonment standards, and restoration. Under certain circumstances, federal authorities may require any of our ongoing or planned operations on federal leases to be delayed, suspended, or terminated. Any such delay, suspension, or termination could have a materially adverse effect on our operations. 
+Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. 
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+Under existing or future environmental laws and regulations, we could face significant liability to governmental authorities and third parties, including joint and several as well as strict liability, for discharges of oil, natural gas, or other pollutants into the air, soil, or water, and we could be required to spend substantial amounts on investigations, litigation, and remediation. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a materially adverse effect on us. 
+Proposed federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. 
+Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. We routinely utilize hydraulic fracturing techniques in many of our reservoirs, and our Eagle Ford, Haynesville, and Woodford shale programs utilize or contemplate the utilization of hydraulic fracturing. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the U.S. Environmental Protection Agency, or the EPA, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. 
+Proposed legislation to eliminate or reduce certain federal income tax incentives and deductions available to oil and gas exploration and production companies could, if enacted into law, have a material adverse effect on our results of operations and cash flows. 
+President Obama’s budget proposal for the fiscal year 2011 recommended the elimination of certain key U.S. federal income tax preferences currently available to coal, oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States production activities, and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for, or development of, oil or gas within the United States. 
+It is unclear whether any such changes will actually be enacted or, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of the Budget Proposal or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and gas exploration and production. 
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+Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas. 
+In December 2009, the EPA determined that emissions of carbon dioxide, methane and other ‘‘greenhouse gases’’ present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act, or CAA. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011. 
+In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. 
+The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, NGLs, and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. 
+The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. 
+The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission (the CFTC) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade execution requirements in connection with its derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. 
+35 
+Table of Contents 
+The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows. 
+Our ability to sell oil, natural gas and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines and other transportation systems owned or operated by others or by other interruptions. 
+The marketability of our oil, natural gas and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing facilities and pipeline and other transportation systems owned or operated by third parties. The lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay or discontinuance of development plans for our properties, or lower price realizations. Although we have some contractual control over the processing and transportation of our production, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process and transport oil, natural gas and NGLs. 
+In particular, if drilling in the Eagle Ford, Haynesville, Granite Wash, and Marcellus plays continues to be successful, the amount of crude oil, NGLs and natural gas being produced by us and others could exceed the capacity of, and result in strains on, the various gathering, and transportation systems, pipelines, processing facilities, and other infrastructure available in these areas. It will be necessary for additional infrastructure, pipelines, gathering, and transportation systems and processing facilities to be expanded, built or developed to accommodate anticipated production from these areas. Because of the current economic climate, certain processing or pipeline and other gathering or transportation projects that might be, or are being, considered for these areas may not be developed timely or at all due to lack of financing or other constraints. In addition, capital and other constraints could limit our ability to build or access intrastate gathering and transportation systems necessary to transport our production to interstate pipelines or other points of sale or delivery. In such event, we might have to delay or discontinue development activities or shut in our wells to wait for sufficient infrastructure development or capacity expansion and/or sell production at significantly lower prices than those quoted on NYMEX, which would adversely affect our results of operations and cash flows. 
+A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flows and results of operations. 
+New technologies may cause our current exploration and drilling methods to become obsolete . 
+The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to 
+36 
+Table of Contents 
+implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected. 
+Risks Related to Our Common Stock 
+The price of our common stock may fluctuate significantly, which may result in losses for investors. 
+From January 1, 2010 to February 18, 2011, the closing daily sale price of our common stock as reported by the New York Stock Exchange ranged from a low of $31.64 per share in February 2010 to a high of $66.39 per share in February 2011. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include: 
+· changes in oil or natural gas prices; 
+· variations in quarterly drilling, recompletions, acquisitions, and operating results; 
+· changes in financial estimates by securities analysts; 
+· changes in market valuations of comparable companies; 
+· additions or departures of key personnel; 
+· future sales of our common stock; and 
+· changes in the national and global economic outlook. 
+We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could decline as a result. 
+Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment. 
+Our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or preventing a change of control. These provisions, among other things, provide for non-cumulative voting in the election of members of the Board of Directors and impose procedural requirements on stockholders who wish to make nominations for the election of directors or propose other actions at stockholder meetings. These provisions, alone or in combination with each other and with the shareholder rights plan described below, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock. 
+Under our shareholder rights plan, if the Board of Directors determines that the terms of a potential acquisition do not reflect the long-term value of SM Energy, the Board of Directors could allow the holder of each outstanding share of our common stock, other than those held by the potential acquirer, to purchase one additional share of our common stock with a market value of twice the exercise price. This prospective dilution to a potential acquirer would make the acquisition impracticable unless the terms were improved to the satisfaction of the Board of Directors. The existence of the plan may impede a takeover not supported by our Board of Directors, even though such takeover may be desired by a majority of our stockholders or may involve a premium over the prevailing stock price. 
+37 
+Table of Contents 
+Shares eligible for future sale may cause the market price of our common stock to drop significantly, even if our business is doing well. 
+The potential for sales of substantial amounts of our common stock in the public market may have a materially adverse effect on our stock price. As of February 18, 2011, 63,335,590 million shares of our common stock were freely tradable without substantial restriction or the requirement of future registration under the Securities Act of 1933. Also as of that date, options to purchase 795,496 shares of our common stock were outstanding, all of which were exercisable. These options are exercisable at prices ranging from $7.97 to $20.87 per share. In addition, restricted stock units (“RSUs”) providing for the issuance of up to a total of 335,809 shares of our common stock and 1,381,929 performance share awards (“PSAs”) were outstanding. The PSAs represent the right to receive, upon settlement of the PSAs after the completion of a three-year performance period, a number of shares of our common stock that may be from zero to two times the number of PSAs granted, depending on the extent to which the underlying performance criteria have been achieved and the extent to which the PSAs have vested. As of February 18, 2011, there were 63,435,434 shares of our common stock outstanding, which is net of 102,635 treasury shares. 
+We may not always pay dividends on our common stock. 
+Payment of future dividends remains at the discretion of the Board of Directors, and will continue to depend on our earnings, capital requirements, financial condition, and other factors. In addition, the payment of dividends is subject to covenants in our credit facility, including a covenant regarding the level of our current ratio of current assets to current liabilities and a limit on the annual dividend rate that we may pay to no more than $0.25 per share, and to covenants in the indenture for our 6.625% Senior Notes that limit our ability to pay dividends beyond a certain amount. The Board of Directors may determine in the future to reduce the current semi-annual dividend rate of $0.05 per share, or discontinue the payment of dividends altogether. 
+38 
+Table of Contents 
+ITEM 1B. UNRESOLVED STAFF COMMENTS 
+SM Energy has no unresolved comments from the SEC staff regarding its periodic or current reports under the Securities Exchange Act of 1934. 
+ITEM 3. LEGAL PROCEEDINGS 
+From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. As of the date of this report no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows. 
+We note that approximately 22,000 acres of our approximately 250,000 net acres in the Eagle Ford shale play in South Texas are the subject of a lawsuit captioned W.H. Sutton, et al. vs. St. Mary Land & Exploration Co., et al. instituted in the District Court of Webb County in and for the 49 th Judicial District of Texas on May 13, 2010. The plaintiffs claim an aggregate overriding royalty interest of 7.46875% in production attributable to a 1966 oil, gas and mineral lease, and that such overriding royalty interest attaches to subsequent leases currently affecting the acreage that is the subject of the lawsuit, which had been released from the 1966 lease. The plaintiffs seek to quiet title to their claimed overriding royalty interest and the recovery of unpaid overriding royalty interest proceeds allegedly due. We believe that the claimed overriding royalty interest has been terminated under the governing agreements and the applicable law, and filed an answer denying the plaintiffs’ claims. Both parties filed motions for summary judgment, and on February 8, 2011, the District Court issued an order granting plaintiffs’ motion for summary judgment and denying our motion for summary judgment. The order granting plaintiffs’ motion for summary judgment did not award damages but reserved such determination for final order. We believe that the summary judgment is incorrect under the governing agreements and applicable law, and intend to appeal. On February 16, 2011, the plaintiffs filed a motion requesting that the court enter final judgment in favor of plaintiffs and requesting the award of damages of approximately $6.6 million, including attorneys’ fees of approximately $1.9 million. 
+We believe this lawsuit is entirely without merit and will continue to vigorously contest this litigation. However, we cannot predict the ultimate outcome of this lawsuit. If the plaintiffs were to ultimately prevail, the overriding royalty interest would have the effect of reducing our net revenue interest in the affected acreage, which would negatively impact our economics in this portion of our acreage, but we do not believe would have a material adverse effect upon our financial condition, results of operations or cash flows, taken as a whole. For a more detailed discussion of our Eagle Ford shale play, see Core Operational Areas, South Texas & Gulf Coast Region in Part I, Items 1. and 2. of this report. 
+ITEM 4. [REMOVED AND RESERVED] 
+39 
+Table of Contents 
+EXECUTIVE OFFICERS OF THE REGISTRANT 
+The following table sets forth the names, ages and positions held by SM Energy’s executive officers. The age of the executive officers is as of February 18, 2011. 
+Name 
+Age 
+Position 
+Anthony J. Best 
+61 
+Chief Executive Officer and President 
+Javan D. Ottoson 
+52 
+Executive Vice President and Chief Operating Officer 
+A. Wade Pursell 
+45 
+Executive Vice President and Chief Financial Officer 
+David W. Copeland 
+54 
+Senior Vice President and General Counsel 
+Gregory T. Leyendecker 
+53 
+Senior Vice President and Regional Manager 
+Mark D. Mueller 
+46 
+Senior Vice President and Regional Manager 
+Lehman E. Newton, III 
+55 
+Senior Vice President and Regional Manager 
+Stephen C. Pugh 
+52 
+Senior Vice President and Regional Manager 
+Paul M. Veatch 
+44 
+Senior Vice President and Regional Manager 
+Dennis A. Zubieta 
+44 
+Vice President—Engineering and Evaluation 
+Mark T. Solomon 
+42 
+Controller 
+Anthony J. Best. Mr. Best joined the Company in June 2006 as President and Chief Operating Officer. In December 2006, Mr. Best relinquished his position as Chief Operating Officer when Javan D. Ottoson was elected to that office. Mr. Best was elected Chief Executive Officer of the Company in February 2007. From November 2005 to June 2006, Mr. Best was developing a business plan and securing capital commitments for a new exploration and production entity. From 2003 to October 2005, Mr. Best was President and Chief Executive Officer of Pure Resources, Inc., an independent oil and natural gas exploration and production company that was a subsidiary of Unocal, where he managed all of Unocal’s onshore U.S. assets. From 2000 to 2002, Mr. Best had an oil and gas consulting practice, working with various energy firms. From 1979 to 2000, Mr. Best was with ARCO in a variety of positions, including serving as President—ARCO Latin America, President—ARCO Permian, Field Manager for Prudhoe Bay and VP—External Affairs for ARCO Alaska. Mr. Best has over 30 years of experience in the energy industry. 
+Javan D. Ottoson. Mr. Ottoson joined the Company in December 2006 as Executive Vice President and Chief Operating Officer. Mr. Ottoson has been in the energy industry for over 25 years. From April 2006 until he joined the Company in December 2006, Mr. Ottoson was Senior Vice President—Drilling and Engineering at Energy Partners, Ltd., an independent oil and natural gas exploration and production company, where his responsibilities included overseeing all aspects of its drilling and engineering functions. Mr. Ottoson managed Permian Basin assets for Pure Resources, Inc., a Unocal subsidiary, and its successor owner, Chevron, from July 2003 to April 2006. From April 2000 to July 2003, Mr. Ottoson owned and operated a homebuilding company in Colorado and ran his family farm. Prior to 2000 Mr. Ottoson worked for ARCO in a variety of management and operational roles, including serving as President of ARCO China, Commercial Director of ARCO United Kingdom, and Vice President of Operations and Development, ARCO Permian. 
+A. Wade Pursell. Mr. Pursell joined the Company in September 2008 as Executive Vice President and Chief Financial Officer. Mr. Pursell was Executive Vice President and Chief Financial Officer for Helix Energy Solutions Group, Inc., a global provider of life-of-field services and development solutions to offshore energy producers and an oil and gas producer, from February 2007 to September 2008. From October 2000 to February 2007, he was Senior Vice President and Chief Financial Officer of Helix. He joined Helix in May 1997, as Vice President—Finance and Chief Accounting Officer. From 1988 through May 1997, Mr. Pursell was with Arthur Andersen LLP, serving lastly as an Experienced Manager specializing in the offshore services industry. Mr. Pursell has over 24 years of experience in the energy industry. 
+David W. Copeland. Mr. Copeland joined the Company in January 2011 as Senior Vice President and General Counsel. Mr. Copeland has over 28 years of experience in the legal profession, including over 19 years as internal counsel for various energy companies. Prior to joining the Company, he served at Concho Resources Inc., in Midland, Texas, as its Vice President, General Counsel and Secretary from April 2004 through November 5, 
+40 
+Table of Contents 
+2009, and then as its Senior Counsel through December 31, 2010. From August 1997 through March 2004, Mr. Copeland served as an executive officer and general counsel of two energy companies he co-founded in Midland, Texas with others. Mr. Copeland started his career in 1982 with the Stubbeman, McRae, Sealy, Laughlin & Browder law firm in Midland, Texas. 
+Gregory T. Leyendecker. Mr. Leyendecker was appointed Senior Vice President and Regional Manager in May 2010. From July 2007 to May 2010, he served as Vice President and Regional Manager. Mr. Leyendecker joined the Company in December 2006 as Operations Manager for the South Texas & Gulf Coast Region in Houston, Texas. Mr. Leyendecker has over 28 years in the energy industry, and held various positions with Unocal Corporation, an independent oil and natural gas exploration and production company, from 1980 until its acquisition in 2005. During his career with Unocal, he was the Asset Manager for Unocal Gulf Region USA from 2003 to June 2004 and Production and Reservoir Engineering Technology Manager for Unocal from June 2004 to August 2005. He was appointed Drilling and Workover Manager for the San Joaquin Valley business unit of Chevron, as successor-by-merger of Unocal Corporation, in Bakersfield, California in August 2005, and held this position until January 2006. Immediately prior to joining the Company, Mr. Leyendecker was Vice President of Drilling Management Services from February 2006 to November 2006 for Enventure Global Technology, a provider of solid expandable tubular technology. 
+Mark D. Mueller. Mr. Mueller joined the Company in September 2007 as Senior Vice President. Mr. Mueller was appointed as the Regional Manager of the Rocky Mountain Region effective January 1, 2008. Mr. Mueller has been in the energy industry for over 24 years. From September 2006 to September 2007, he was Vice President and General Manager at Samson Exploration Ltd., an oil and gas exploration and production company that was a subsidiary of Samson Investment Company, in Calgary, Canada, where his responsibilities included fiscal performance, reserves, and all operational functions of the company. From April 2005 until its sale in August 2006, Mr. Mueller was Vice President and General Manager for Samson Canada Ltd., an oil and gas exploration and production company that was a subsidiary of Samson Investment Company, where he was responsible for all business units and the eventual sale of the company. Mr. Mueller joined Samson Canada Ltd. as Project Manager in May 2003 to build a new basin-centered gas business unit and was Vice President from December 2003 to August 2006. Prior to joining Samson, Mr. Mueller was West Central Alberta Engineering Manager for Northrock Resources Ltd., a Canadian oil and gas company that was a wholly-owned subsidiary of Unocal Corporation, in Calgary, Canada. From 1986 to 2003, Mr. Mueller held positions of increasing responsibility in engineering and management for Unocal throughout North America and Southeast Asia. 
+Lehman E. Newton, III. Mr. Newton joined the Company in December 2006 as General Manager for the Midland, Texas office, was appointed Vice President and Regional Manager of the Permian region in June 2007, and was appointed Senior Vice President and Regional Manager in May 2010. Mr. Newton has over 33 years of experience in the energy industry. From November 2005 to November 2006, Mr. Newton served as Project Manager for one of Chevron’s largest Lower 48 projects. Mr. Newton joined Pure Resources in February 2003 as the Business Development Manager and worked in that capacity until October 2005. Mr. Newton was a founding partner in Westwin Energy, an independent Permian Basin exploration and production company, from June 2000 to January 2003. Prior to that, Mr. Newton spent 21 years with ARCO in various engineering, operations and management roles, including as Asset Manager, ARCO’s East Texas operations, Vice President, Business Development, ARCO Permian, and Vice President of Operations and Development, ARCO Permian. 
+Stephen C. Pugh. Mr. Pugh joined the Company as Senior Vice President and Regional Manager of the ArkLaTex Region in July 2007. Mr. Pugh has over 29 years of experience in the energy industry. Prior to joining the Company, Mr. Pugh was Managing Director for Scotia Waterous, a global leader in oil and gas merger and acquisition advisory services from July 2006 to July 2007. Mr. Pugh was responsible for new business development, managing client relationships and providing merger and acquisition advice to clients in the energy sector. Prior to joining Scotia Waterous, Mr. Pugh had over 17 years of experience in acquisitions and divestitures, operations and engineering with Burlington Resources, and its successor-by-merger, ConocoPhillips. His most recent position with Burlington Resources, Inc. and ConocoPhillips was General Manager, Engineering and Operations—Gulf Coast, a position he held from May 2004 to June 2006. Prior to that, he was Vice President—Acquisitions and Divestitures for Burlington Resources Canada. He held that position from May 2000 
+41 
+Table of Contents 
+to May 2004. Mr. Pugh began his career with Superior Oil (subsequently Mobil Oil) in Lafayette, Louisiana, where he worked in production, drilling, and reservoir engineering. 
+Paul M. Veatch. Mr. Veatch was appointed Senior Vice President and Regional Manager of the Company in March 2006. Mr. Veatch joined the Company in April 2001 as Regional A & D Engineer. He served as the Company’s Vice President—General Manager, ArkLaTex from August 2004 to March 2006, and Manager of Engineering for the ArkLaTex region from April 2003 to August 2004. Mr. Veatch has over 21 years of experience in the energy industry. 
+Dennis A. Zubieta. Mr. Zubieta was appointed Vice President—Engineering and Evaluation of the Company in August 2008. Mr. Zubieta joined the Company in June 2000 as Corporate A&D Engineer, assumed the role of Reservoir Engineer in February 2003, and was appointed Reservoir Engineering Manager in August 2005. Mr. Zubieta was employed by Burlington Resources from June 1988 to May 2000 in various operations and reservoir engineering capacities. Mr. Zubieta has over 22 years of experience in the energy industry. 
+Mark T. Solomon. Mr. Solomon was appointed Controller of the Company in January 2007. Mr. Solomon served as the Company’s Acting Principal Financial Officer from April 30, 2008, to September 8, 2008, which was during the period of time that the Company’s Chief Financial Officer position was vacant. Mr. Solomon joined the Company in 1996. He served as Financial Reporting Manager from February 1999 to September 2002, Assistant Vice President—Financial Reporting from September 2002 to May 2006 and Assistant Vice President—Assistant Controller from May 2006 to January 2007. Prior to joining the Company, Mr. Solomon was an auditor with Ernst & Young. Mr. Solomon has over 14 years of experience in the energy industry. 
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+Table of Contents 
+PART II 
+ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Market Information. SM Energy’s common stock is currently traded on the New York Stock Exchange under the ticker symbol “SM”. The following table presents the range of high and low intraday sales prices per share for the indicated quarterly periods in 2010 and 2009, as reported by the New York Stock Exchange: 
+Quarter Ended 
+High 
+Low 
+December 31, 2010 
+$ 
+59.82 
+$ 
+37.30 
+September 30, 2010 
+44.93 
+33.80 
+June 30, 2010 
+49.13 
+35.29 
+March 31, 2010 
+38.18 
+30.70 
+December 31, 2009 
+$ 
+38.05 
+$ 
+29.80 
+September 30, 2009 
+33.62 
+17.13 
+June 30, 2009 
+23.48 
+12.05 
+March 31, 2009 
+24.60 
+11.21 
+43 
+Table of Contents 
+PERFORMANCE GRAPH 
+The following performance graph compares the cumulative return on SM Energy’s common stock, not including dividend payments, for the period beginning December 31, 2005, and ending on December 31, 2010, with the cumulative total returns of the Dow Jones U.S. Exploration and Production Board Index, and the Standard & Poor’s 500 Stock Index. 
+COMPARE 5-YEAR CUMULATIVE TOTAL RETURN 
+The preceding information under the caption “Performance Graph” shall be deemed to be “furnished” but not “filed” with the Securities and Exchange Commission. 
+Holders. As of February 18, 2011, the number of record holders of SM Energy’s common stock was 101. Based on inquiry, management believes that the number of beneficial owners of our common stock is approximately 34,500. 
+Dividends. SM Energy has paid cash dividends to its stockholders every year since 1940. Annual dividends of $0.05 per share were paid in each of the years 1998 through 2004. Annual dividends of $0.10 per share were paid in 2005 through 2010. We expect that our practice of paying dividends on our common stock will continue, although the payment of future dividends will continue to depend on our earnings, cash flow, capital requirements, financial condition, and other factors. In addition, the payment of dividends is subject to covenants in our credit facility, including the requirement that we maintain the level of our current ratio of current assets to current liabilities and a limitation of our annual dividend rate to no more than $0.25 per share per year. We are also subject to certain covenants under our 6.625% Senior Notes that limit the payment of dividends on our common stock to $6.5 million in any given calendar year during the eight year term of the notes. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $6.3 million in 2010 and $6.2 million in 2009. 
+Restricted Shares. SM Energy has no restricted shares outstanding as of December 31, 2010, aside from Rule 144 restrictions on shares held by insiders, shares subject to transfer restrictions under the provisions of the Employee Stock Purchase Plan, and shares issued to members of the Board of Directors under the Equity Incentive Compensation Plan (“Equity Plan”). 
+44 
+Table of Contents 
+Securities Authorized for Issuance Under Equity Compensation Plans. SM Energy has the Equity Plan under which options and shares of SM Energy common stock are authorized for grant or issuance as compensation to eligible employees, consultants, and members of the Board of Directors. Our stockholders have approved this plan. See Note 7 — Compensation Plans in the Notes to Consolidated Financial Statements included in Part IV, Item 15 of this report for further information about the material terms of our equity compensation plans. The following table is a summary of the shares of common stock authorized for issuance under the equity compensation plans as of December 31, 2010: 
+(a) 
+(b) 
+(c) 
+Plan category 
+Number of securities to be issued upon exercise of outstanding options, warrants, and rights 
+Weighted-average exercise price of outstanding options, warrants, and rights 
+Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) 
+Equity compensation plans approved by security holders: 
+Equity Incentive Compensation Plan 
+Stock options and incentive stock options(1) 
+920,765 
+$ 
+13.11 
+Restricted stock(1) 
+333,359 
+— 
+Performance share awards(1)(3) 
+1,398,248 
+$ 
+39.48 
+Total for Equity Incentive Compensation Plan 
+2,652,372 
+$ 
+23.65 
+2,557,096 
+Employee Stock Purchase Plan(2) 
+— 
+— 
+1,415,327 
+Equity compensation plans not approved by security holders 
+— 
+— 
+— 
+Total for all plans 
+2,652,372 
+$ 
+23.65 
+3,972,423 
+(1) In May 2006 the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and members of the Board of Directors of SM Energy or any affiliate of SM Energy. The Equity Plan serves as the successor to the SM Energy Company Stock Option Plan, the SM Energy Company Incentive Stock Option Plan, the SM Energy Company Restricted Stock Plan, and the SM Energy Company Non-Employee Director Stock Compensation Plan (collectively referred to as the “Predecessor Plans”). All grants of equity are now made under the Equity Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under a Predecessor Plan immediately prior to the effective date of the Equity Plan continues to be governed solely by the terms and conditions of the instruments evidencing such grants or issuances. Our Board of Directors approved amendments to the Equity Plan in March 2008, 2009, and 2010, and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. Awards granted in 2010, 2009, and 2008 under the Equity Plan were 540,774, 1,016,931, and 932,767, respectively. 
+(2) Under the SM Energy Company Employee Stock Purchase Plan (the “ESPP”), eligible employees may purchase shares of our common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the six-month offering period, and shares issued under the ESPP through December 31, 2009, are restricted for a period of 18 months from the date issued. Effective January 1, 2010, shares issued under the ESPP will be restricted for a period six months from the date issued. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. Shares issued under the ESPP totaled 52,948, 86,308, and 45,228 in 2010, 2009, and 2008, respectively. 
+(3) The PSAs represent the right to receive, upon settlement of the PSAs after the completion of a three-year performance measurement period, a number of shares of our common stock that may be from zero to two times the number of PSAs granted, depending on the extent to which the underlying performance criteria have been achieved and the extent to which the PSAs have vested. The performance criteria for the PSAs are based on a combination of our annualized Total Shareholder Return (“TSR”) for the performance period and the relative measure of our TSR compared with the TSR of an index comprised of certain peer companies for the performance period. The current outstanding PSAs were granted on July 1, 2010, August 1, 2009, and August 1, 2008, and utilize a three-year performance measurement period, which began on July 1, 2010, 2009, and 2008, respectively. On July 1, 2010, the grant date, the market value per share of our common stock was $40.15. On July 1, 2009, the market value per share of our common stock 
+45 
+Table of Contents 
+was $21.15, and on the date of grant the market value per share of our common stock was $23.87. On July 1, 2008, the market value per share of our common stock was $62.51, and on the date of grant the market value per share of our common stock was $43.11. The PSAs do not have an exercise price associated with them, but rather the $39.48 price shown in the above table represents the weighted-average per share fair value as of December 31, 2010, which is presented in order to provide additional information regarding the potential dilutive effect of the PSAs as of December 31, 2010, in view of the share price level at the beginning of the performance period, which will be utilized to compute the TSR measurements for determination of the number of shares to be issued upon settlement of the PSAs after completion of the three-year performance measurement period. 
+46 
+Table of Contents 
+Purchases of Equity Securities By the Issuer and Affiliated Purchasers. The following table provides information about purchases by the Company and any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the indicated quarters and year ended December 31, 2010, of shares of the Company’s common stock, which is the sole class of equity securities registered by the Company pursuant to Section 12 of the Exchange Act. 
+ISSUER PURCHASES OF EQUITY SECURITIES 
+Total Number of Shares Purchased(1) 
+Average Price Paid per Share 
+Total Number of Shares Purchased as Part of Publicly Announced Program 
+Maximum Number of Shares that May Yet be Purchased Under the Program(2) 
+January 1, 2010—March 31, 2010 
+16,100 
+$ 
+32.75 
+— 
+3,072,184 
+April 1, 2010—June 30, 2010 
+427 
+$ 
+40.47 
+— 
+3,072,184 
+July 1, 2010—September 30, 2010 
+8,794 
+$ 
+41.42 
+— 
+3,072,184 
+October 1, 2010—October 31, 2010 
+91 
+$ 
+41.35 
+— 
+3,072,184 
+November 1, 2010—November 30, 2010 
+87 
+$ 
+42.42 
+— 
+3,072,184 
+December 1, 2010—December 31, 2010 
+21,779 
+$ 
+54.01 
+— 
+3,072,184 
+Total October 1, 2010—December 31, 2010 
+21,957 
+$ 
+53.92 
+— 
+3,072,184 
+Total 
+47,278 
+$ 
+44.26 
+— 
+3,072,184 
+(1) All shares purchased in 2010 were to offset tax withholding obligations that occur upon the delivery of outstanding shares underlying restricted stock units delivered under the terms of grants under the Equity Plan. 
+(2) In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of this filing, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of SM Energy’s credit facility, provisions of our 6.625% Senior Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow, or borrowings under our credit facility. The stock repurchase program may be suspended or discontinued at any time. 
+The payment of dividends is subject to covenants in our credit facility, including the requirement that we maintain certain levels of stockholders’ equity and the limitation that does not allow our annual dividend rate may not exceed $0.25 per share. The payment of dividends is also subject to covenants under our 6.625% Senior Notes, including covenants limiting the payment of dividends on our common stock to $6.5 million in the aggregate in any given calendar year during the eight year term of the notes. 
+47 
+Table of Contents 
+ITEM 6. SELECTED FINANCIAL DATA 
+The following table sets forth supplemental selected financial and operating data for SM Energy as of the dates and periods indicated. The financial data for each of the five years presented were derived from the consolidated financial statements of SM Energy. The following data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with SM Energy’s consolidated financial statements included in this report. 
+Years Ended December 31, 
+2010 
+2009 
+2008 
+2007 
+2006 
+(in thousands, except per share data) 
+Total operating revenues 
+$ 
+1,092,834 
+$ 
+832,201 
+$ 
+1,301,301 
+$ 
+990,094 
+$ 
+787,701 
+Net income (loss) 
+$ 
+196,837 
+$ 
+(99,370 
+) 
+$ 
+87,348 
+$ 
+187,098 
+$ 
+190,015 
+Net income (loss) per share: 
+Basic 
+$ 
+3.13 
+$ 
+(1.59 
+) 
+$ 
+1.40 
+$ 
+3.02 
+$ 
+3.38 
+Diluted 
+$ 
+3.04 
+$ 
+(1.59 
+) 
+$ 
+1.38 
+$ 
+2.90 
+$ 
+2.94 
+Total assets at year end 
+$ 
+2,744,321 
+$ 
+2,360,936 
+$ 
+2,697,247 
+$ 
+2,572,942 
+$ 
+1,899,097 
+Long-term debt: 
+Line of credit 
+$ 
+48,000 
+$ 
+188,000 
+$ 
+300,000 
+$ 
+285,000 
+$ 
+334,000 
+Senior convertible notes, net of debt discount 
+$ 
+275,673 
+$ 
+266,902 
+$ 
+258,713 
+$ 
+251,070 
+$ 
+99,980 
+Cash dividends declared and paid per common share 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+48 
+Table of Contents 
+Supplemental Selected Financial and Operations Data 
+Years Ended December 31, 
+2010 
+2009 
+2008 
+2007 
+2006 
+(in thousands, except sales prices, volumes, and per MCFE amounts) 
+Balance Sheet Data 
+Total working capital (deficit) 
+$ 
+(227,408 
+) 
+$ 
+(87,625 
+) 
+$ 
+15,193 
+$ 
+(92,604 
+) 
+$ 
+22,870 
+Total stockholders’ equity 
+$ 
+1,218,526 
+$ 
+973,570 
+$ 
+1,162,509 
+$ 
+902,574 
+$ 
+743,374 
+Weighted-average shares outstanding 
+Basic 
+62,969 
+62,457 
+62,243 
+61,852 
+56,291 
+Diluted 
+64,689 
+62,457 
+63,133 
+64,850 
+65,962 
+Reserves 
+Oil (MMBbl) 
+57.4 
+53.8 
+51.4 
+78.8 
+74.2 
+Gas (Bcf) 
+640.0 
+449.5 
+557.4 
+613.5 
+482.5 
+BCFE 
+984.5 
+772.2 
+865.5 
+1,086.5 
+927.6 
+Production and Operational: 
+Oil and gas production revenues, including hedging 
+$ 
+859,753 
+$ 
+756,601 
+$ 
+1,158,304 
+$ 
+936,577 
+$ 
+758,913 
+Oil and gas production expenses 
+$ 
+195,075 
+$ 
+206,800 
+$ 
+271,355 
+$ 
+218,208 
+$ 
+176,590 
+DD&A 
+$ 
+336,141 
+$ 
+304,201 
+$ 
+314,330 
+$ 
+227,596 
+$ 
+154,522 
+General and administrative 
+$ 
+106,663 
+$ 
+76,036 
+$ 
+79,503 
+$ 
+60,149 
+$ 
+38,873 
+Production Volumes: 
+Oil (MMBbl) 
+6.4 
+6.3 
+6.6 
+6.9 
+6.1 
+Gas (Bcf) 
+71.9 
+71.1 
+74.9 
+66.1 
+56.4 
+BCFE 
+110.0 
+109.1 
+114.6 
+107.5 
+92.8 
+Realized price—pre hedging: 
+Per Bbl 
+$ 
+72.65 
+$ 
+54.40 
+$ 
+92.99 
+$ 
+67.56 
+$ 
+59.33 
+Per Mcf 
+$ 
+5.21 
+$ 
+3.82 
+$ 
+8.60 
+$ 
+6.74 
+$ 
+6.58 
+Realized price—net of hedging: 
+Per Bbl 
+$ 
+66.85 
+$ 
+56.74 
+$ 
+75.59 
+$ 
+62.60 
+$ 
+56.60 
+Per Mcf 
+$ 
+6.05 
+$ 
+5.59 
+$ 
+8.79 
+$ 
+7.63 
+$ 
+7.37 
+Expense per MCFE: 
+LOE 
+$ 
+1.10 
+$ 
+1.33 
+$ 
+1.46 
+$ 
+1.31 
+$ 
+1.25 
+Transportation 
+$ 
+0.19 
+$ 
+0.19 
+$ 
+0.19 
+$ 
+0.14 
+$ 
+0.12 
+Production taxes 
+$ 
+0.48 
+$ 
+0.37 
+$ 
+0.71 
+$ 
+0.58 
+$ 
+0.54 
+DD&A 
+$ 
+3.06 
+$ 
+2.79 
+$ 
+2.74 
+$ 
+2.12 
+$ 
+1.67 
+General and administrative 
+$ 
+0.97 
+$ 
+0.70 
+$ 
+0.69 
+$ 
+0.56 
+$ 
+0.42 
+Statement of Cash Flow Data: 
+Provided by operations 
+$ 
+497,097 
+$ 
+436,106 
+$ 
+679,190 
+$ 
+632,054 
+$ 
+467,700 
+Used in investing 
+$ 
+(361,573 
+) 
+$ 
+(304,092 
+) 
+$ 
+(673,754 
+) 
+$ 
+(805,134 
+) 
+$ 
+(724,719 
+) 
+Provided by (used in) financing 
+$ 
+(141,096 
+) 
+$ 
+(127,496 
+) 
+$ 
+(42,815 
+) 
+$ 
+215,126 
+$ 
+243,558 
+49 
+Table of Contents 
+ITEM 7 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+This discussion includes forward-looking statements. Please refer to “Cautionary Information about Forward-Looking Statements” in Part I, Items 1 and 2 of this report for important information about these types of statements. 
+Overview of the Company 
+General Overview 
+We are an independent energy company engaged in the acquisition, exploration, exploitation, development and production of natural gas and crude oil in North America, with a focus on oil and liquids-rich resource plays. Our assets include leading positions in the Eagle Ford shale and Bakken/Three Forks resource plays, as well as meaningful positions in the Granite Wash, Haynesville shale, and Woodford shale resource plays. We have developed our portfolio of properties with reserves, development drilling opportunities, and unconventional resource prospects onshore in North America, typically through early entrance into existing and emerging resource plays. We believe this approach allows for stable and predictable production and reserves growth. Furthermore, by entering these plays earlier, we believe that we can reduce costs and capture larger resource potential. 
+We generally generate almost all our revenues and cash flows from the sale of produced natural gas, NGLs and crude oil. In 2010 we have generated significant gains and cash proceeds from the sale of non-strategic oil and gas properties. Please refer to discussion below under 2010 Highlights . 
+Our business strategy is to increase net asset value through attractive oil and gas investment activity while maintaining a conservative capital structure and optimizing capital expenditures. We focus our efforts on the exploration for and development of onshore, lower-risk resource plays in North America. We believe our inventory of drilling locations is ideally suited for growing reserves and production due to predictable geology and lower-risk profile. Furthermore, our assets produce significant volumes of oil and NGLs that limit our exposure to the current lower natural gas price environment. Our strategy is based on the following points: 
+· leveraging our core competencies in replicating resource play success in the drilling, completion, and development of oil and natural gas reserves; 
+· focusing on resource plays with low-risk geology and high liquids content; 
+· exploiting our legacy assets and optimizing our asset base; 
+· selectively acquiring leasehold positions in new and emerging resource plays; and 
+· maintaining a strong balance sheet while funding the growth of our business. 
+In 2010 we had the following financial and operational results: 
+· At year end 2010 we had estimated proved reserves of 984.5 BCFE, of which 65 percent were natural gas and 70 percent were characterized as proved developed. We added 384.2 BCFE from our drilling program, the majority of which related to our activity in our Eagle Ford shale in South Texas and the Woodford shale in eastern Oklahoma. We sold 86.8 BCFE of proved reserves during the year related to non-strategic assets located primarily in our Rocky Mountain and Permian regions. We added 42.6 BCFE of estimated proved reserves as a result of price revisions in 2010. The prices used in the calculation of proved reserve estimates as of December 31, 2010, were $79.43 per Bbl and $4.38 per MMBTU for oil and natural gas, respectively. These prices were 30 percent and 13 percent higher, respectively, than the prices used at year end 2009. Performance revisions in 2010 resulted in a net 11.2 BCFE decrease in our estimate of proved reserves. While we recognized positive performance 
+50 
+Table of Contents 
+revisions in every region on proved developed properties, we had approximately 19.3 BCFE of negative performance revisions related to estimated proved undeveloped reserves in primarily dry gas regions, given the impact of lower gas prices and higher well costs on the economics of these projects. Lastly, we reduced estimated proved reserves by 6.7 BCFE by removing proved undeveloped reserves related to assets that reached aging limitations, as mandated by the SEC. 
+· The PV-10 value of our proved reserves was $2.3 billion as of December 31, 2010, compared with $1.3 billion as of December 31, 2009. The after tax value, represented by the standardized measure calculation, was $1.7 billion as of December 31, 2010, compared with $1.0 billion as of December 31, 2009. The standardized measure calculation is presented in Note 15 — Disclosures about Oil and Gas Producing Activities of Part IV, Item 15 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown under Reserves in Part I, Items 1 and 2 of this report. 
+· We recorded net income of $196.8 million and diluted earnings per share of $3.04 for the year ended December 31, 2010. This compares with a net loss of $99.4 million, or $1.59 loss per diluted share, for the year ended December 31, 2009. 
+· Our average daily production for 2010 was 196.9 MMcf of gas and 17.4 MBbl of oil, for an average equivalent production rate of 301.4 MMCFE per day, compared with 298.8 MMCFE per day for 2009. 
+· Cash flow from operating activities of $497.1 million, was an increase of 14 percent from 2009. 
+· Costs incurred for oil and gas producing activities for the year ended December 31, 2010, were $877.4 million, compared with $419.0 million for the same period in 2009. 
+Our operations are generally funded first through cash flows from operating activities and then through borrowings under our credit facility. The divestiture of assets is also a potential source of liquidity. Acquisitions may be funded with proceeds from sales of public or private debt and equity, borrowings under our credit facility, property sales, and cash flow from operating activities. In 2010 we invested $823.5 million for development and exploration, including facility costs, and $53.9 million for leasehold and acquisitions. Total costs incurred during 2010 increased $458.4 million, or 109 percent, to $877.4 million compared to $419.0 million in 2009. This increase in capital and exploration activities reflects a stable and improving economic environment, higher cash flows available for investment provided by operating activities and divestiture proceeds, and our increased level of drilling activity, particularly in the Eagle Ford shale. 
+51 
+Table of Contents 
+Reserve Replacement, Finding Costs, and Growth 
+Like all oil and gas exploration and production companies, we face the challenge of growing oil and natural gas reserves. An exploration and production company depletes part of its asset base with each unit of oil or gas it produces. Our future growth will depend on our ability to organically and economically add reserves in excess of production. 
+The following table provides various reserve replacement and finding cost metrics for the year ended December 31, 2010: 
+Reserve Replacement 
+Percentage 
+Finding Cost per MCFE 
+Excluding 
+sales 
+Including 
+sales 
+Excluding 
+sales 
+Including 
+sales 
+Drilling, excluding revisions 
+349 
+% 
+270 
+% 
+$ 
+2.14 
+$ 
+2.77 
+Drilling, including revisions 
+372 
+% 
+293 
+% 
+$ 
+2.01 
+$ 
+2.56 
+Drilling and acquisitions, excluding revisions 
+349 
+% 
+270 
+% 
+$ 
+1.94 
+$ 
+2.50 
+Drilling and acquisitions, including revisions 
+372 
+% 
+293 
+% 
+$ 
+1.82 
+$ 
+2.31 
+Acquisitions 
+N/M 
+* 
+N/M 
+* 
+N/M 
+* 
+N/M 
+* 
+All-in 
+372 
+% 
+293 
+% 
+$ 
+2.14 
+$ 
+2.72 
+* N/M—Percentage is not meaningful 
+The following table provides three-year average reserve replacement and finding cost metrics for the years ended December 31, 2010, 2009, and 2008: 
+Reserve Replacement 
+Percentage 
+Finding Cost per MCFE 
+Excluding 
+sales 
+Including 
+sales 
+Excluding 
+sales 
+Including 
+sales 
+Drilling, excluding revisions 
+199 
+% 
+141 
+% 
+$ 
+2.83 
+$ 
+3.99 
+Drilling, including revisions 
+118 
+% 
+61 
+% 
+$ 
+4.76 
+$ 
+9.29 
+Drilling and acquisitions, excluding revisions 
+208 
+% 
+150 
+% 
+$ 
+2.65 
+$ 
+3.67 
+Drilling and acquisitions, including revisions 
+127 
+% 
+69 
+% 
+$ 
+4.33 
+$ 
+7.93 
+Acquisitions 
+9 
+% 
+N/M 
+* 
+$ 
+1.78 
+N/M 
+* 
+All-in 
+127 
+% 
+69 
+% 
+$ 
+5.08 
+$ 
+9.30 
+* N/M—Percentage is not meaningful 
+Our strategic challenge is to grow net asset value per share, which we believe drives appreciation in our stock price over the long term. To accomplish this, we believe it is important to organically and economically replace annual production with new reserves. We believe annual reserve replacement percentage and finding cost amounts are important analytical measures that are widely used by investors and industry peers in evaluating and comparing the performance of oil and gas companies. While single-year measurements have some meaning in terms of a trend, we believe that aberrations, causing both relatively good and bad results, will occur over short intervals of time. The information used to calculate the above reserve replacement and finding cost metrics is included in Note 14 — Oil and Gas Activities and Note 15 — Disclosures about Oil and Gas Producing Activities of the Notes to Consolidated Financial Statements included in Part IV, Item 15 of this report. For additional 
+52 
+Table of Contents 
+information about these metrics, see the reserve replacement and finding cost terms in the Glossary at the end of Part I, Items 1 and 2 of this report. 
+Financial Standing and Liquidity 
+In the third quarter of 2010, the borrowing base under our credit facility was redetermined and was increased from $900 million to $1.1 billion. The commitment amount of the bank group remained unchanged at $678 million. At the end of 2010, we had $48.0 million outstanding under our credit facility. Subsequent to year end, we issued $350.0 million in aggregate principal amount of 6.625% Senior Notes. Pursuant to the terms of our credit facility, our borrowing base was reduced by 25 percent of the $350.0 million resulting in a new borrowing base of $1.0 billion, effective as of February 2011. The next scheduled redetermination of our borrowing base is scheduled for April, 2011. We used a portion of the proceeds from our 6.625% Senior Notes offering to repay our outstanding balance under our credit facility. As of February 18, 2011, we had no outstanding borrowings under our credit facility. We have no debt maturities until 2012, when our credit facility matures and all or a portion of our outstanding 3.50% Senior Convertible Notes can be first put to us on April 1, 2012. If the 3.50% Senior Convertible Notes are put to us on April 1, 2012, we have the option of paying the purchase price in cash shares of our common stock, or a combination thereof. On or after April 6, 2012, we have the option of redeeming all or a portion of the outstanding 3.50% Senior Convertible Notes for cash. The 3.50% Senior Convertible Notes are convertible into shares of our common stock under certain circumstances, including if the 3.50% Senior Convertible Notes are called for redemption, and we may elect to settle conversion obligations in cash, shares of our common stock, or a combination thereof. Given the condition of our business, our debt position, credit standing, and relationships with the participants in our bank group, we believe we will be able to extend our existing facility or obtain a replacement credit facility before our current credit facility matures in 2012. 
+We anticipate that cash flows from operations, proceeds from our 6.625% Senior Notes, and proceeds from additional asset divestitures will fund the majority of our 2011 capital program. We plan to use our credit facility to fund the remaining portion of our capital program. Given the magnitude of the commitments associated with our existing inventory of potential drilling projects, our funding requirements could increase significantly in 2011 and beyond. As a result, we may consider accessing the capital markets, selling assets, entering into joint ventures, and other financing alternatives as we determine the best options to fund our capital programs. We continue to believe we currently have adequate liquidity available, as discussed under the caption Overview of Liquidity and Capital Resources . 
+Oil, Gas, and NGL Prices 
+Our financial condition and the results of our operations are significantly affected by the prices we receive for oil, natural gas, and NGL production, which can fluctuate dramatically. Please refer to Comparison of Financial Results and Trends between 2010 and 2009 for the realized price tables for the respective periods. We sell a majority of our natural gas under contracts that use first of the month index pricing, which means that gas produced in a given month is sold at the first of the month price regardless of the spot price on the day the gas is produced. We account for the majority of our natural gas sales as they occur at the wellhead and accordingly do not present a separate production stream for the NGLs processed from our natural gas production. We receive value for the NGL content in our natural gas stream, which can result in us realizing a higher per unit price for our reported gas production. Volumes associated with the sale of processed NGLs are currently not significant and have not been included in our production volumes. We anticipate that dollars and volumes associated with our NGL production will become a growing part of our production stream and reserve base. Our crude oil is sold using contracts that pay us either the average of the NYMEX WTI daily settlement price or the average of alternative posted prices for the periods in which the crude oil is produced, adjusted for quality, transportation, and location differentials. 
+53 
+Table of Contents 
+The following table is a summary of commodity price data for the years ended December 31, 2010, 2009, and 2008. 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+Crude Oil (per Bbl): 
+Average NYMEX WTI spot price 
+$ 
+79.51 
+$ 
+61.99 
+$ 
+99.92 
+Realized price, before the effects of hedging 
+$ 
+72.65 
+$ 
+54.40 
+$ 
+92.99 
+Net realized price, including the effects of hedging 
+$ 
+66.85 
+$ 
+56.74 
+$ 
+75.59 
+Natural Gas (per Mcf): 
+Average NYMEX Henry Hub spot price 
+$ 
+4.37 
+$ 
+3.94 
+$ 
+8.89 
+Realized price, before the effects of hedging 
+$ 
+5.21 
+$ 
+3.82 
+$ 
+8.60 
+Net realized price, including the effects of hedging 
+$ 
+6.05 
+$ 
+5.59 
+$ 
+8.79 
+We expect future prices for crude oil, NGLs, and natural gas to be volatile. In addition to supply and demand fundamentals, the relative strength of the U.S. Dollar will likely continue to impact crude oil prices. Historically, NGL prices have trended and correlated with the price for crude oil. The supply of NGLs is expected to grow in the near term as a result of a number of industry participants targeting projects that produce these products, which could negatively impact future pricing. Natural gas prices are facing downward pressure as a result of excess supply resulting from high levels of drilling activity across the country, as well as tepid demand due to the economic recession in the United States. The 12-month strip prices for NYMEX WTI crude and NYMEX Henry Hub gas as of December 31, 2010, were $93.70 per Bbl and $4.64 per MMBTU, respectively; comparable prices as of February 18, 2011, were $94.86 per Bbl and $4.23 per MMBTU, respectively. 
+While changes in quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the price we receive for oil and natural gas is affected by quality, energy content, location, and transportation differentials for these products. We refer to this hedge impacted price as our realized price, which excludes the effects of hedging. Our realized price is further impacted by the results of our hedging arrangements that are settled in the respective periods. We refer to this price as our net realized price. For the year ended December 31, 2010, our net natural gas price realization was positively impacted by $60.3 million of realized hedge settlements, and our net oil price realization was negatively impacted by $36.8 million of realized hedge settlements. 
+2010 Highlights 
+Operational activities. We had between ten and twelve operated drilling rigs running company-wide for most of 2010. The thrust of our operated drilling activity this year has been focused on oil and NGL-rich gas programs and selected natural gas projects of potential strategic importance to us. Our operating partners have also increased their levels of activity in oil and NGL-rich gas plays. 
+In our Eagle Ford shale program in South Texas, we operated a two rig drilling program on our acreage throughout 2010. Our focus was on drilling in areas with higher BTU gas content and higher condensate yields. We continued to test different ways to complete these wells with the objective of optimizing future development potential. We have been encouraged with the results in our operated portion of the play and have been working to increase the pace of development on our acreage. Securing infrastructure to gather, transport, process, and market production from our Eagle Ford shale program has been an issue we have worked to address over the last year, which has yielded benefits to us in recent months. However given increased activity across the Eagle Ford shale play as a whole, we expect that the industry, including us, will continue to experience capacity limitations as the infrastructure required to serve this play is developed and expanded. During 2010, we entered into arrangements to secure the takeaway capacity and to secure drilling and completion services required to accelerate our operated program. We continue to explore other arrangements to facilitate the growth of this program. Please refer to 
+54 
+Table of Contents 
+Note 6—Commitments and Contingencies under Part IV, Item 15 of this report and Delivery Commitments under Part I, Item 1 and 2 of this report for additional discussion concerning these agreements. On our outside-operated Eagle Ford acreage, the operator increased activity on our shared acreage throughout 2010. At year end, seven drilling rigs were running in this program. This outside-operated acreage had limited infrastructure to support the development program, and accordingly we participated in the construction projects with our partner during 2010. The increase in partner-operated rigs and the infrastructure build-out resulted in higher capital expenditures in this program than we initially budgeted for at the beginning of the year. 
+We operated an average of two drilling rigs in the Williston Basin throughout 2010, both of which were focused on Bakken/Three Forks drilling. Our drilling results in prospects west of the majority of industry activity met or exceeded our expectations in 2010. Elsewhere in the Rocky Mountain region, we tested the Niobrara formation in southeastern Wyoming during the year with the drilling of two test wells. Interest in the Niobrara formation increased significantly during 2010 based on positive field reports coming out of the play. Our early results from our exploratory program have been encouraging. 
+In our Mid-Continent region, we operated an average of two drilling rigs in our Granite Wash program in western Oklahoma. Our acreage position is held by production, and we believe the potential from this emerging program could be significant. We also operated a rig in the Woodford shale in the Arkoma Basin during the second half of 2010, which focused primarily on drilling sections of our acreage with richer natural gas. 
+Our Permian region operated a two-rig program throughout 2010, focusing on Wolfberry tight oil targets. In our operated Haynesville shale program, we entered into a sharing arrangement involving our East Texas acreage position in early 2010 as discussed further in Note 12 - Carry and Earning Agreement under Part IV, Item 15. The arrangement allowed us to de-risk our Haynesville shale acreage in East Texas with a considerably reduced capital investment on our part. We had two drilling rigs operating in the play for most of the second half of 2010. 
+Marketing of properties. In the third quarter of 2010, we began marketing two divestiture packages that included non-strategic properties in our Rocky Mountain, Mid-Continent, and Permian regions. We closed the Permian component of this package at the end of 2010. Subsequent to year end we divested the Rocky Mountain component of the package. Both divestitures are discussed in further detail below. The non-strategic properties being marketed also include all of our Marcellus shale assets in North Central Pennsylvania. We are continuing to market the Mid-Continent component of this package and our Marcellus shale assets in Pennsylvania. Finally, we have announced that we are pursuing a transaction that could result in a partial sale or farm-down of our total Eagle Ford shale position. The marketing process for our Eagle Ford shale assets began subsequent to year end. Please refer to Outlook for 2011 and Note 3 — Divestitures and Assets Held for Sale, in Part IV, Item 15 of this report for additional information. 
+Legacy Divestiture. On February 17, 2010, we sold certain non-strategic properties in Wyoming to Legacy Reserves Operating LP. Total cash received, before marketing costs and Net Profits Plan payments, was $125.3 million. The final gain on divestiture activity related to the divestiture was approximately $66.7 million. 
+Sequel Divestiture. On March 12, 2010, we sold certain non-strategic properties located in North Dakota to Sequel Energy Partners, LP, Bakken Energy Partners, LLC, and Three Forks Energy Partners, LLC. Total cash received, before marketing costs and Net Profits Plan payments, was $129.1 million. The final gain on divestiture activity related to the divestiture was approximately $53.1 million. 
+Permian Divestiture. On December 29, 2010, we sold certain non-strategic properties located in our Permian region. Total cash received, before marketing costs and Net Profits Plan payments, was $56.3 million. The final sale price is subject to post-closing adjustments and is expected to be finalized during the first half of 2011. The estimated gain on divestiture activity related to this divestiture is approximately $19.9 million and may be impacted by the forthcoming post-closing adjustments mentioned above. 
+Rockies Divestiture. Subsequent to year end, we sold certain non-strategic oil and gas properties located in our Rocky Mountain region. Total cash received, before marketing costs and Net Profits Plan payments, was 
+55 
+Table of Contents 
+$44.4 million. The final sales price is subject to post-closing adjustments and is expected to be finalized during the first half of 2011. 
+Financial and production results. We recorded net income for the year ended December 31, 2010, of $196.8 million or $3.04 per diluted share compared to 2009 results of a net loss of $99.4 million or $(1.59) per diluted share. 
+The table below details the regional breakdown of our 2010 production: 
+ArkLaTex 
+Mid-Continent 
+South Texas & Gulf Coast 
+Permian 
+Rocky 
+Mountain 
+Total(1) 
+Production: 
+Oil (MMBbl) 
+0.1 
+0.2 
+1.0 
+1.7 
+3.3 
+6.4 
+Gas (Bcf) 
+13.9 
+32.1 
+16.4 
+4.3 
+5.2 
+71.9 
+Equivalent (BCFE) 
+14.4 
+33.4 
+22.7 
+14.7 
+24.9 
+110.0 
+Avg. Daily Equivalents (MMCFE/d) 
+39.3 
+91.5 
+62.1 
+40.2 
+68.3 
+301.4 
+Relative percentage 
+13 
+% 
+30 
+% 
+21 
+% 
+13 
+% 
+23 
+% 
+100 
+% 
+(1) Totals may not add due to rounding 
+In 2010 our production growth was led by our Eagle Ford shale program. Both our operated and non-operated programs targeting the Eagle Ford contributed more production than originally budgeted. Please refer to Comparison of Financial Results and Trends between 2010 and 2009 below for additional discussion on production. 
+Hedging Activities. On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was enacted into law. This financial reform legislation includes provisions that require over-the-counter derivative transactions to be executed through an exchange or centrally cleared. The Dodd-Frank Act requires the CFTC and SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. On October 1, 2010, the CFTC introduced its first series of proposed rules coming out of the Dodd-Frank Act. The effect of the proposed rules and any additional regulations on our business is currently uncertain. Of particular concern, the Dodd-Frank Act does not explicitly exempt end users (such as us) from the requirements to post margin in connection with hedging activities. While several senators have indicated that it was not the intent of the Dodd-Frank Act to require margin from end users, the exemption is not explicit in the Dodd-Frank Act. Final rules on major provisions in the legislation, such as new margin requirements, will be established through rulemakings and will not take effect until 12 months after the date of enactment. Although we cannot predict the ultimate outcome of these rulemakings, new regulations in this area may result in increased costs and cash collateral requirements for the types of derivative instruments we use to hedge and otherwise manage our financial risks related to volatility in oil, gas, and NGL commodity prices. 
+Hedging is an important part of our financial risk management program. We have a financial risk management policy that governs our practices relating to hedging. The amount of production we hedge is driven by the amount of debt on our consolidated balance sheet and the level of capital commitments and long-term obligations we have in place. In the case of a significant acquisition of producing properties, we will consider hedging a portion of the acquired production in order to protect the economics assumed in the acquisition. With the hedges we have in place, we believe we have established a base cash flow stream for our future operations, and our use of collars for a portion of the hedges allows us to participate in upward movements in oil and gas prices while also setting a price floor for a portion of our production. Please see Note 10 — Derivative Financial 
+56 
+Table of Contents 
+Instruments of Part IV, Item 15 of this report for additional information regarding our oil and gas hedges, and see the caption, Summary of Oil and Gas Production Hedges in Place, later in this section. 
+Prior to January 1, 2011, we attempted to qualify our oil and gas derivative instruments as cash flow hedges for accounting purposes, whereby changes in the value of our hedge positions were primarily reflected in our consolidated balance sheets. A portion of the changes in the value of our hedge positions were recognized in our consolidated statements of operations when hedges were partially ineffective at offsetting the fluctuations in cash flow due to changes in the spot price for oil, natural gas, and NGLs. Effective January 1, 2011, we have elected to de-designate all of our commodity hedges that had previously been designated as cash flow hedges as of December 31, 2010. We have also elected to discontinue hedge accounting prospectively. Hedging will continue to be an important part of our financial risk management program. The election to de-designate our commodity hedges does not impact the economic substance of these transactions and changes only how these transactions are accounted for in our consolidated financial statements. 
+We recognized $8.9 million in non-cash unrealized derivative loss for the year ended December 31, 2010. Our overall hedge liability decreased year over year as a result of the continued deterioration in natural gas prices, which caused an increase in our natural gas hedge assets at December 31, 2010. Our net hedge liability was $52.3 million as of December 31, 2010, compared to $80.9 million at the end of 2009. Corresponding changes are reflected in accumulated other comprehensive income on the consolidated balance sheets and unrealized derivative (gain) loss on the consolidated statements of operations. 
+Net Profits Plan. For the year ended December 31, 2010, the change in the value of this liability resulted in a non-cash benefit of $34.4 million compared with a $7.1 million benefit for the same period in 2009. Current year payments made or accrued as part of allocating the proceeds received from divestitures in 2010 have decreased the estimated liability for the future amounts to be paid to plan participants. This liability is a significant management estimate. Adjustments to the liability are subject to estimation and may change dramatically from period to period based on assumptions used for production rates, reserve quantities, commodity pricing, discount rates, tax rates, and production costs. 
+Payments made or accrued under the Net Profits Plan have been expensed as compensation costs in the amounts of $22.4 million, $19.9 million, and $36.3 million for the years ended December 31, 2010, 2009, and 2008, respectively. Additionally, the divestiture of oil and gas properties described above included a number of properties included in the net profits pools and resulted in payments made or accrued under the Net Profits Plan of $26.1 million for the year ended December 31, 2010. For the years ended December 31, 2009, and 2008, we made or accrued cash payments under the Net Profits Plan of $724,000 and $15.1 million, respectively, as a result of divestitures. These cash payments are accounted for as a reduction in the gain on divestiture activity in the accompanying consolidated statements of operations. 
+The recurring cash payments we make are dependent on actual production, realized prices, and operating and capital costs associated with the properties in each individual pool. Actual cash payments will be inherently different from the estimated liability amounts. More detailed discussion is included in the analysis in the Comparison of Financial Results and Trends section below and in Note 11 — Fair Value Measurements in Part IV, Item 15. An increasing percentage of the costs associated with the payments from the Net Profits Plan are being categorized as general and administrative expense as compared to exploration expense. This is a function of the normal departure of employees who previously contributed to our exploration efforts. In December 2007, our Board of Directors approved an incentive compensation plan restructuring, whereby the Net Profits Plan was replaced with a long-term incentive program utilizing equity awards. As a result, the 2007 Net Profits Plan pool was the last pool established. 
+The calculation of the estimated liability for the Net Profits Plan is highly sensitive to our price estimates and discount rate assumptions. For example, if we changed the commodity prices in our calculation by five percent, the liability recorded on the balance sheet at December 31, 2010, would differ by approximately $12 million. A one percentage point decrease in the discount rate would result in an increase to the liability of approximately $7 million, while a one percentage point increase in the discount rate would result in a decrease to the liability of approximately $6 million. We frequently re-evaluate the assumptions used in our calculations and 
+57 
+Table of Contents 
+consider the possible impacts stemming from the current market environment including current and future oil and gas prices, discount rates, and overall market conditions for oil and gas properties. 
+Outlook for 2011 
+We enter the year with a capital expenditure budget of approximately $1.0 billion, of which approximately $830.0 million will be spent drilling activity. Approximately 80 percent of our drilling capital budget will be deployed in our Eagle Ford shale and Bakken/Three Forks programs during the year. 
+We began 2011 operating two rigs on our Eagle Ford acreage with plans to increase our operated rig count to five or six drilling rigs by year end. We have extended the contracts for two rigs currently working for us and have also contracted for two additional rigs, which are scheduled to be available in mid-2011. We have also been working with completion service providers to ensure we have access to certain services throughout the year. We have made commitments that secure a portion of our required services and we continue to work with providers to support our anticipated level of activity. During 2010 we entered into separate arrangements that increase our gas takeaway capacity in 2011 and beyond in this play. Our current export capacity is approximately 100 MMcf per day, which we anticipate will increase to 150 MMcf per day around mid-2011. During the same time frame, capacity under a separate agreement is scheduled to be available which will ultimately provide an additional 160 MMcf per day in the next several years. 
+In our non-operated Eagle Ford shale program, the operator is currently operating seven drilling rigs and our expectation is that such number will increase to ten rigs by the end of the first quarter of 2011. The operator has indicated that it is exploring various transactions which could allow it to increase activity even further. We have initiated a marketing effort to sell down or joint venture a portion of our Eagle Ford shale position. Although details of the contemplated transaction are still being determined, we estimate that we could farm down or joint venture approximately 20 to 30 percent of our total acreage position, resulting in a net investment by us in the Eagle Ford in 2011 of approximately $500 million. 
+We plan to deploy approximately $170 million of our capital budget in our Bakken/Three Forks formations in the Williston Basin in 2011. We currently are operating two drilling rigs in this program and plan to add a third rig by mid-year. We would consider increasing activity in this program beyond three rigs should additional capital become available for investment during the year and other circumstances warrant such action. 
+We also have activity planned in our Granite Wash, Permian Basin, and Haynesville shale programs in 2011. Approximately $60 million of our capital budget in 2011 is budgeted for our Granite Wash program, where we anticipate operating a two rig program throughout the year. We plan to spend approximately $40 million of our capital budget in our Permian region in 2011, where approximately 50 percent of our activity will be focused on our vertical Wolfberry tight oil program. In the Haynesville shale, our capital budget is approximately $35 million, related primarily to non-operated activity. Five operated wells in our Haynesville shale program are currently anticipated for the year, of which the majority of our costs will be carried under the previously announced carry and earning agreement covering a portion of our operated Haynesville shale acreage in East Texas. We are currently exploring a number of 2011 and 2012 drilling options for our operated Haynesville shale acreage position in East Texas that would allow us to drill enough wells in 2011 and 2012 to hold substantially all of our existing acreage, while minimizing the amount of capital deployed by us. Please refer to additional discussion under Note 12 — Carry and Earning Agreement under Part IV, Item 15 of this report. 
+Please refer to Overview of Liquidity and Capital Resources for additional discussion regarding how we anticipate funding our 2011 capital program. 
+58 
+Table of Contents 
+Financial Results of Operations and Additional Comparative Data 
+The table below provides information regarding selected production and financial information for the quarter ended December 31, 2010, and the immediately preceding three quarters. Additional details of per MCFE costs are contained later in this section. 
+For the Three Months Ended 
+December 31, 
+September 30, 
+June 30, 
+March 31, 
+2010 
+2010 
+2010 
+2010 
+(in millions, except production sales data) 
+Production (BCFE) 
+31.6 
+27.5 
+25.2 
+25.7 
+Oil and gas production revenue, excluding the effects of hedging 
+$ 
+250.1 
+$ 
+197.4 
+$ 
+175.9 
+$ 
+212.9 
+Realized oil and gas hedge gain 
+$ 
+2.8 
+$ 
+8.8 
+$ 
+9.3 
+$ 
+2.6 
+Gain on divestiture activity 
+$ 
+23.1 
+$ 
+4.2 
+$ 
+7.0 
+$ 
+121.0 
+Lease operating expense 
+$ 
+33.5 
+$ 
+29.0 
+$ 
+29.0 
+$ 
+30.0 
+Transportation costs 
+$ 
+7.1 
+$ 
+4.9 
+$ 
+5.1 
+$ 
+4.1 
+Production taxes 
+$ 
+16.4 
+$ 
+10.7 
+$ 
+11.1 
+$ 
+14.2 
+DD&A 
+$ 
+94.7 
+$ 
+83.8 
+$ 
+79.8 
+$ 
+77.8 
+Exploration 
+$ 
+21.1 
+$ 
+14.4 
+$ 
+14.5 
+$ 
+13.9 
+General and administrative 
+$ 
+31.6 
+$ 
+26.2 
+$ 
+25.4 
+$ 
+23.5 
+Change in Net Profits Plan liability 
+$ 
+(4.6 
+) 
+$ 
+4.1 
+$ 
+(6.6 
+) 
+$ 
+(27.3 
+) 
+Unrealized derivative (gain) loss 
+$ 
+13.0 
+$ 
+5.7 
+$ 
+(2.1 
+) 
+$ 
+(7.7 
+) 
+Net income 
+$ 
+37.0 
+$ 
+15.5 
+$ 
+18.1 
+$ 
+126.2 
+Percentage change from previous quarter: 
+Production (BCFE) 
+15 
+% 
+9 
+% 
+(2 
+)% 
+(2 
+)% 
+Oil and gas production revenue, excluding the effects of hedging 
+27 
+% 
+12 
+% 
+(17 
+)% 
+13 
+% 
+Realized oil and gas hedge gain 
+(68 
+)% 
+(5 
+)% 
+258 
+% 
+(81 
+)% 
+Gain on divestiture activity 
+450 
+% 
+(40 
+)% 
+(94 
+)% 
+448 
+% 
+Lease operating expense 
+16 
+% 
+— 
+% 
+(3 
+)% 
+(13 
+)% 
+Transportation costs 
+45 
+% 
+(4 
+)% 
+24 
+% 
+(21 
+)% 
+Production taxes 
+53 
+% 
+(4 
+)% 
+(22 
+)% 
+7 
+% 
+DD&A 
+13 
+% 
+5 
+% 
+3 
+% 
+4 
+% 
+Exploration 
+47 
+% 
+(1 
+)% 
+4 
+% 
+4 
+% 
+General and administrative 
+21 
+% 
+3 
+% 
+8 
+% 
+14 
+% 
+Change in Net Profits Plan liability 
+(212 
+)% 
+(162 
+)% 
+(76 
+)% 
+(490 
+)% 
+Unrealized derivative (gain) loss 
+128 
+% 
+(371 
+)% 
+(73 
+)% 
+(341 
+)% 
+Net income 
+139 
+% 
+(14 
+)% 
+(86 
+)% 
+12,520 
+% 
+59 
+Table of Contents 
+A year to year overview of selected reserve, production and financial information, including trends: 
+Selected Operations Data (in thousands, except sales price, volumes, and per MCFE amounts): 
+As of and for the Years Ended December 31, 
+Percent Change Between 
+2010 
+2009 
+2008 
+2010/2009 
+2009/2008 
+Total proved reserves 
+Oil (MMBbl) 
+57.4 
+53.8 
+51.4 
+7 
+% 
+5 
+% 
+Natural gas (Bcf) 
+640.0 
+449.5 
+557.4 
+42 
+% 
+(19 
+)% 
+BCFE 
+984.5 
+772.2 
+865.5 
+27 
+% 
+(11 
+)% 
+Net production volumes 
+Oil (MMBbl) 
+6.4 
+6.3 
+6.6 
+— 
+% 
+(4 
+)% 
+Natural gas (Bcf) 
+71.9 
+71.1 
+74.9 
+1 
+% 
+(5 
+)% 
+BCFE 
+110.0 
+109.1 
+114.6 
+1 
+% 
+(5 
+)% 
+Average daily production 
+Oil (MBbl) 
+17.4 
+17.3 
+18.1 
+— 
+% 
+(4 
+)% 
+Natural gas (MMcf) 
+196.9 
+194.8 
+204.7 
+1 
+% 
+(5 
+)% 
+MMCFE 
+301.4 
+298.8 
+313.1 
+1 
+% 
+(5 
+)% 
+Oil & gas production revenues 
+Oil production, including hedging 
+$ 
+425,104 
+$ 
+359,075 
+$ 
+500,062 
+18 
+% 
+(28 
+)% 
+Gas production, including hedging 
+434,649 
+397,526 
+658,242 
+9 
+% 
+(40 
+)% 
+Total 
+$ 
+859,753 
+$ 
+756,601 
+$ 
+1,158,304 
+14 
+% 
+(35 
+)% 
+Oil & gas production costs 
+Lease operating expenses 
+$ 
+121,544 
+$ 
+145,463 
+$ 
+167,384 
+(16 
+)% 
+(13 
+)% 
+Transportation costs 
+21,175 
+20,657 
+22,205 
+3 
+% 
+(7 
+)% 
+Production taxes 
+52,356 
+40,680 
+81,766 
+29 
+% 
+(50 
+)% 
+Total 
+$ 
+195,075 
+$ 
+206,800 
+$ 
+271,355 
+(6 
+)% 
+(24 
+)% 
+Average net realized sales price(1) 
+Oil (per Bbl) 
+$ 
+66.85 
+$ 
+56.74 
+$ 
+75.59 
+18 
+% 
+(25 
+)% 
+Natural gas (per Mcf) 
+$ 
+6.05 
+$ 
+5.59 
+$ 
+8.79 
+8 
+% 
+(36 
+)% 
+Per MCFE data 
+Average net realized price(1) 
+$ 
+7.82 
+$ 
+6.94 
+$ 
+10.11 
+13 
+% 
+(31 
+)% 
+Lease operating expense 
+(1.10 
+) 
+(1.33 
+) 
+(1.46 
+) 
+(17 
+)% 
+(9 
+)% 
+Transportation costs 
+(0.19 
+) 
+(0.19 
+) 
+(0.19 
+) 
+— 
+% 
+— 
+% 
+Production taxes 
+(0.48 
+) 
+(0.37 
+) 
+(0.71 
+) 
+30 
+% 
+(48 
+)% 
+General and administrative 
+(0.97 
+) 
+(0.70 
+) 
+(0.69 
+) 
+39 
+% 
+1 
+% 
+Operating profit 
+$ 
+5.08 
+$ 
+4.35 
+$ 
+7.06 
+17 
+% 
+(38 
+)% 
+Depletion, depreciation and amortization 
+$ 
+3.06 
+$ 
+2.79 
+$ 
+2.74 
+10 
+% 
+2 
+% 
+(1) Includes the effects of our hedging activities. 
+We present per MCFE information because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe require analysis. Average daily production for the year ended December 31, 2010, increased one percent to 301.4 MMCFE compared with 298.8 MMCFE for the same period in 2009, driven mainly by the development of our Eagle Ford program. Adjusting for divestitures, our average daily production from retained properties for the year ended December 31, 2010, increased 12 percent to 294.0 MMCFE compared with 262.3 MMCFE for the same period in 2009. 
+Changes in production volumes, oil and gas production revenues, and costs reflect the cyclical and highly volatile nature of our industry. Our average net realized price for the year ended December 31, 2010, was $7.82 per MCFE compared with $6.94 per MCFE for the same period in 2009. The increase in our equivalent realized price for production corresponds with stronger commodity prices in 2010 when compared with 2009. 
+Our LOE for the year ended December 31, 2010, decreased 17 percent to $1.10 per MCFE compared with $1.33 for the same period in 2009. The divestiture of non-strategic properties with meaningfully higher operating costs is the primary reason for the decline in LOE from 2009. We believe the steady increase in industry activity we have experienced will put upward pressure on lease operating costs in 2011. Production taxes for year ended December 31, 2010, increased 30 percent to $0.48 per MCFE compared with $0.37 for the same period in 2009. 
+60 
+Table of Contents 
+Production taxes are highly correlated to pre-hedge oil and gas revenues, and stronger commodity prices have impacted results for this expense item. Transportation costs remained steady at $0.19 per MCFE for the years ended December 31, 2010, and 2009. Our general and administrative expense for the year ended December 31, 2010, increased 39 percent to $0.97 per MCFE compared to $0.70 per MCFE for the same period in 2009. A portion of our general and administrative expense is linked to our profitability and cash flow, which are driven in large part by the realized commodity prices we receive for our production. The Net Profits Plan and a portion of our current short-term incentive compensation are tied to net revenues and therefore are subject to variability. Our operating profit for the year ended December 31, 2010, increased 17 percent to $5.08 per MCFE compared to $4.35 per MCFE for the same period in 2009. 
+Our depletion, depreciation, and amortization, including asset retirement obligation accretion expense, for the year ended December 31, 2010, increased ten percent to $3.06 per MCFE compared to $2.79 per MCFE for the same period in 2009. Depreciation, depletion, and amortization was impacted by our divestiture of lower cost basis properties in the first quarter of 2010. Additionally, we have been impacted by higher DD&A rates in our Eagle Ford and Haynesville shales. We are incurring capital for research wells and infrastructure that will benefit future development in these plays but are currently limited in the amount of reserves we can record to carry the costs, which results in higher per unit DD&A costs early in the lives of these plays. Our DD&A rate can also fluctuate as a result of impairments, divestitures, and changes in the mix of our production and the underlying proved reserve volumes. Additionally, the accounting treatment for assets that are classified as assets held for sale can impact our DD&A rate since properties held for sale are not depleted. 
+Please refer to Comparison of Financial Results and Trends between 2010 and 2009 for additional discussion on oil and gas production expense, DD&A, and general and administrative expense. 
+Financial information (in thousands, except per share amounts): 
+As of and for the Years Ended December 31, 
+Percent Change Between 
+2010 
+2009 
+2008 
+2010/2009 
+2009/2008 
+Working capital (deficit) 
+$ 
+(227,408 
+) 
+$ 
+(87,625 
+) 
+$ 
+15,193 
+160 
+% 
+(677 
+)% 
+Long-term debt 
+$ 
+323,673 
+$ 
+454,902 
+$ 
+558,713 
+(29 
+)% 
+(19 
+)% 
+Stockholders’ equity 
+$ 
+1,218,526 
+$ 
+973,570 
+$ 
+1,162,509 
+25 
+% 
+(16 
+)% 
+Net income 
+$ 
+196,837 
+$ 
+(99,370 
+) 
+$ 
+87,348 
+(298 
+)% 
+(214 
+)% 
+Basic net income per common share 
+$ 
+3.13 
+$ 
+(1.59 
+) 
+$ 
+1.40 
+(297 
+)% 
+(214 
+)% 
+Diluted net income per common share 
+$ 
+3.04 
+$ 
+(1.59 
+) 
+$ 
+1.38 
+(291 
+)% 
+(215 
+)% 
+Basic weighted-average shares outstanding 
+62,969 
+62,457 
+62,243 
+1 
+% 
+— 
+% 
+Diluted weighted-average shares outstanding 
+64,689 
+62,457 
+63,133 
+4 
+% 
+(1 
+)% 
+Net cash provided by operating activities 
+$ 
+497,097 
+$ 
+436,106 
+$ 
+679,190 
+14 
+% 
+(36 
+)% 
+Net cash used in investing activities 
+$ 
+(361,573 
+) 
+$ 
+(304,092 
+) 
+$ 
+(673,754 
+) 
+19 
+% 
+(55 
+)% 
+Net cash used in financing activities 
+$ 
+(141,096 
+) 
+$ 
+(127,496 
+) 
+$ 
+(42,815 
+) 
+11 
+% 
+198 
+% 
+We present this table as a summary of information relating to key indicators of financial condition and operating performance that we believe are important. 
+We account for our 3.50% Senior Convertible Notes under the treasury stock method. There is no impact on the diluted share calculation for the periods presented since our average stock price for the relevant reporting periods has not exceeded the conversion price. The 3.50% Senior Convertible Notes were issued April 4, 2007, and have not been dilutive for a reporting period since their issuance. Subsequent to December 31, 2010, our stock has consistently been trading above the $54.42 conversion price and as such we expect the 3.50% Senior Convertible Notes to have a dilutive impact on our first quarter 2011 dilutive earnings per share calculation. We have in-the-money stock options, unvested RSUs, and contingent 
+61 
+Table of Contents 
+PSAs that may be potentially dilutive securities. There were no potentially dilutive shares related to in-the-money stock options, unvested RSUs, and contingent PSAs included in the diluted earnings per share calculation for the year ended December 31, 2009, as we recorded a net loss for the period. Both basic and diluted earnings per share are presented in the table above. A detailed explanation is presented under the caption Earnings per Share included in Note 1 — Summary of Significant Accounting Policies, in Part IV, Item 15 of this report. 
+Basic and diluted weighted-average common shares outstanding used in our 2010, 2009, and 2008 earnings per share calculations reflect our stock repurchases, offset by increases in outstanding shares related to stock option exercises, ESPP shares issued, and vested RSUs. We issued 346,377, 189,740, and 868,372 shares of common stock in 2010, 2009, and 2008, respectively, as a result of stock option exercises. The number of RSUs that vested in 2010, 2009, and 2008 were 160,398, 211,092, and 291,659, respectively. The number of ESPP shares issued totaled 52,948, 86,308, and 45,228 in 2010, 2009, and 2008, respectively. These share issuances were offset by the repurchase of 2,135,600 shares of common stock in 2008 through our stock repurchase plan. There were no shares of common stock repurchased in the open market in 2010 or 2009. 
+Additional Comparative Data in Tabular Format: 
+Change Between Years 
+2010 and 2009 
+2009 and 2008 
+Oil and Gas Production Revenues: 
+Increase (decrease) in oil and gas production revenues, net of hedging (in thousands) 
+$ 
+103,152 
+$ 
+(401,703 
+) 
+Components of Revenue Increases (Decreases): 
+Oil 
+Realized price change per Bbl, net of hedging 
+$ 
+10.11 
+$ 
+(18.85 
+) 
+Realized price percent change 
+18 
+% 
+(25 
+)% 
+Production change (MMBbl) 
+0.1 
+(0.3 
+) 
+Production percentage change 
+— 
+% 
+(4 
+)% 
+Natural Gas 
+Realized price change per Mcf, net of hedging 
+$ 
+0.46 
+$ 
+(3.20 
+) 
+Realized price percentage change 
+8 
+% 
+(36 
+)% 
+Production change (Bcf) 
+0.8 
+(3.8 
+) 
+Production percentage change 
+1 
+% 
+(5 
+)% 
+Our product mix as a percentage of total oil and gas revenue, including the effects of hedging, and production: 
+Years Ended December 31, 
+2010 
+2009 
+2008 
+Revenue 
+Oil 
+49 
+% 
+47 
+% 
+43 
+% 
+Natural Gas 
+51 
+% 
+53 
+% 
+57 
+% 
+Production 
+Oil 
+35 
+% 
+35 
+% 
+35 
+% 
+Natural Gas 
+65 
+% 
+65 
+% 
+65 
+% 
+62 
+Table of Contents 
+Information regarding the effects of oil and gas hedging activity: 
+Years Ended December 31, 
+2010 
+2009 
+2008 
+Oil Hedging 
+Percentage of oil production hedged 
+47 
+% 
+52 
+% 
+61 
+% 
+Oil volumes hedged (MBbl) 
+2,999 
+3,306 
+4,022 
+Increase (Decrease) in oil revenue 
+$ 
+(36.8) million 
+$ 
+14.8 million 
+$ 
+(115.1) million 
+Average realized oil price per Bbl before hedging 
+$ 
+72.65 
+$ 
+54.40 
+$ 
+92.99 
+Average realized oil price per Bbl after hedging 
+$ 
+66.85 
+$ 
+56.74 
+$ 
+75.59 
+Natural Gas Hedging, including NGLs 
+Percentage of gas production hedged 
+43 
+% 
+45 
+% 
+46 
+% 
+Natural gas volumes hedged (MMBtu) 
+34.6 million 
+34.3 million 
+36.4 million 
+Increase in gas revenue 
+$ 
+60.3 million 
+$ 
+125.9 million 
+$ 
+14.0 million 
+Average realized gas price per Mcf before hedging 
+$ 
+5.21 
+$ 
+3.82 
+$ 
+8.60 
+Average realized price per Mcf after hedging 
+$ 
+6.05 
+$ 
+5.59 
+$ 
+8.79 
+Information regarding the components of exploration expense: 
+Years Ended December 31, 
+Summary of Exploration Expense (in millions) 
+2010 
+2009 
+2008 
+Geological and geophysical expenses 
+$ 
+21.5 
+$ 
+20.2 
+$ 
+14.2 
+Exploratory dry holes 
+0.3 
+7.8 
+6.8 
+Overhead and other expenses 
+42.1 
+34.2 
+39.1 
+Total 
+$ 
+63.9 
+$ 
+62.2 
+$ 
+60.1 
+Comparison of Financial Results and Trends between 2010 and 2009 
+Oil and gas production revenue. Average daily production for the year ended December 31, 2010, increased one percent to 301.4 MMCFE compared with 298.8 MMCFE for the same period in 2009. The following table presents the regional changes in our production and oil and gas revenues and costs between the two years. 
+Average Net Daily Production Added/(Lost) 
+Pre-Hedge Oil and Gas Revenue Added 
+Production Costs Increase/ (Decrease) 
+(MMCFE) 
+(in millions) 
+(in millions) 
+ArkLaTex 
+(1.5 
+) 
+$ 
+7.4 
+$ 
+(5.8 
+) 
+Mid-Continent 
+(7.2 
+) 
+23.9 
+4.0 
+South Texas & Gulf Coast 
+35.4 
+131.4 
+20.6 
+Permian 
+(1.3 
+) 
+37.8 
+2.2 
+Rocky Mountain 
+(22.8 
+) 
+19.8 
+(32.7 
+) 
+Total 
+2.6 
+$ 
+220.3 
+$ 
+(11.7 
+) 
+The largest regional production decrease occurred in the Rocky Mountain region as a result of our divestitures of non-strategic oil and gas assets that occurred in the fourth quarter of 2009 and first quarter of 2010. The largest production growth occurred in our South Texas & Gulf Coast region as a result of production from drilling activity in our Eagle Ford shale program. We expect to grow our overall full year production in 2011. 
+63 
+Table of Contents 
+The following table summarizes the average realized prices we received in 2010 and 2009, before the effects of hedging: 
+For the Years Ended 
+December 31, 
+2010 
+2009 
+Realized oil price ($/Bbl) 
+$ 
+72.65 
+$ 
+54.40 
+Realized gas price ($/Mcf) 
+$ 
+5.21 
+$ 
+3.82 
+Realized equivalent price ($/MCFE) 
+$ 
+7.60 
+$ 
+5.65 
+The 35 percent increase in average realized prices per MCFE coupled with a one percent increase in production volumes between periods resulted in higher oil and gas revenue. We expect our realized price to trend with commodity prices. 
+Realized oil and gas hedge gain. We recorded a net realized hedge gain of $23.5 million for the year ended December 31, 2010, compared with a net realized hedge gain of $140.6 million for the same period in 2009. These gains were mainly related to favorable settlements on natural gas hedges. Please refer to our discussion above under the heading Oil, Gas, and NGL Prices . 
+Marketed gas system revenue and expense. Marketed gas system revenue increased $11.6 million to $70.1 million for the year ended December 31, 2010, compared with $58.5 million for the year ended December 31, 2009. Concurrent with the increase in marketed gas system revenue, marketed gas system expense increased $9.1 million to $66.7 million for the year ended December 31, 2010, compared with $57.6 million for the comparable period of 2009. We expect that marketed gas system revenue and expense will continue to trend with increases and decreases in production and our net realized price for natural gas. 
+Gain on divestiture activity. We recorded a gain on divestiture activity of $155.3 million for the year ended December 31, 2010, compared with $11.4 million for the comparable period of 2009. The 2010 gain relates to the divestitures of non-strategic oil and gas properties located in our Rocky Mountain and Permian regions as discussed above. The 2009 gain was mainly related to the Hanging Woman Basin property divestiture that closed in late 2009. The final gain on divestiture activity related to the Permian divestiture will be adjusted for normal post-closing adjustments and is expected to be finalized in the first half of 2011. We are currently marketing other oil and gas properties, and we will continue to evaluate property for divestiture in the normal course of our business. Please refer to Marketing of properties under 2010 Highlights for additional discussion. 
+Oil and gas production expense. Total production costs decreased $11.7 million or six percent to $195.1 million for the year ended December 31, 2010, compared with $206.8 million in 2009. Total oil and gas production costs per MCFE decreased $0.12 to $1.77 for the year ended December 31, 2010, compared with $1.89 in 2009. This decrease is comprised of the following: 
+· A $0.23 decrease in recurring LOE on a per MCFE basis reflects the sale of non-strategic properties in late 2009 and early 2010 with higher per unit LOE costs that resulted in lower LOE on a per unit basis year over year. We expect the various resources required to service our industry will become more sought after and harder to secure as a result of an increase in activity. We expect to see upward pressure on LOE in 2011. 
+· An $0.11 increase in production taxes on a per MCFE basis is due to the increase in realized prices between periods. We expect production taxes to trend with commodity prices over time. 
+· Workover LOE on a per MCFE basis remained flat year over year. 
+· Transportation costs on a per MCFE basis remained flat year over year. We anticipate transportation costs will increase over the next year on a per MCFE basis given the increase in production expected from programs with higher transportation costs. 
+64 
+Table of Contents 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A increased $31.9 million, or ten percent, to $336.1 million in 2010 compared with $304.2 million in 2009. DD&A expense per MCFE increased ten percent to $3.06 in 2010 compared to $2.79 in 2009. Please refer to discussion under the heading Selected Operations Data under Overview of the Company. Any future proved property impairments, divestitures, and changes in underlying proved reserve volumes will impact our DD&A expense. 
+Exploration. Exploration expense increased $1.7 million or three percent to $63.9 million in 2010 compared with $62.2 million for the same period in 2009. The overall increase in expense primarily relates to an increase in exploration overhead, which is partially offset by a decrease in exploratory dry hole expense. In 2009, we had $7.8 million of exploratory dry hole expense related to properties in our ArkLaTex region compared with minimal exploratory dry hole expense in the current year. Other increases in exploration costs related to an increase in equity incentive compensation expense are discussed under General and administrative below. 
+Impairment of proved properties. We recorded a $6.1 million impairment of proved oil and gas properties in 2010 compared to $174.8 million in 2009. A significant decrease in commodity prices, including differentials, during the first quarter of 2009 caused the majority of the non-cash impairment. The largest portion of the impairment in 2009 was $97.3 million related to assets located in the Mid-Continent region which were impacted at the end of the first quarter by low natural gas prices and wider than normal differentials. We generally expect proved property impairments will be more likely to occur in periods of low commodity prices. 
+Abandonment and impairment of unproved properties. During 2010, we abandoned or impaired $2.0 million of unproved properties compared with $45.4 million for 2009. The largest specific components of the 2009 impairment and abandonment related to our Floyd shale acreage located in Mississippi and certain acreage in Oklahoma. Additionally in 2009, we incurred write-offs related to acreage that we did not maintain based on our current capital allocation plans or related to acreage that we do not believe will be prospective. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices since fewer dollars will be available for exploratory and development efforts. 
+Impairment of materials inventory. There were no impairments of materials inventory recorded in 2010. We recorded a $14.2 million impairment of materials inventory for the year ended December 31, 2009. The 2009 inventory impairment was caused by a decrease in the value of tubular goods and other raw materials. Impairments of materials inventory are impacted by fluctuations in the materials cost environment and increases and decreases in development and exploration activity, which generally trend with commodity prices. 
+General and administrative. General and administrative expense increased $30.7 million or 40 percent, to $106.7 million for the year ended December 31, 2010, compared with $76.0 million for the same period in 2009. G&A increased $0.27 to $0.97 per MCFE for the year ended December 31, 2010, compared to $0.70 per MCFE for the same period in 2009. 
+General and administrative expense increased due to a $21.9 million increase in base compensation, cash bonus, and long-term incentive compensation expense for the year ended December 31, 2010, compared with the same period in 2009. The increase in cash bonus and long-term incentive compensation expense reflects compensation expense associated with the PSAs granted in the third quarter of 2010, as well as the improvement in our performance and the anticipated achievement of various performance criteria, established by our Compensation Committee. 
+Additionally, G&A expense increased as a result of a $5.1 million decrease in COPAS overhead reimbursements, caused by a decrease in our operated well count resulting from our recent divestiture efforts, and a $1.4 million increase in cash payments accrued under the Net Profits Plan. We expect payments made under the Net Profits Plan to trend with commodity prices. 
+Bad debt expense (recovery). We did not record any bad debt expense or recovery of bad debt expense in 2010. In 2008 SemGroup, L.P. and certain of its North American subsidiaries filed for bankruptcy protection. At that time, certain SemGroup L.P. entities purchased a portion of our crude oil production. As a result of the bankruptcy filing, we recorded bad debt expense of $16.6 million as of December 31, 2008. In 2009, we sold a 
+65 
+Table of Contents 
+portion of our SemGroup L.P. administrative claim at which time we recorded a recovery of bad debt expense of $5.2 million. 
+Change in Net Profits Plan liability. For 2010 this non-cash item was a $34.4 million benefit compared to a $7.1 million benefit for 2009. We broadly expect the change in this liability to trend with commodity prices but it can be impacted by divestiture activity. Please refer to discussion under the heading Net Profits Plan under Overview of the Company. 
+Unrealized derivative loss. We recognized a loss of $8.9 million in 2010 compared to a loss of $20.5 million for 2009. This non-cash item is driven by the change in the value of our hedge position, as well as the portion of that position that is considered ineffective for accounting purposes. Please refer to discussion under the heading Hedging Activities under Overview of the Company. 
+Other expense. Other expense decreased $10.5 million to $3.0 million in 2010 compared with $13.5 million in 2009. During 2009 we incurred $1.5 million of expense related to the assignment of a drilling rig contract in our Rocky Mountain region and incurred a loss related to hurricanes of $8.3 million. 
+Income tax benefit (expense). Income tax expense totaled $118.1 million for 2010 compared to a tax benefit of $60.1 million for 2009, resulting in effective tax rates of 37.5 percent and 37.7 percent, respectively. The effective rate change from 2009 primarily reflects changes in the mix of the highest marginal state tax rates, anticipated utilization of state tax net operating losses, and differing effects of other permanent differences including percentage depletion. Our current income tax expense in 2010 is $3.5 million compared to current income tax benefit of $20.4 million in 2009. These amounts are three percent and 34 percent, respectively, of the total income tax expense or benefit for each period. 
+Qualified property placed in service in 2009 was eligible for 50 percent bonus depreciation as a result of tax law passed in 2008. At the end of 2010, to aid a perceived slowly recovering economy, Federal legislation was passed making qualified property placed in service after September 8, 2010, and before January 1, 2012, eligible for 100 percent bonus depreciation. This same law makes qualified property placed in service between January 1, 2010, and December 31, 2012, eligible for the 50 percent bonus depreciation election. Since we are currently in an accelerated development mode on several of our unconventional projects we will not receive much of a current benefit resulting solely from this deduction. However, making this election for 2010 accelerates deductions impacting our alternative minimum tax calculations in future years providing us with an anticipated opportunity, given current development expectations, to limit the impact of alternative minimum tax on the calculation of current income tax expense in those years. The amounts of current income tax expense reported above reflect our election to utilize bonus depreciation for both years. The benefit of bonus depreciation in 2010 was limited by alternative minimum tax calculations related to intangible drilling costs. Our 2009 current income tax benefit reflects creation of a net operating loss due in part to bonus depreciation which we carried back to 2005 to obtain a refund. 
+At December 31, 2010, we have utilized net operating losses to offset all prior year income for open tax years. The ability to record benefit from future net operating loss deductions will depend upon our ability to justify utilization of those losses in future tax years. The Administration’s Fiscal Year 2011 Budget includes proposals for legislation that would, if enacted into law, make significant changes to U.S. tax laws, which could eliminate or postpone certain U.S. federal income tax incentives currently available to oil and gas exploration and production companies. Proposed changes include, but are not limited to (i) repeal of the percentage depletion allowance for oil and gas properties, (ii) elimination of current deductions for intangible drilling and development costs, (iii) elimination of the deduction for certain domestic production activities, and (iv) extension of the amortization period for certain geological and geophysical expenditures. Each of these changes is proposed to be effective for taxable years beginning, or in the case of costs described in (ii) and (iv), costs paid or incurred, after December 31, 2010. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. Enactment of these changes would be expected to negatively impact our effective tax rate and the cash tax portion of our income tax expense would increase in the year the legislation became effective. 
+66 
+Table of Contents 
+Comparison of Financial Results between 2009 and 2008 
+Oil and gas production revenue. Production decreased five percent to 109.1 BCFE for the year ended December 31, 2009, compared with 114.6 BCFE for the year ended December 31, 2008. Production for the year ended December 31, 2009, included approximately 5.1 BCFE related to non-strategic properties divested throughout 2009. Adjusting for divestitures of non-strategic properties that were sold in the last two years, production on retained properties declined slightly from 104.5 BCFE in 2008 to 104.0 BCFE in 2009. The following table presents the regional changes in our production and oil and gas revenues and costs between the two years: 
+Average Net Daily Production Added/(Lost) 
+Pre-Hedge Oil and Gas Revenue Added (Lost) 
+Production Costs Increase (Decrease) 
+(MMCFE) 
+(in millions) 
+(in millions) 
+ArkLaTex 
+(9.9 
+) 
+$ 
+(115.0 
+) 
+$ 
+(1.1 
+) 
+Mid-Continent 
+8.5 
+(142.1 
+) 
+(16.4 
+) 
+South Texas & Gulf Coast 
+(12.4 
+) 
+(97.0 
+) 
+(13.8 
+) 
+Permian 
+3.7 
+(79.1 
+) 
+(1.7 
+) 
+Rocky Mountain 
+(4.2 
+) 
+(210.2 
+) 
+(31.6 
+) 
+Total 
+(14.3 
+) 
+$ 
+(643.4 
+) 
+$ 
+(64.6 
+) 
+Daily production decreased by approximately 14.3 MMCFE during 2009 compared to 2008. Production decreased between these two periods as a result of decreased levels of capital investment throughout 2009 and the lack of contribution in 2009 from properties that were sold in the second half of 2008. The largest regional increase between 2009 and 2008 occurred in the Mid-Continent region as a result of success in the horizontal Woodford shale program in the Arkoma Basin and strong results from our Deep Springer program in the Anadarko Basin. Production growth in the Permian region was the result of continued development of Wolfberry assets at Sweetie Peck and Halff East. The decrease in the South Texas & Gulf Coast region’s production was primarily a result of the loss of production from the Judge Digby Field due to an exchange of assets that occurred in late 2008. The decrease in our ArkLaTex region was due to natural decline and decreased levels of capital investment in the region by us and our partners, particularly at the Elm Grove Field. The Rocky Mountain region realized a slight decline as a result of its more mature production decline profile and modest capital investment. 
+The following table summarizes the average realized prices we received in 2009 and 2008, before the effects of hedging: 
+For the Years Ended 
+December 31, 
+2009 
+2008 
+Realized oil price ($/Bbl) 
+$ 
+54.40 
+$ 
+92.99 
+Realized gas price ($/Mcf) 
+$ 
+3.82 
+$ 
+8.60 
+Realized equivalent price ($/MCFE) 
+$ 
+5.65 
+$ 
+10.99 
+The 49 percent decrease in average realized prices per MCFE coupled with a five percent decrease in production volumes between periods resulted in lower oil and gas revenue. 
+Realized oil and gas hedge gain (loss). We recorded a net realized hedge gain of $140.6 million for the year ended December 31, 2009, mainly related to favorable settlements on gas hedges. For the year ended December 31, 2008, we recorded a net realized hedge loss of $101.1 million mainly due to unfavorable settlements on oil hedges. 
+67 
+Table of Contents 
+Marketed gas system revenue and expense. Marketed gas system revenue decreased $18.9 million to $58.5 million for the year ended December 31, 2009, compared with $77.4 million for the comparable period of 2008. Concurrent with the decrease in marketed gas system revenue, marketed gas system expense decreased $14.6 million to $57.6 million for the year ended December 31, 2009, compared with $72.2 million for the comparable period of 2008. 
+Gain on divestiture activity. We recorded a gain on divestiture activity of $11.4 million for the year ended December 31, 2009, compared with $63.6 million for the comparable period of 2008. The 2009 gain was mainly related to the Hanging Woman Basin divestiture that closed in December of 2009, which was subject to normal post-closing adjustments and was finalized during 2010. The 2008 gain was mainly related to the Abraxas divestiture that closed in January 2008. 
+Oil and gas production expense. Total production costs decreased $64.6 million or 24 percent to $206.8 million for the year ended December 31, 2009, compared with $271.4 million in 2008. Total oil and gas production costs per MCFE decreased $0.47 to $1.89 for the year ended December 31, 2009, compared with $2.36 in 2008. This decrease was comprised of the following: 
+· A $0.34 decrease in production taxes on a per MCFE basis due to the decrease in realized prices between periods. 
+· A $0.11 decrease in recurring lease operating expense on a per MCFE basis was related to reductions in recurring LOE that stemmed from the slowdown in activity in the exploration and production industry, as well as the broader economy. 
+· A $0.02 decrease in overall workover LOE on a per MCFE basis was related to a reduction in the amount of workovers that were performed given the slowdown in activity in the exploration and production industry. 
+· Transportation costs on a per MCFE basis remained flat year over year. 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A decreased $10.1 million, or three percent, to $304.2 million in 2009 compared with $314.3 million in 2008. DD&A expense per MCFE increased two percent to $2.79 in 2009 compared to $2.74 in 2008. The decrease in absolute DD&A reflected lower total production volumes in 2009 compared to 2008. The DD&A expense per MCFE increase reflects the industry trend of increased amounts of investment to add reserves. Generally, as these recently acquired or developed assets become a larger portion of our asset base, our DD&A expense will increase as those acquisitions and developments were made at higher costs. 
+Exploration. Exploration expense increased $2.1 million or four percent to $62.2 million in 2009 compared with $60.1 million for 2008. The increase was due to a $1.0 million increase in exploratory dry hole expense and a $6.0 million increase in geological and geophysical expense due to an increase in the amount spent on seismic. These increases were offset by a $4.9 million decrease in exploration overhead expense due to a decrease in Net Profits Plan payments as a result of decreased oil and gas commodity prices. 
+Impairment of proved properties. We recorded a $174.8 million impairment of proved oil and gas properties in 2009 compared to $302.2 million in 2008. A significant decrease in commodity prices, including differentials, during the first quarter of 2009 caused the majority of the non-cash impairment. The largest portion of the impairment in 2009 was $97.3 million related to assets located in the Mid-Continent region which were impacted at the end of the first quarter by low natural gas prices and wider than normal differentials. Our ArkLaTex region was impacted by a $20.4 million impairment related to negative pricing and engineering revisions. We incurred a $14.0 million impairment on proved properties related to the write-down of certain assets located in the Gulf of Mexico in which we are relinquishing our ownership interests. 
+Abandonment and impairment of unproved properties. During 2009, we abandoned or impaired $45.4 million of unproved properties compared with $39.0 million for 2008. The largest specific components of the 2009 impairment and abandonment related to our Floyd shale acreage located in Mississippi and certain 
+68 
+Table of Contents 
+acreage in Oklahoma. Additionally, we incurred write-offs related to acreage we believe we would not keep based on our capital allocation plans or related to acreage that we did not believe to be prospective. 
+Impairment of Goodwill. We recorded a $9.5 million impairment of goodwill in 2008. The goodwill was the result of our purchase of Agate Petroleum, Inc. in January 2005. The impairment was a result of downward price adjustments to reserves for properties located in our Mid-Continent and Rocky Mountain regions and represented our entire goodwill balance. We had no goodwill impairment in 2009. 
+Impairment of materials inventory. We recorded a $14.2 million impairment of materials inventory for the year ended December 31, 2009. There were no impairments recorded in 2008. The inventory impairment was caused by a decrease in the value of tubular goods and other raw materials. 
+General and administrative. General and administrative expense decreased $3.5 million or four percent to $76.0 million for the year ended December 31, 2009, compared with $79.5 million for the same period in 2008. G&A increased $0.01 to $0.70 per MCFE for the year ended December 31, 2009, compared to $0.69 per MCFE for the same period in 2008. 
+General and administrative expense decreased due to an $11.3 million decrease in cash payments made under the Net Profits Plan. As a result of the lower price realization we received in 2009 compared to 2008, the payouts from this plan were meaningfully smaller than those paid out in the prior year. 
+Compensation related costs allocated to general and administrative expense increased in 2009. The largest increases were for headcount related costs, such as salary, benefits, and payroll taxes, which increased $10.6 million for the year ended December 31, 2009, when compared with the same period in 2008. A significant driver of this headcount increase was the conversion from contract lease operators to internal lease operators which began to take place in 2008. Stock compensation was also up $ 3.3 million year over year as a result of layering in the second year of stock compensation amortization from our PSA long-term incentive program. COPAS overhead reimbursements were $6.4 million higher for the year ended December 31, 2009, compared with the same period in 2008. 
+Bad debt expense (recovery). We recorded a recovery of bad debt expense of $5.2 million in 2009. We recorded $16.7 million of bad debt expense in 2008 of which $16.6 million was a result of SemGroup L.P. and certain of its North American subsidiaries filing for bankruptcy protection. Certain SemGroup entities had purchased a portion of our crude oil production. This amount related to oil produced in June and July of 2008 that was fully reserved in the year ended December 31, 2008. 
+Change in Net Profits Plan liability. For the year ended December 31, 2009, this non-cash item was a $7.1 million benefit compared to a $34.0 million benefit for the same period in 2008. Significant decreases in oil and gas commodity prices decreased the estimated liability for the future amounts to be paid to plan participants. 
+Unrealized derivative (gain) loss. We recognized a loss of $20.5 million for the year ended December 31, 2009, compared to a gain of $11.2 million for the same period in 2008. This non-cash item was driven by the change in the value of our hedge position, as well as the portion of that position that is considered ineffective for accounting purposes. 
+Other expense. Other expense increased $3.1 million to $13.5 million for the year ended December 31, 2009, compared with $10.4 million for the same period in 2008. During the year ended December 31, 2009, we incurred $1.5 million of expense related to the assignment of a drilling rig contract in our Rocky Mountain region. We also incurred a loss related to hurricanes of $8.3 million for the year ended December 31, 2009, compared with a loss related to hurricanes of $7.0 million for the same period in 2008. 
+Income tax benefit (expense). Income tax benefit totaled $60.1 million for 2009 compared to tax expense of $57.4 million for 2008, resulting in effective tax rates of 37.7 percent and 39.7 percent, respectively. The effective rate change from 2008 primarily reflected the impact of goodwill impairment in that year, but changes in the mix of the highest marginal state tax rates and differing effects of other permanent differences, including the 
+69 
+Table of Contents 
+impact between years of the domestic production activities deduction and percentage depletion, also had an effect. Our current income tax benefit in 2009 was $20.4 million compared to current income tax expense of $19.2 million in 2008. These amounts were 34 percent and 33 percent, respectively, of the total income tax benefit or expense for each period. Our 2009 current income tax benefit reflected the creation of a net operating loss which we could carry back to one or more prior tax years to obtain a refund. 
+Overview of Liquidity and Capital Resources 
+In order to meet our projected growth targets, we will have to effectively invest capital into new projects and acquisitions. The following analysis and discussion includes our assessment of market risk and possible effects of inflation and changing prices. 
+Sources of cash 
+In 2011, we anticipate that cash flow from operations, the proceeds from our 6.625% Senior Notes, and expected divestiture and/or joint venture activity will fund the majority of our 2011 capital program. Our credit facility will be used to fund any remaining balance of our capital program for the year. Given the size of the commitments associated with our existing inventory of potential capital projects, our requirements for funding could increase significantly during 2011 and beyond. As a result, we may consider accessing the capital markets or using other financing alternatives as we determine how to best fund our capital program. We will continue to evaluate our property base to identify and divest of properties we consider non-core to our strategic goals. 
+Our primary sources of liquidity are the cash flows provided by our operating activities, use of our credit facility, divestitures of properties, and other financing alternatives, including accessing the capital and debt markets. From time to time, we may be able to enter into carrying cost funding and sharing arrangements with third parties for particular exploration and development programs. All of our sources of liquidity can be impacted by the general condition of the broad economy and by significant fluctuations in oil and gas prices, operating costs, and volumes produced, all of which affect us and our industry. We have no control over the market prices for oil, natural gas, or NGLs, although we are able to influence the amount of our net realized revenues related to our oil and gas sales through the use of derivative contracts. The borrowing base on our credit facility could be reduced as a result of lower commodity prices or divestitures of producing properties. Historically, decreases in commodity prices have limited our industry’s access to the capital markets. Subsequent to year end, we issued $350.0 million in aggregate principal amount of 6.625% Senior Notes. We do not anticipate the need to issue additional debt or equity in the near term, however these are options we would consider under the appropriate circumstances. 
+Current credit facility 
+On April 14, 2009, we entered into an amended $1.0 billion senior secured revolving credit facility with twelve participating banks. The initial borrowing base was set at $900 million. During September 2010 the lending group redetermined our reserve-based borrowing base under the credit facility at $1.1 billion. We have been provided a $678 million commitment amount by the bank group. We believe that the current commitment is sufficient to meet our current liquidity and operating needs. To date, we have experienced no issues drawing upon our credit facility. No individual bank participating in the credit facility represents more than 17 percent of the lending commitments under the credit facility. We monitor the credit environment closely and have frequent discussions with the lending group. Our credit facility expires on July 31, 2012, and we have begun discussions with the banks within the existing bank group, as well as banks not in the existing facility, about a new credit facility. Our intention is to have a new credit facility in place during the first half of 2011. 
+Pursuant to the terms of our credit facility our borrowing base was reduced by 25 percent of the $350.0 million of 6.625% Senior Notes issued, resulting in a new borrowing base of $1.0 billion. The next redetermination of our borrowing base is scheduled to occur in April 2011. 
+70 
+Table of Contents 
+We had no borrowings outstanding under this facility as of February 18, 2011. We had a single letter of credit outstanding under our credit facility, in the amount of $483,000 as of February 18, 2011, which reduces the amount available under the commitment amount on a dollar-for-dollar basis. We currently have $677.5 million of available borrowing capacity under this facility. Borrowings under our credit facility are secured by mortgages on substantially all of our oil and gas properties. Please refer to Note 5 — Long-term Debt in Part IV, Item 15 of this report for our borrowing base utilization grid. 
+The following table sets forth our weighted-average credit facility debt balance and weighted-average interest rate: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in millions) 
+Weighted-average credit facility debt balance 
+$ 
+54.6 
+$ 
+275.4 
+$ 
+257.0 
+Weighted-average interest rate(1) 
+8.3 
+% 
+5.4 
+% 
+5.8 
+% 
+(1) Includes the impact of our 3.50% Senior Convertible Notes. 
+Our weighted-average interest rates in the current and prior year include cash interest payments, cash fees paid on the unused portion of the credit facility’s aggregate commitment amount, letter of credit fees, amortization of the convertible notes debt discount, and amortization of deferred financing costs. The increase in our weighted-average interest rate from 2009 is the result of commitment fees and non-cash charges being spread across a much lower average outstanding credit facility debt balance. 
+We are subject to customary covenants under our credit facility, including limitations on dividend payments and requirements to maintain certain financial ratios, which include debt to earnings before interest, taxes, depreciation, and amortization of less than 3.5 to 1.0 and a current ratio as defined by our credit agreement of not less than 1.0. As of December 31, 2010, our debt to EBITDA ratio and current ratio as defined by our credit agreement, were 0.67 and 2.05, respectively. We are in compliance with all financial and non-financial covenants under our credit facility. 
+Uses of cash 
+We use cash for the acquisition, exploration, and development of oil and gas properties, and for the payment of debt obligations, trade payables, income taxes, common stock repurchases, stockholder dividends, and other general corporate purposes. During 2010, we spent $668.3 million for exploration and development capital expenditures. These amounts differ from the cost incurred amounts based on the timing of cash payments associated with these activities as compared to the accrual-based activity upon which the costs incurred amounts are presented. These cash flows were funded using cash inflows from operations, proceeds from the sale of assets, and available borrowing capacity under our credit facility. 
+Expenditures for exploration and development of oil and gas properties and acquisitions are the primary use of our capital resources. The majority of our capital and exploration expenditures in 2011 will be funded with current year operating cash flows and the proceeds from the divestiture of assets and the issuance of our 6.625% Senior Notes. The amount and allocation of future capital expenditures will depend upon a number of factors including the number and size of available economic acquisitions and drilling opportunities, our cash flows from operating, investing and financing activities, and our ability to assimilate acquisitions. In addition, the impact of oil and natural gas prices on investment opportunities, the availability of capital and borrowing facilities, and the success of our development and exploratory activities may lead to changes in funding requirements for future development. We regularly review our capital expenditure budget to assess changes in current and projected cash flows, acquisition opportunities, debt requirements, and other factors. 
+We may from time to time repurchase certain amounts of our outstanding debt securities for cash and/or through exchanges for other securities. Such repurchases or exchanges may be made in open market transactions, 
+71 
+Table of Contents 
+privately negotiated transactions, or otherwise. Any such repurchases or exchanges will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws and other factors. The amounts involved in any such transaction may be material. 
+In 2010 we paid $6.3 million in dividends to our stockholders. Our current intention is to continue to make dividend payments for the foreseeable future, subject to our future earnings, our financial condition, possible credit facility, and other covenants, and other currently unexpected factors which could arise. Payment of future dividends remains at the discretion of the Board of Directors, and will continue to depend on our earnings, capital requirements, financial condition, and other factors. 
+As of the filing date of this report, we have authorization from our Board of Directors to repurchase up to 3,072,184 shares of our common stock under our stock repurchase program. Shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility and the indenture governing our 6.625% Senior Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. There were no share repurchases in 2010. 
+Current proposals to fund the federal government budget include eliminating or reducing current tax deductions for intangible drilling costs, the domestic production activities deduction, and percentage depletion. Legislation modifying or eliminating these deductions would have the immediate effect of reducing operating cash flows thereby reducing funding available for our exploration and development capital programs and those of our peers in the industry. These funding reductions could have a significant adverse effect on drilling in the United States for a number of years. 
+The following table presents amounts and percentage changes between years in net cash flows from our operating, investing, and financing activities. The analysis following the table should be read in conjunction with our consolidated statements of cash flows in Part IV, Item 15 of this report. 
+Amount of Changes Between 
+Percent of Change Between 
+2010/2009 
+2009/2008 
+2010/2009 
+2009/2008 
+Change in net cash provided by operating activities 
+$ 
+60,991 
+$ 
+(243,084 
+) 
+14 
+% 
+(36 
+)% 
+Change in net cash used in investing activities 
+$ 
+(57,481 
+) 
+$ 
+369,662 
+19 
+% 
+(55 
+)% 
+Change in net cash used in financing activities 
+$ 
+(13,600 
+) 
+$ 
+(84,681 
+) 
+11 
+% 
+198 
+% 
+Analysis of cash flow changes between 2010 and 2009 
+Operating activities. Cash received from oil and gas production revenues, net of the realized effects of hedging, increased $84.6 million to $836.4 million for the year ended December 31, 2010. The increase was the result of a one percent increase in production and a 13 percent increase in our net realized price after hedging, resulting in a 14 percent increase in production revenue. Included in the 2010 oil and gas production revenue amounts is $23.5 million of net realized hedging gains. Additionally, cash paid for lease operating expenses decreased $29.2 million. We received $25.6 million in income tax refunds in 2010 compared to $9.9 million received during 2009. 
+Investing activities. Cash used for investing activities was $361.6 million for the year ended December 31, 2010, compared with $304.1 million for the same period in 2009. We received proceeds of $311.5 million primarily from the sale of non-strategic properties located in our Rocky Mountain and Permian regions, as discussed under 2010 Highlights above. The $39.9 million proceeds from the sale of oil and gas properties received in 2009 related primarily to the sale of non-strategic properties located in the Rocky Mountain region that were divested of in the fourth quarter of 2009. Cash outflows for 2010 capital expenditures increased 
+72 
+Table of Contents 
+$289.0 million, or 76 percent, to $668.3 million. This is due to increased drilling activity as a result of more favorable commodity prices, an improved overall macro-economic environment, and our drilling efforts in our Eagle Ford shale play. We received $16.8 million in proceeds from an insurance settlement relating to Hurricane Ike for the year ended December 31, 2009. There were no insurance proceeds received in 2010. 
+Financing activities. Net repayments to our credit facility increased $28.0 million for the year ended December 31, 2010, compared to 2009. We spent $11.1 million on debt issuance costs for our amended credit facility during the year ended December 31, 2009. We did not incur any debt issuance costs in 2010. We received $3.3 million more in proceeds from the sale of common stock in 2010, than in 2009. 
+We had $5.1 million in cash and cash equivalents and a working capital deficit of $227.4 million as of December 31, 2010, compared to $10.6 million in cash and cash equivalents and working capital deficit of $87.6 million as of December 31, 2009. 
+Analysis of cash flow changes between 2009 and 2008 
+Operating activities. Cash received from oil and gas production revenues, net of the realized effects of hedging, decreased $438.5 million to $751.8 million for the year ended December 31, 2009. The decrease was the result of a five percent decrease in production and a 31 percent decrease in our net realized price after hedging, resulting in a 35 percent decrease in production revenue. Included in the 2009 oil and gas production revenue amounts was $140.6 million of net realized hedging gains. We received $9.9 million in income tax refunds in 2009 compared to payments of $17.3 million during 2008. 
+Investing activities. Cash used for investing activities decreased $369.7 million for the year ended December 31, 2009, compared with the same period in 2008. Cash outflows for 2009 capital expenditures for development and exploration activities decreased $367.3 million or 49 percent to $379.3 million, which reflected a reduced level of activity as a result of lower commodity prices. Total cash outflow for 2009 related to the acquisition of oil and gas properties decreased $81.7 million or 100 percent to $76,000. We had no significant acquisitions of oil and gas properties in 2009, compared with the acquisition of Carthage Field properties during 2008. Proceeds from an insurance settlement relating to Hurricane Ike were $16.8 million for the year ended December 31, 2009, compared with the same period in 2008 when we received no proceeds from insurance settlements. Proceeds from the sale of oil and gas properties for the year ended December 31, 2009, decreased $139.0 million compared to the same period in 2008. Proceeds received in 2009 from the sale of oil and gas properties related to non-strategic properties located in the Rocky Mountain region that were divested of in the fourth quarter of 2009. The majority of the 2008 proceeds related to non-strategic properties sold in the first quarter of 2008. 
+Financing activities. Net repayments to our credit facility increased $127.0 million for the year ended December 31, 2009, compared to 2008. We spent $11.1 million on debt issuance costs for our amended credit facility during the year ended December 31, 2009. We did not incur any debt issuance costs during 2008. Our excess income tax benefit attributable to the exercise of stock awards decreased $13.9 million in the year ended December 31, 2009, compared with 2008. We received $8.8 million less in proceeds from the sale of common stock in 2009, than in 2008. Additionally, we invested $77.2 million less to repurchase shares of our common stock during 2009, than in 2008. 
+We had $10.6 million in cash and cash equivalents and a working capital deficit of $87.6 million as of December 31, 2009, compared to $6.1 million in cash and cash equivalents and working capital of $15.2 million as of December 31, 2008. 
+Commodity Price Risk and Interest Rate Risk 
+We are exposed to market risk, including the effects of changes in oil and gas commodity prices and changes in interest rates. Changes in interest rates can affect the amount of interest we earn on our cash, cash equivalents, and short-term investments and the amount of interest we pay on borrowings under our revolving 
+73 
+Table of Contents 
+credit facility. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate 3.50% Senior Convertible Notes, but do affect their fair market value. 
+Market risk is estimated as the potential change in fair value resulting from an immediate hypothetical one percentage point parallel shift in the yield curve. For fixed-rate debt, interest changes affect the fair market value but do not impact results of operations or cash flows. Conversely, interest rate changes for floating-rate debt generally do not affect the fair market value but do impact future results of operations and cash flows, assuming other factors are held constant. The carrying amount of our floating-rate debt typically approximates its fair value. We had $48.0 million of floating-rate debt outstanding as of December 31, 2010. Our fixed-rate debt outstanding, net of debt discount, at this same date was $275.7 million. As of December 31, 2010, we do not have any interest rate hedges in place to mitigate potential interest rate risks. 
+Since we produce and sell natural gas and crude oil, our financial results are affected when prices for these commodities fluctuate. The following table reflects our estimate of the effect on net cash flows from operations of a ten percent change in our average realized sales price for natural gas, for oil, and in combination for the years presented, inclusive of the impact of hedging. These amounts have been reduced by the effective income tax rate applicable to each period since a reduction in revenue would reduce cash requirements to pay income taxes. General and administrative expenses have not been adjusted. To fund the capital expenditures we incurred in those years we would have been required to utilize amounts under our credit facility as a source of funds. In each of these years we would have had sufficient unused borrowing capacity available under our credit facility to meet this contingency without reducing or eliminating expenditures or altering our growth strategy. 
+Pro forma effect on net cash flow from operations of a ten percent decrease in average realized sales price: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Oil 
+$ 
+48,710 
+$ 
+29,523 
+$ 
+27,818 
+Natural Gas 
+30,455 
+11,874 
+37,288 
+Total 
+$ 
+79,165 
+$ 
+41,397 
+$ 
+65,106 
+We enter into hedging transactions in order to reduce the impact of fluctuations in commodity prices. Please refer to Note 10—Derivative Financial Instruments of Part IV, Item 15 of this report for additional information about our oil and gas derivative contracts, and additional information is below under the caption Summary of Oil and Gas Production Hedges in Place. We do not anticipate significant changes in existing hedge contracts or derivative contract transactions. 
+Summary of Oil and Gas Production Hedges in Place 
+Our oil and natural gas derivative contracts include swap and costless collar arrangements. All contracts are entered into for other-than-trading purposes. Please refer to Note 10 — Derivative Financial Instruments in Part IV, Item 15 of this report for additional information regarding accounting for our derivative transactions. Our net realized oil and gas prices are impacted by hedges we have placed on future forecasted production. Hedging is an important part of our financial risk management program. The amount of production we hedge is driven by the amount of debt on our consolidated balance sheet and the level of capital and long-term commitments we have made. In the case of a significant acquisition of producing properties, we will consider hedging a portion of the anticipated production in order to protect the economics assumed at the time of the acquisition. As of December 31, 2010, our hedged positions of anticipated production through the third quarter of 2013 totaled approximately 6 million Bbls of oil, 35 million MMBtu of natural gas, and 2 million Bbls of NGLs. As of February 18, 2011, the Company had hedge contracts in place through the fourth quarter of 2013 for a total of approximately 9 million Bbls of anticipated crude oil production, 44 million MMBtu of anticipated natural gas production, and 2 million Bbls of anticipated NGL production. 
+74 
+Table of Contents 
+In a typical commodity swap agreement, if the agreed-upon published third-party index price is lower than the swap fixed price, we receive the difference between the index price per unit of production and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, we pay the difference. For collar agreements, we receive the difference between an agreed upon index and the floor price if the index price is below the floor price. We pay the difference between the agreed upon contracted ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the contracted floor and ceiling prices. 
+The following table describes the volumes, average contract prices, and fair value of contracts we have in place as of December 31, 2010. We seek to minimize basis risk and index the majority of our oil contracts to NYMEX WTI prices and the majority of our gas contracts to various regional index prices associated with pipelines in proximity to our areas of gas production. 
+Oil contracts 
+Oil Swaps: 
+Contract Period 
+Volumes 
+Weighted-Average Contract Price 
+Fair Value at December 31, 2010 Liability 
+(Bbls) 
+(per Bbl) 
+(in thousands) 
+First quarter 2011 
+418,000 
+$ 
+70.36 
+$ 
+9,170 
+Second quarter 2011 
+367,800 
+$ 
+69.49 
+8,901 
+Third quarter 2011 
+327,800 
+$ 
+68.63 
+8,354 
+Fourth quarter 2011 
+325,400 
+$ 
+73.51 
+6,738 
+2012 
+1,514,200 
+$ 
+82.62 
+16,696 
+2013 
+294,600 
+$ 
+84.30 
+2,473 
+All oil swap contracts 
+3,247,800 
+$ 
+52,332 
+Oil Collars: 
+Contract Period 
+NYMEX WTI Volumes 
+Weighted-Average Floor Price 
+Weighted-Average Ceiling Price 
+Fair Value at December 31, 2010 Liability 
+(Bbls) 
+(per Bbl) 
+(per Bbl) 
+(in thousands) 
+First quarter 2011 
+305,250 
+$ 
+50.00 
+$ 
+63.70 
+$ 
+8,735 
+Second quarter 2011 
+308,250 
+$ 
+50.00 
+$ 
+63.70 
+9,334 
+Third quarter 2011 
+311,250 
+$ 
+50.00 
+$ 
+63.70 
+9,686 
+Fourth quarter 2011 
+311,250 
+$ 
+50.00 
+$ 
+63.70 
+9,783 
+2012 
+667,500 
+$ 
+72.45 
+$ 
+103.35 
+2,402 
+2013 
+1,176,300 
+$ 
+72.40 
+$ 
+103.55 
+4,431 
+All oil collars 
+3,079,800 
+$ 
+44,371 
+75 
+Table of Contents 
+Gas Contracts 
+Gas Swaps: 
+Contract Period 
+Volumes 
+Weighted-Average Contract Price 
+Fair Value at December 31, 2010 Asset 
+(MMBtu) 
+(per MMBtu) 
+(in thousands) 
+First quarter 2011 
+IF ANR OK 
+110,000 
+$ 
+6.56 
+$ 
+266 
+IF CIG 
+180,000 
+$ 
+6.38 
+417 
+IF El Paso 
+610,000 
+$ 
+6.93 
+1,738 
+IF HSC 
+360,000 
+$ 
+9.01 
+1,730 
+IF NGPL 
+260,000 
+$ 
+6.39 
+583 
+IF NNG Ventura 
+290,000 
+$ 
+6.77 
+691 
+IF PEPL 
+510,000 
+$ 
+6.44 
+1,182 
+IF Reliant 
+1,140,000 
+$ 
+6.36 
+2,528 
+IF TETCO STX 
+450,000 
+$ 
+6.97 
+1,238 
+NYMEX Henry Hub 
+510,000 
+$ 
+7.11 
+1,409 
+Second quarter 2011 
+IF ANR OK 
+110,000 
+$ 
+5.74 
+173 
+IF CIG 
+210,000 
+$ 
+5.54 
+333 
+IF El Paso 
+520,000 
+$ 
+5.99 
+976 
+IF NGPL 
+220,000 
+$ 
+5.65 
+327 
+IF NNG Ventura 
+280,000 
+$ 
+6.02 
+477 
+IF PEPL 
+450,000 
+$ 
+5.59 
+655 
+IF Reliant 
+1,070,000 
+$ 
+5.63 
+1,529 
+IF TETCO STX 
+420,000 
+$ 
+6.52 
+926 
+NYMEX Henry Hub 
+810,000 
+$ 
+6.41 
+1,593 
+Third quarter 2011 
+IF ANR OK 
+140,000 
+$ 
+5.92 
+227 
+IF CIG 
+340,000 
+$ 
+5.81 
+575 
+IF El Paso 
+330,000 
+$ 
+6.08 
+577 
+IF NGPL 
+290,000 
+$ 
+5.93 
+476 
+IF NNG Ventura 
+340,000 
+$ 
+6.14 
+597 
+IF PEPL 
+500,000 
+$ 
+5.90 
+806 
+IF Reliant 
+1,170,000 
+$ 
+6.06 
+2,052 
+IF TETCO STX 
+280,000 
+$ 
+5.96 
+421 
+NYMEX Henry Hub 
+390,000 
+$ 
+6.59 
+783 
+Fourth quarter 2011 
+IF ANR OK 
+140,000 
+$ 
+6.21 
+223 
+IF CIG 
+300,000 
+$ 
+6.19 
+509 
+IF El Paso 
+320,000 
+$ 
+6.10 
+492 
+IF NGPL 
+270,000 
+$ 
+6.31 
+464 
+IF NNG Ventura 
+290,000 
+$ 
+6.53 
+499 
+IF PEPL 
+370,000 
+$ 
+6.23 
+645 
+IF Reliant 
+1,130,000 
+$ 
+6.42 
+2,069 
+IF TETCO STX 
+270,000 
+$ 
+6.31 
+426 
+NYMEX Henry Hub 
+420,000 
+$ 
+6.98 
+882 
+76 
+Table of Contents 
+Gas Swaps (continued) 
+Contract Period 
+Volumes 
+Weighted-Average Contract Price 
+Fair Value at December 31, 2010 Asset 
+(MMBtu) 
+(per MMBtu) 
+(in thousands) 
+2012 
+IF ANR OK 
+360,000 
+$ 
+6.18 
+517 
+IF CIG 
+1,020,000 
+$ 
+5.77 
+1,077 
+IF El Paso 
+850,000 
+$ 
+6.04 
+1,047 
+IF NGPL 
+660,000 
+$ 
+6.34 
+1,043 
+IF NNG Ventura 
+620,000 
+$ 
+6.51 
+909 
+IF PEPL 
+2,730,000 
+$ 
+6.25 
+4,136 
+IF Reliant 
+3,540,000 
+$ 
+5.97 
+3,912 
+IF TETCO STX 
+660,000 
+$ 
+6.30 
+880 
+2013 
+IF PEPL 
+1,250,000 
+$ 
+5.65 
+482 
+IF Reliant 
+1,290,000 
+$ 
+5.64 
+489 
+All gas swap contracts 
+28,780,000 
+$ 
+45,986 
+77 
+Table of Contents 
+Gas Collars: 
+Contract Period 
+Volumes 
+Weighted- Average Floor Price 
+Weighted- Average Ceiling Price 
+Fair Value at December 31, 2010 Asset 
+(MMBtu) 
+(per MMBtu) 
+(per MMBtu) 
+(in thousands) 
+First quarter 2011 
+IF CIG 
+450,000 
+$ 
+5.00 
+$ 
+6.32 
+$ 
+457 
+IF HSC 
+120,000 
+$ 
+5.57 
+$ 
+6.77 
+160 
+IF PEPL 
+1,050,000 
+$ 
+5.31 
+$ 
+6.51 
+1,264 
+NYMEX Henry Hub 
+30,000 
+$ 
+6.00 
+$ 
+7.25 
+51 
+Second quarter 2011 
+IF CIG 
+450,000 
+$ 
+5.00 
+$ 
+6.32 
+497 
+IF HSC 
+120,000 
+$ 
+5.57 
+$ 
+6.77 
+148 
+IF PEPL 
+1,055,000 
+$ 
+5.31 
+$ 
+6.51 
+1,296 
+NYMEX Henry Hub 
+30,000 
+$ 
+6.00 
+$ 
+7.25 
+48 
+Third quarter 2011 
+IF CIG 
+450,000 
+$ 
+5.00 
+$ 
+6.32 
+457 
+IF HSC 
+120,000 
+$ 
+5.57 
+$ 
+6.77 
+141 
+IF PEPL 
+1,060,000 
+$ 
+5.31 
+$ 
+6.51 
+1,203 
+NYMEX Henry Hub 
+30,000 
+$ 
+6.00 
+$ 
+7.25 
+45 
+Fourth quarter 2011 
+IF CIG 
+450,000 
+$ 
+5.00 
+$ 
+6.32 
+346 
+IF HSC 
+120,000 
+$ 
+5.57 
+$ 
+6.77 
+119 
+IF PEPL 
+1,060,000 
+$ 
+5.31 
+$ 
+6.51 
+1,039 
+NYMEX Henry Hub 
+30,000 
+$ 
+6.00 
+$ 
+7.25 
+38 
+All gas collars 
+6,625,000 
+$ 
+7,309 
+78 
+Table of Contents 
+Natural Gas Liquid Contracts 
+Natural Gas Liquid Swaps: 
+Volumes 
+Weighted-Average Contract Price 
+Fair Value at December 31, 2010 Liability 
+(approx. Bbls) 
+(per Bbl) 
+(in thousands) 
+First quarter 2011 
+331,000 
+$ 
+40.34 
+$ 
+2,537 
+Second quarter 2011 
+302,000 
+$ 
+39.43 
+1,607 
+Third quarter 2011 
+279,000 
+$ 
+39.51 
+1,270 
+Fourth quarter 2011 
+260,000 
+$ 
+39.55 
+1,241 
+2012 
+642,000 
+$ 
+38.47 
+1,919 
+2013 
+84,000 
+$ 
+44.95 
+287 
+All natural gas liquid swaps* 
+1,898,000 
+$ 
+8,861 
+*Natural gas liquid swaps are comprised of OPIS Mont. Belvieu LDH Propane (28%), OPIS Mont. Belvieu Purity Ethane (46%), OPIS Mont. Belvieu NON-LDH Isobutane (4%), OPIS Mont. Belvieu NON-LDH Natural Gasoline (12%), and OPIS Mont. Belvieu NON-LDH Normal Butane (10%). 
+79 
+Table of Contents 
+Hedge Contracts Entered into After December 31, 2010 
+The following tables include all hedges entered into subsequent to December 31, 2010 through February 18, 2011: 
+Oil Collars: 
+Contract Period 
+NYMEX WTI Volumes 
+Weighted- Average Floor Price 
+Weighted- Average Ceiling Price 
+(Bbls) 
+(per Bbl) 
+(per Bbl) 
+Second Quarter 2011 
+318,800 
+$ 
+80.00 
+$ 
+109.30 
+Third Quarter 2011 
+265,500 
+$ 
+80.00 
+$ 
+109.30 
+Fourth Quarter 2011 
+203,600 
+$ 
+80.00 
+$ 
+109.30 
+2012 
+767,100 
+$ 
+80.00 
+$ 
+115.40 
+2013 
+970,200 
+$ 
+80.00 
+$ 
+117.40 
+All oil collars 
+2,525,200 
+Gas Swaps: 
+Contract Period 
+Volumes 
+Weighted- Average Contract Price 
+(MMBtu) 
+(per MMBtu) 
+Fourth Quarter 2011 
+IF HSC 
+529,000 
+$ 
+4.56 
+IF TETCO STX 
+691,000 
+$ 
+4.24 
+2012 
+IF HSC 
+1,871,000 
+$ 
+4.56 
+IF TETCO STX 
+2,289,000 
+$ 
+4.54 
+2013 
+IF TETCO STX 
+3,220,000 
+$ 
+4.88 
+All gas swap contracts 
+8,600,000 
+Please see Note 10—Derivative Financial Instruments in Part IV, Item 15 of this report for additional information regarding our oil and gas hedges. 
+Schedule of Contractual Obligations 
+The following table summarizes our future estimated principal payments and minimum lease payments for the periods specified (in millions): 
+Contractual Obligations 
+Total 
+Less than 1 year 
+1-3 years 
+3-5 years 
+More than 
+5 years 
+Long-term debt 
+$ 
+348.1 
+$ 
+10.1 
+$ 
+338.0 
+$ 
+— 
+$ 
+— 
+Derivative liability 
+115.7 
+82.5 
+33.2 
+— 
+— 
+Net Profits Plan 
+133.8 
+22.1 
+46.6 
+43.8 
+21.3 
+Delivery commitments 
+181.1 
+4.8 
+33.8 
+41.6 
+100.9 
+Operating leases and contracts 
+227.2 
+101.9 
+82.7 
+23.9 
+18.7 
+Other 
+15.2 
+5.0 
+9.6 
+0.2 
+0.4 
+Total 
+$ 
+1,021.1 
+$ 
+226.4 
+$ 
+543.9 
+$ 
+109.5 
+$ 
+141.3 
+This table includes the remaining unfunded portion of our estimated pension liability of $13.5 million even though we recognize that we cannot accurately determine the timing of future payments. We are required to make a contribution to the Pension Plan in 2011 of $4.4 million. We made contributions of $1.7 million and $2.0 million in 2010 and 2009, respectively, towards our pension liability. The table also includes $133.8 million in other long-term liabilities that represents six years of undiscounted forecasted payments for the Net Profits Plan. Payments are expected to gradually decrease for the years beyond what is shown in this table. The amounts recorded on the consolidated balance sheets reflect all future Net Profits Plan payments and the impact of discounting and therefore differ from the amounts disclosed in this table. The variability in the amount of payments will be a direct reflection of commodity prices, production rates, capital expenditures, and operating costs in future periods. Predicting the timing and amounts of payments associated with this liability is contingent upon estimates of appropriate discount factors, adjusting for risk and time value, and upon a number of factors that we cannot control. The components of the operating leases are discussed in more detail in Note 6—Commitments and Contingencies of Part IV, Item 15 of this report. 
+The actual payments under our revolving credit facility will vary significantly. Our credit facility has a maturity date of July 31, 2012, and therefore for purposes of this table, the December 31, 2010, balance under our credit facility has been disclosed in the table under the heading 1-3 years. For purposes of this table, we have assumed we will net share settle the 3.50% Senior Convertible Notes in 2012. Accordingly, $12.6 million of interest payments related to the 3.50% Senior Convertible Notes are included in the long-term debt line in table above. We have excluded asset retirement obligations because we are not able to accurately predict the precise timing of these amounts. Pension liabilities, asset retirement obligations, and Net Profits Plan are discussed in Note 8—Pension Benefits, Note 9—Asset Retirement Obligations, and Note 7—Compensation Plans of Part IV, Item 15 of this report. 
+This table also includes estimated oil and natural gas derivative payments of $115.7 million based on future market prices as of December 31, 2010. This amount represents only the cash outflows; it does not include estimated oil and gas derivative receipts of $62.7 million that would be paid based on December 31, 2010, market prices. The net liability of $53.0 million represents cash flows from the intrinsic value of our collar arrangements and differs in amount from our recorded fair value, which as of December 31, 2010, was a net liability of $52.3 million. The fair value considers time value, volatility, and the risk of non-performance for us and for our counterparties. Both the intrinsic value and fair value will change as oil and natural gas commodity prices 
+80 
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+change. Please refer to the discussion above under the caption Summary of Oil and Gas Production Hedges in Place and Note 10—Derivative Financial Instruments in Part IV, Item 15 of this report for additional information regarding our oil and gas hedges. 
+We believe that we will continue to pay annual dividends of $0.10 per share. We anticipate making cash payments for income taxes, dependent on net income and capital spending; however, payment of future dividends remains at the discretion of the Board of Directors, and will continue to depend on our earnings, capital requirements, financial condition, and other factors. 
+Subsequent to year end, we issued $350.0 million in aggregate principal amount of 6.625% Senior Notes. The 6.625% Senior Notes mature on February 15, 2019, and we will make annual interest payments of $23.2 million. Additionally, subsequent to year end we entered into a hydraulic fracturing services contract. The total commitment is $180.0 million over a two year term; provided however, our liability upon early termination of this contract may not exceed $24 million. These obligations are not reflected in the amounts above. 
+Off-balance Sheet Arrangements 
+As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of December 31, 2010, we have not been involved in any unconsolidated SPE transactions. 
+We evaluate our transactions to determine if any variable interest entities exist. If it is determined that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. 
+Critical Accounting Policies and Estimates 
+Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our decisions affecting the estimates we use on historical experience and various other sources that are believed to be reasonable under the circumstances. Actual results may differ from the estimates we calculate due to changes in business conditions or due to unexpected circumstances. Policies we believe are critical to understanding our business operations and results of operations are detailed below. For additional information on our significant accounting policies, please refer to Note 1 — Summary of Significant Accounting Policies, Note 9—Asset Retirement Obligations, and Note 15—Disclosures about Oil and Gas Producing Activities in Part IV, Item 15 of this report. 
+Proved oil and gas reserve quantities. Estimated reserve quantities and the related estimates of future net cash flows are critical estimates for our company because they affect the perceived value of an exploration and production company. Additionally, they are used in comparative financial analysis ratios and are used as the basis for the most significant accounting estimates in our financial statements. Those significant accounting estimates include the periodic calculations of depletion, depreciation, and impairment of our proved oil and gas properties and the estimates of our liability for future payments under the Net Profits Plan. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to the estimated quantities of proved oil and gas reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used. For example, the standardized measure calculations require a ten percent discount rate to be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves, including using independent reserve engineering consultants. We expect that periodic reserve 
+81 
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+estimates will change in the future as additional information becomes available and as oil and gas prices and operating and capital costs change. We evaluate and estimate our proved oil and gas reserves at December 31 and June 30 of each year. For purposes of depletion, depreciation, and impairment, reserve quantities are adjusted at all interim periods for the estimated impact of additions and dispositions. Changes in depletion, depreciation, or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period the reserve estimates change. 
+The following table presents information regarding reserve changes from period to period that reflect changes from items we do not control, such as price, and from changes resulting from better information due to production history, and from well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves. 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+BCFE 
+BCFE 
+BCFE 
+Change 
+Change 
+Change 
+Revisions resulting from price changes 
+42.6 
+12.0 
+(199.7 
+) 
+Revisions resulting from performance 
+(17.9 
+) 
+(61.6 
+) 
+(44.5 
+) 
+Total 
+24.7 
+(49.6 
+) 
+(244.2 
+) 
+We have added 424.1 BCFE of reserves over a three-year period, excluding divestitures. A 124.0 BCFE decrease in reserves was a result of changes in engineering estimates based on the performance of our oil and gas properties. A 145.1 BCFE decrease in reserves was a result of price changes. As previously noted, oil and gas prices are volatile, and estimates of reserves are inherently imprecise. Consequently, we anticipate we may continue to experience these types of changes. 
+The following table reflects the estimated BCFE change and percentage change to our total reported reserve volumes from the described hypothetical changes: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+BCFE 
+Percentage 
+BCFE 
+Percentage 
+BCFE 
+Percentage 
+Change 
+Change 
+Change 
+Change 
+Change 
+Change 
+A 10% decrease in pricing 
+(13.9 
+) 
+(1 
+)% 
+(25.1 
+) 
+(3 
+)% 
+(120.8 
+) 
+(14 
+)% 
+A 10% decrease in proved undeveloped reserves 
+(29.7 
+) 
+(3 
+)% 
+(14.2 
+) 
+(2 
+)% 
+(15.0 
+) 
+(2 
+)% 
+Additional reserve information can be found in the reserve table and discussion included in Items 1 and 2 of Part I of this report. 
+Successful efforts method of accounting. Generally accepted accounting principles provide for two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method. Both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities, and a detailed description is included in Note 1 of Part IV, Item 15 of this report. 
+Revenue recognition. Our revenue recognition policy is significant because revenue is a key component of our results of operations and our forward-looking statements contained in our analysis of liquidity and capital resources. We derive our revenue primarily from the sale of produced natural gas, natural gas liquids, and crude oil. We report revenue as the gross amounts we receive before taking into account production taxes and 
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+transportation costs, which are reported as separate expenses. Revenue is recorded in the month our production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a purchaser. At the end of each month we make estimates of the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our properties, their historical performance, NYMEX and local spot market prices, and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are recorded in the month payment is received. A ten percent change in our year end revenue accrual would have impacted net income before tax by approximately $10.8 million in 2010. 
+Crude oil and natural gas hedging. Through December 31, 2010, our crude oil and natural gas hedging contracts were intended to and usually did qualify for cash flow deferral hedge accounting. Under this guidance a majority of the gain or loss from a contract qualified as a cash flow hedge was deferred from recognition in the consolidated statement of operations. The realized gain or loss reflected in the consolidated statement of operations was based on actual hedge contract settlements. Effective January 1, 2011, we elected to de-designate all of our commodity hedges that had previously been designated as cash flow hedges as of December 31, 2010. We also elected to discontinue hedge accounting prospectively. As a result, our periodic consolidated statements of operations could include significant changes in the estimate of non-cash derivative gain or loss due to swings in the value of these contracts. Consequently, we would report a different amount of oil and gas hedge loss in our statements of operations. These fluctuations could be especially significant in a volatile pricing environment such as what we have encountered over the last few years. The amounts recorded to accumulated other comprehensive income (loss) of $23.5 million of income, $103.3 million of loss, and $223.5 million of income for 2010, 2009, and 2008, respectively, would have increased or decreased net income after tax if our hedges did not qualify as cash flow hedges. 
+Change in Net Profits Plan Liability. We record the estimated liability of future payments for our Net Profits Plan. The estimated liability is calculated based on a number of assumptions, including estimates of proved oil and gas reserves, recurring and workover lease operating expense, production and ad valorem tax rates, present value discount factors, and pricing assumptions. Additional discussion is included in the analysis in the above section titled 2010 Highlights under the heading Net Profits Plan. In 2008 the Net Profits Plan was replaced with a long-term equity incentive program. As a result, the 2007 Net Profits Plan pool was the last pool established. 
+Asset retirement obligations. We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells projected into the future based on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates, and determine what credit adjusted risk-free rate discount to use. The impact to the consolidated statement of operations from these estimates is reflected in our depreciation, depletion, and amortization calculations and occurs over the remaining life of our respective oil and gas properties. 
+Valuation of long-lived and intangible assets. Our property and equipment are recorded at cost. An impairment allowance is provided on unproven property when we determine that the property will not be developed or the carrying value will not be realized. We evaluate the realizability of our proved properties and other long-lived assets whenever events or changes in circumstances indicate that impairment may be appropriate. Our impairment test compares the expected undiscounted future net revenues from property, using escalated pricing, with the related net capitalized cost of the property at the end of each period. When the net capitalized costs exceed the undiscounted future net revenue of a property, the cost of the property is written down to its estimate of fair value, which is determined by applying a discount rate we believe is indicative of the current market. Our criteria for an acceptable internal rate of return are subject to change over time. Different pricing assumptions or discount rates could result in a different calculated impairment. We recorded a $6.1 million impairment of proved oil and gas properties in 2010, compared with $174.8 million impairment of proved oil and gas properties in 2009. A significant decrease in commodity prices and increase in differentials during the first quarter of 2009 caused the majority of the non-cash impairment. The largest portion of the impairment in 2009 
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+was $97.3 million related to assets located in the Mid-Continent region that were significantly impacted by lower prices and wider than normal differentials. 
+Income taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not. Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared, therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations. A one percent change in our effective tax rate would have changed our calculated income tax expense by $3.1 million for the year ended December 31, 2010. 
+Accounting Matters 
+Please refer to the section entitled Recently Issued Accounting Standards under Note 1—Summary of Significant Accounting Policies for additional information on the recent adoption of new authoritative accounting guidance in Part IV, Item 15 of this report. 
+Environmental 
+SM Energy’s compliance with applicable environmental laws and regulations has to date not resulted in significant capital expenditures or material adverse effects on our liquidity or results of operations. We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes and we are unable to predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital expenditures, liquidity, and results of operations. 
+Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. For additional information about hydraulic fracturing and related environmental matters, see “Risk Factors—Risks Related to Our Business—Proposed federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” 
+Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other ‘‘greenhouse gases’’ present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011. 
+In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work 
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+by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. 
+The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. 
+In terms of opportunities, the regulation of greenhouse gas emissions and the introduction of alternative incentives, such as enhanced oil recovery, carbon sequestration and low carbon fuel standards, could benefit us in a variety of ways. For example, although climate change legislation could reduce the overall demand for the oil and natural gas that we produce, the relative demand for natural gas may increase since the burning of natural gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources, such as wind or solar power become more prevalent, natural gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel standards, natural gas may become a more attractive transportation fuel. In both 2009 and 2010, approximately 65 percent of our production was natural gas on an MCFE basis. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and natural gas reservoirs, could also benefit us through the potential to obtain greenhouse gas emission allowances or offsets from or government incentives for the sequestration of carbon dioxide. 
+ITEM 7A . 
+QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+The information required by this item is provided under the captions “ Commodity Price Risk and Interest Rate Risk ” and “ Summary of Oil and Gas Production Hedges in Place ” in Item 7 above and is incorporated herein by reference. 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The Consolidated Financial Statements that constitute Item 8 follow the text of this report. An index to the Consolidated Financial Statements and Schedules appears in Item 15(a) of this report. 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+None. 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+We maintain a system of disclosure controls and procedures that are designed to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. 
+85 
+Table of Contents 
+We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures are effective for the purpose discussed above as of the end of the period covered by this Annual Report on Form 10-K. There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 
+86 
+Table of Contents 
+MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 
+To the Stockholders’ of SM Energy Company 
+Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that: 
+(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements. 
+Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. 
+Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework. 
+Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2010. 
+The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal controls over financial reporting. That report immediately follows this report. 
+/s/ ANTHONY J. BEST 
+/s/ A. WADE PURSELL 
+Anthony J. Best 
+A. Wade Pursell 
+President and Chief Executive Officer 
+Executive Vice President and Chief Financial Officer 
+February 25, 2011 
+February 25, 2011 
+87 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Board of Directors and Stockholders of 
+SM Energy Company and Subsidiaries 
+Denver, Colorado 
+We have audited the internal control over financial reporting of SM Energy Company and subsidiaries (the “Company”) as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2010, of the Company and our report dated February 25, 2011, expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company’s adoption of new accounting guidance. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 25, 2011 
+88 
+Table of Contents 
+ITEM 9B. 
+OTHER INFORMATION 
+None. 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE 
+The information required by this Item concerning SM Energy’s Directors and corporate governance is incorporated by reference to the information provided under the captions “Structure of the Board of Directors,” “Proposal 1—Election of Directors,” and “Corporate Governance” in SM Energy’s definitive proxy statement for the 2011 annual meeting of stockholders to be filed within 120 days from December 31, 2010. The information required by the Item concerning SM Energy’s executive officers is incorporated by reference to the information provided in Part I—EXECUTIVE OFFICERS OF THE REGISTRANT, included in this Form 10-K. 
+The information required by this Item concerning compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated by reference to the information provided under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in SM Energy’s definitive proxy statement for the 2011 annual meeting of stockholders to be filed within 120 days from December 31, 2010. 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+The information required by this Item is incorporated by reference to the information provided under the captions, “Executive Compensation” and “Director Compensation” in SM Energy’s definitive proxy statement for the 2011 annual meeting of stockholders to be filed within 120 days from December 31, 2010. 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The information required by this Item concerning security ownership of certain beneficial owners and management is incorporated by reference to the information provided under the caption “Security Ownership of Certain Beneficial Owners and Management” in SM Energy’s definitive proxy statement for the 2011 annual meeting of stockholders to be filed within 120 days from December 31, 2010. 
+The information required by this Item concerning securities authorized for issuance under equity compensation plans is incorporated by reference to the information provided under the caption “Equity Compensation Plans” in Part II, Item 5—Market for Registrant’s Common Equity, Related Stockholder Matter and Issuer Purchases of Equity Securities, included in this report. 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+The information required by this Item is incorporated by reference to the information provided under the caption “Certain Relationships and Related Transactions,” and “Corporate Governance,” in SM Energy’s definitive proxy statement for the 2011 annual meeting of stockholders to be filed within 120 days from December 31, 2010. 
+89 
+Table of Contents 
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+The information required by this Item is incorporated by reference to the information provided under the caption “Independent Accountants” and “Audit Committee Preapproval Policy and Procedures” in SM Energy’s definitive proxy statement for the 2011 annual meeting of stockholders to be filed within 120 days from December 31, 2010. 
+PART IV 
+ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
+(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules: 
+Report of Independent Registered Public Accounting Firm 
+F-1 
+Consolidated Balance Sheets 
+F-2 
+Consolidated Statements of Operations 
+F-3 
+Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) 
+F-4 
+Consolidated Statements of Cash Flows 
+F-5 
+Notes to Consolidated Financial Statements 
+F-7 
+All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto. 
+(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K: 
+Exhibit Number 
+Description 
+2.1 
+Purchase and Sale Agreement dated December 11, 2007, among St. Mary Land & Exploration Company, Ralph H. Smith Restated Revocable Trust Dated 8/14/97, Ralph H. Smith Trustee, Kent. J. Harrell, Trustee of the Kent J. Harrell Revocable Trust Dated January 19, 1995, and Abraxas Operating LLC (filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed on February 1, 2008, and incorporated herein by reference) 
+2.2 
+Ratification and Joinder Agreement dated January 31, 2008, among St. Mary Land & Exploration Company, Ralph H. Smith, Kent J. Harrell, Abraxas Operating, LLC and Abraxas Petroleum Corporation (filed as Exhibit 2.2 to the registrant’s Current Report on Form 8-K filed on February 1, 2008, and incorporated herein by reference) 
+2.3 
+Purchase and Sale Agreement dated December 17, 2009 and effective as of November 1, 2009, between Legacy Reserves Operating LP and St. Mary Land & Exploration Company (filed as Exhibit 2.5 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference) 
+2.4 
+Purchase and Sale Agreement dated January 7, 2010 and effective as of November 1, 2009, between Sequel Energy Partners LP, Bakken Energy Partners, LLC, Three Forks Energy Partners, LLC and St. Mary Land & Exploration Company (filed as Exhibit 2.6 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference) 
+90 
+Table of Contents 
+3.1 
+Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+3.2 
+Restated By-Laws of SM Energy Company amended effective as of June 1, 2010 (filed as Exhibit 3.2 to the registrant’s Current Report on Form 8-K filed on June 2, 2010, and incorporated herein by reference) 
+4.1 
+Shareholder Rights Plan adopted on July 15, 1999 (filed as Exhibit 4.1 to the registrant’s Quarterly Report on Form 10-Q/A for the quarter ended June 30, 1999 and incorporated herein by reference) 
+4.2 
+First Amendment to Shareholders Rights Plan dated March 15, 2002 as adopted by the Board of Directors on July 19, 2001 (filed as Exhibit 4.2 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2001 and incorporated herein by reference) 
+4.3 
+Second Amendment to Shareholder Rights Plan dated April 24, 2006 (filed as Exhibit 4.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 and incorporated herein by reference) 
+4.4 
+Indenture related to the 3.50% Senior Convertible Notes due 2027, dated as of April 4, 2007, between St. Mary Land & Exploration Company and Wells Fargo Bank, National Association, as trustee (including the form of 3.50% Senior Convertible Note due 2027) (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on April 4, 2007 and incorporated herein by reference) 
+4.5 
+Registration Rights Agreement, dated as of April 4, 2007, among St. Mary Land & Exploration Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wachovia Capital Markets, LLC, for themselves and as representatives of the Initial Purchasers (filed Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on April 4, 2007, and incorporated herein by reference) 
+4.6 
+Indenture related to the 6.625% Senior Notes due 2019, dated as of February 7, 2011, by and between SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on February 10, 2011, and incorporated herein by reference) 
+4.7 
+Registration Rights Agreement, dated as of February 7, 2011, by and among SM Energy Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as representatives of the several initial purchasers (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on February 10, 2011, and incorporated herein by reference) 
+10.1† 
+Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference) 
+10.2† 
+Incentive Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.2 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference) 
+10.3† 
+Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001 and incorporated herein by reference) 
+10.4† 
+Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.9 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 
+91 
+Table of Contents 
+2005 and incorporated herein by reference) 
+10.5† 
+Employment Agreement of A.J. Best dated May 1, 2006 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 4, 2006 and incorporated herein by reference) 
+10.6† 
+Form of Performance Share Award Agreement (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q filed on August 5, 2008 and incorporated herein by reference) 
+10.7† 
+Form of Performance Share Award Notice (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q filed on August 5, 2008 and incorporated herein by reference) 
+10.8 
+Third Amended and Restated Credit Agreement dated April 14, 2009 among St. Mary Land & Exploration Company, Wachovia Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference) 
+10.9 
+Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement for the benefit of Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference) 
+10.10 
+Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference) 
+10.11† 
+Equity Incentive Compensation Plan as Amended and Restated as of March 26, 2009 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 27, 2009, and incorporated herein by reference) 
+10.12† 
+Equity Incentive Compensation Plan As Amended and Restated as of April 1, 2010 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on June 2, 2010, and incorporated herein by reference) 
+10.13♦ 
+SM Energy Company Equity Incentive Compensation Plan, As Amended as of July 30, 2010 (filed as Exhibit 10.7 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.14† 
+Form of Performance Share and Restricted Stock Unit Award Agreement (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, and incorporated herein by reference) 
+10.15† 
+Form of Performance Share and Restricted Stock Unit Award Notice (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, and incorporated herein by reference) 
+10.16† 
+Third Amendment to Employee Stock Purchase Plan dated September 23, 2009 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, and incorporated herein by reference) 
+10.17† 
+Fourth Amendment to Employee Stock Purchase Plan dated December 29, 2009 (filed as Exhibit 10.46 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein by reference) 
+10.18♦ 
+Employee Stock Purchase Plan, As Amended and Restated as of July 30, 2010 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+92 
+Table of Contents 
+10.19 
+Carry and Earning Agreement between St. Mary Land & Exploration Company and Encana Oil & Gas (USA) Inc. executed as of April 29, 2010 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.20† 
+Form of Performance Share and Restricted Stock Unit Award Agreement as of July 1, 2010 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.21† 
+Form of Performance Share and Restricted Stock Unit Award Notice as of July 1, 2010 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.22† 
+Form of Non-Employee Director Restricted Stock Award Agreement as of May 27, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.23*** 
+Gas Services Agreement effective as of July 1, 2010 between SM Energy Company and Eagle Ford Gathering LLC (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.24♦ 
+Cash Bonus Plan, As Amended on July 30, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.25♦ 
+Net Profits Interest Bonus Plan, As Amended by the Board of Directors on July 30, 2010 (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.26♦ 
+SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan, As Amended as of July 30, 2010 (filed as Exhibit 10.8 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.27† 
+Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on December 29, 2010, and incorporated herein by reference) 
+10.28*† 
+Amendment to A.J. Best Employment Agreement dated December 31, 2010 
+10.29 
+Purchase Agreement, dated January 31, 2011, among SM Energy Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as representatives of the Initial Purchasers named therein (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on February 1, 2011, and incorporated herein by reference) 
+10.30* 
+Pension Plan for Employees of SM Energy Company as Amended and Restated as of January 1, 2010 
+10.31*+ 
+SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan as Amended as of November 9, 2010 
+10.32*† 
+Summary of Compensation Arrangements for Non-Employee Directors 
+21.1* 
+Subsidiaries of Registrant 
+23.1* 
+Consent of Deloitte & Touche LLP 
+23.2* 
+Consent of Ryder Scott Company L.P. 
+93 
+Table of Contents 
+23.3* 
+Consent of Netherland, Sewell & Associates, Inc. 
+24.1* 
+Power of Attorney 
+31.1* 
+Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 
+31.2* 
+Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 
+32.1** 
+Certification pursuant to U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 
+99.1* 
+Ryder Scott Audit Letter 
+101.INS**** 
+XBRL Instance Document 
+101.SCH**** 
+XBRL Schema Document 
+101.CAL**** 
+XBRL Calculation Linkbase Document 
+101.LAB**** 
+XBRL Label Linkbase Document 
+101.PRE**** 
+XBRL Presentation Linkbase Document 
+101.DEF**** 
+XBRL Taxonomy Extension Definition Linkbase Document 
+* 
+Filed with this Form 10-K 
+** 
+Furnished with this Form 10-K 
+*** 
+Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934. 
+**** 
+Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections. 
+† 
+Exhibit constitutes a management contract or compensatory plan or agreement. 
+♦ 
+Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the recent change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the substantive terms and conditions in this document. 
++ 
+Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal Revenue Code. There were no material changes to the substantive terms and conditions in this document. 
+(c) Financial Statement Schedules. See Item 15(a) above. 
+94 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Board of Directors and Stockholders of 
+SM Energy Company and Subsidiaries 
+Denver, Colorado 
+We have audited the accompanying consolidated balance sheets of SM Energy Company and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits. 
+We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. 
+In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of SM Energy Company and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. 
+As discussed in Note 1 to the consolidated financial statements, the Company changed its method of oil and gas reserve estimation and related required disclosures in 2009 with the implementation of new accounting guidance. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2011, expressed an unqualified opinion on the Company’s internal control over financial reporting. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 25, 2011 
+F-1 
+Table of Contents 
+PART II. FINANCIAL INFORMATION 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share amounts) 
+December 31, 
+2010 
+2009 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+5,077 
+$ 
+10,649 
+Accounts receivable (note 2) 
+163,190 
+116,136 
+Refundable income taxes 
+8,482 
+32,773 
+Prepaid expenses and other 
+45,522 
+14,259 
+Derivative asset 
+43,491 
+30,295 
+Deferred income taxes 
+8,883 
+4,934 
+Total current assets 
+274,645 
+209,046 
+Property and equipment (successful efforts method), at cost: 
+Land 
+1,491 
+1,371 
+Proved oil and gas properties 
+3,389,158 
+2,797,341 
+Less—accumulated depletion, depreciation, and amortization 
+(1,326,932 
+) 
+(1,053,518 
+) 
+Unproved oil and gas properties 
+94,290 
+132,370 
+Wells in progress 
+145,327 
+65,771 
+Materials inventory, at lower of cost or market 
+22,542 
+24,467 
+Oil and gas properties held for sale (note 3) 
+86,811 
+145,392 
+Other property and equipment, net of accumulated depreciation of $15,480 in 2010 and $14,550 in 2009 
+21,365 
+14,404 
+2,434,052 
+2,127,598 
+Other noncurrent assets: 
+Derivative asset 
+18,841 
+8,251 
+Other noncurrent assets 
+16,783 
+16,041 
+Total other noncurrent assets 
+35,624 
+24,292 
+Total Assets 
+$ 
+2,744,321 
+$ 
+2,360,936 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued expenses (note 2) 
+$ 
+417,654 
+$ 
+236,242 
+Derivative liability 
+82,044 
+53,929 
+Deposit associated with oil and gas properties held for sale 
+2,355 
+6,500 
+Total current liabilities 
+502,053 
+296,671 
+Noncurrent liabilities: 
+Long-term credit facility 
+48,000 
+188,000 
+Senior convertible notes, net of unamortized discount of $11,827 in 2010, and $20,598 in 2009 
+275,673 
+266,902 
+Asset retirement obligation 
+69,052 
+60,289 
+Asset retirement obligation associated with oil and gas properties held for sale 
+2,119 
+18,126 
+Net Profits Plan liability 
+135,850 
+170,291 
+Deferred income taxes 
+443,135 
+308,189 
+Derivative liability 
+32,557 
+65,499 
+Other noncurrent liabilities 
+17,356 
+13,399 
+Total noncurrent liabilities 
+1,023,742 
+1,090,695 
+Commitments and contingencies (note 6) 
+Stockholders’ equity: 
+Common stock, $0.01 par value—authorized: 200,000,000 shares; issued: 63,412,800 shares in 2010 and 62,899,122 shares in 2009; outstanding, net of treasury shares: 63,310,165 shares in 2010 and 62,772,229 shares in 2009 
+634 
+629 
+Additional paid-in capital 
+191,674 
+160,516 
+Treasury stock, at cost: 102,635 shares in 2010 and 126,893 shares in 2009 
+(423 
+) 
+(1,204 
+) 
+Retained earnings 
+1,042,123 
+851,583 
+Accumulated other comprehensive loss 
+(15,482 
+) 
+(37,954 
+) 
+Total stockholders’ equity 
+1,218,526 
+973,570 
+Total Liabilities and Stockholders’ Equity 
+$ 
+2,744,321 
+$ 
+2,360,936 
+The accompanying notes are an integral part of these consolidated financial statements. 
+F-2 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+(In thousands, except per share amounts) 
+For the Years 
+Ended December 31, 
+2010 
+2009 
+2008 
+Operating revenues and other income: 
+Oil and gas production revenue 
+$ 
+836,288 
+$ 
+615,953 
+$ 
+1,259,400 
+Realized oil and gas hedge gain (loss) 
+23,465 
+140,648 
+(101,096 
+) 
+Gain on divestiture activity (note 3) 
+155,277 
+11,444 
+63,557 
+Marketed gas system revenue 
+70,110 
+58,459 
+77,350 
+Other revenue 
+7,694 
+5,697 
+2,090 
+Total operating revenues and other income 
+1,092,834 
+832,201 
+1,301,301 
+Operating expenses: 
+Oil and gas production expense 
+195,075 
+206,800 
+271,355 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion 
+336,141 
+304,201 
+314,330 
+Exploration 
+63,860 
+62,235 
+60,121 
+Impairment of proved properties 
+6,127 
+174,813 
+302,230 
+Abandonment and impairment of unproved properties 
+1,986 
+45,447 
+39,049 
+Impairment of materials inventory 
+— 
+14,223 
+— 
+Impairment of goodwill 
+— 
+— 
+9,452 
+General and administrative 
+106,663 
+76,036 
+79,503 
+Bad debt expense (recovery) 
+— 
+(5,189 
+) 
+16,735 
+Change in Net Profits Plan liability 
+(34,441 
+) 
+(7,075 
+) 
+(34,040 
+) 
+Marketed gas system expense 
+66,726 
+57,587 
+72,159 
+Unrealized derivative (gain) loss 
+8,899 
+20,469 
+(11,209 
+) 
+Other expense 
+3,027 
+13,489 
+10,415 
+Total operating expenses 
+754,063 
+963,036 
+1,130,100 
+Income (loss) from operations 
+338,771 
+(130,835 
+) 
+171,201 
+Nonoperating income (expense): 
+Interest income 
+321 
+227 
+485 
+Interest expense 
+(24,196 
+) 
+(28,856 
+) 
+(26,950 
+) 
+Income (loss) before income taxes 
+314,896 
+(159,464 
+) 
+144,736 
+Income tax benefit (expense) 
+(118,059 
+) 
+60,094 
+(57,388 
+) 
+Net income (loss) 
+$ 
+196,837 
+$ 
+(99,370 
+) 
+$ 
+87,348 
+Basic weighted-average common shares outstanding 
+62,969 
+62,457 
+62,243 
+Diluted weighted-average common shares outstanding 
+64,689 
+62,457 
+63,133 
+Basic net income (loss) per common share 
+$ 
+3.13 
+$ 
+(1.59 
+) 
+$ 
+1.40 
+Diluted net income (loss) per common share 
+$ 
+3.04 
+$ 
+(1.59 
+) 
+$ 
+1.38 
+The accompanying notes are an integral part of these consolidated financial statements. 
+F-3 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS) 
+(In thousands, except share amounts) 
+Accumulated 
+Additional 
+Other 
+Total 
+Common Stock 
+Paid-in 
+Treasury Stock 
+Retained 
+Comprehensive 
+Stockholders’ 
+Shares 
+Amount 
+Capital 
+Shares 
+Amount 
+Earnings 
+Income (Loss) 
+Equity 
+Balances, January 1, 2008 
+64,010,832 
+$ 
+640 
+$ 
+211,913 
+(1,009,712 
+) 
+$ 
+(29,049 
+) 
+$ 
+876,038 
+$ 
+(156,968 
+) 
+$ 
+902,574 
+Comprehensive income, net of tax: 
+Net income 
+— 
+— 
+— 
+— 
+— 
+87,348 
+— 
+87,348 
+Change in derivative instrument fair value 
+— 
+— 
+— 
+— 
+— 
+— 
+177,005 
+177,005 
+Reclassification to earnings 
+— 
+— 
+— 
+— 
+— 
+— 
+46,463 
+46,463 
+Minimum pension liability adjustment 
+— 
+— 
+— 
+— 
+— 
+— 
+(1,207 
+) 
+(1,207 
+) 
+Total comprehensive income 
+309,609 
+Cash dividends, $ 0.10 per share 
+— 
+— 
+— 
+— 
+— 
+(6,186 
+) 
+— 
+(6,186 
+) 
+Treasury stock purchases 
+— 
+— 
+— 
+(2,135,600 
+) 
+(77,150 
+) 
+— 
+— 
+(77,150 
+) 
+Retirement of treasury stock 
+(2,945,212 
+) 
+(29 
+) 
+(103,237 
+) 
+2,945,212 
+103,266 
+— 
+— 
+— 
+Issuance of common stock under Employee Stock Purchase Plan 
+45,228 
+— 
+1,055 
+— 
+— 
+— 
+— 
+1,055 
+Issuance of common stock upon settlement of RSUs following expiration of restriction period, net of shares used for tax withholdings 
+482,602 
+5 
+(6,910 
+) 
+— 
+— 
+— 
+— 
+(6,905 
+) 
+Sale of common stock, including income tax benefit of stock option exercises 
+868,372 
+9 
+24,691 
+— 
+— 
+— 
+— 
+24,700 
+Stock-based compensation expense 
+3,750 
+— 
+13,771 
+23,113 
+1,041 
+— 
+— 
+14,812 
+Balances, December 31, 2008 
+62,465,572 
+$ 
+625 
+$ 
+141,283 
+(176,987 
+) 
+$ 
+(1,892 
+) 
+$ 
+957,200 
+$ 
+65,293 
+$ 
+1,162,509 
+Comprehensive loss, net of tax: 
+Net loss 
+— 
+— 
+— 
+— 
+— 
+(99,370 
+) 
+— 
+(99,370 
+) 
+Change in derivative instrument fair value 
+— 
+— 
+— 
+— 
+— 
+— 
+(35,977 
+) 
+(35,977 
+) 
+Reclassification to earnings 
+— 
+— 
+— 
+— 
+— 
+— 
+(67,344 
+) 
+(67,344 
+) 
+Minimum pension liability adjustment 
+— 
+— 
+— 
+— 
+— 
+— 
+74 
+74 
+Total comprehensive loss 
+(202,617 
+) 
+Cash dividends, $ 0.10 per share 
+— 
+— 
+— 
+— 
+— 
+(6,247 
+) 
+— 
+(6,247 
+) 
+Issuance of common stock under Employee 
+Stock Purchase Plan 
+86,308 
+1 
+1,515 
+— 
+— 
+— 
+— 
+1,516 
+Issuance of common stock upon settlement of 
+RSUs following expiration of restriction period, net of shares used for tax withholdings, including income tax cost of RSUs 
+156,252 
+1 
+(1,951 
+) 
+— 
+— 
+— 
+— 
+(1,950 
+) 
+Sale of common stock, including income tax benefit of stock option exercises 
+189,740 
+2 
+1,592 
+— 
+— 
+— 
+— 
+1,594 
+Stock-based compensation expense 
+1,250 
+— 
+18,077 
+50,094 
+688 
+— 
+— 
+18,765 
+Balances, December 31, 2009 
+62,899,122 
+$ 
+629 
+$ 
+160,516 
+(126,893 
+) 
+$ 
+(1,204 
+) 
+$ 
+851,583 
+$ 
+(37,954 
+) 
+$ 
+973,570 
+Comprehensive income, net of tax: 
+Net income 
+— 
+— 
+— 
+— 
+— 
+196,837 
+— 
+196,837 
+Change in derivative instrument fair value 
+— 
+— 
+— 
+— 
+— 
+— 
+16,811 
+16,811 
+Reclassification to earnings 
+— 
+— 
+— 
+— 
+— 
+— 
+6,641 
+6,641 
+Minimum pension liability adjustment 
+— 
+— 
+— 
+— 
+— 
+— 
+(980 
+) 
+(980 
+) 
+Total comprehensive income 
+219,309 
+Cash dividends, $ 0.10 per share 
+— 
+— 
+— 
+— 
+— 
+(6,297 
+) 
+— 
+(6,297 
+) 
+Issuance of common stock under Employee Stock Purchase Plan 
+52,948 
+1 
+1,669 
+— 
+— 
+— 
+— 
+1,670 
+Issuance of common stock upon settlement of RSUs following expiration of restriction period, net of shares used for tax withholdings, including income tax cost of RSUs 
+113,103 
+1 
+(2,094 
+) 
+— 
+— 
+— 
+— 
+(2,093 
+) 
+Sale of common stock, including income tax benefit of stock option exercises 
+346,377 
+3 
+5,621 
+— 
+— 
+— 
+— 
+5,624 
+Stock-based compensation expense 
+1,250 
+— 
+25,962 
+24,258 
+781 
+— 
+— 
+26,743 
+Balances, December 31, 2010 
+63,412,800 
+$ 
+634 
+$ 
+191,674 
+(102,635 
+) 
+$ 
+(423 
+) 
+$ 
+1,042,123 
+$ 
+(15,482 
+) 
+$ 
+1,218,526 
+The accompanying notes are an integral part of these consolidated financial statements. 
+F-4 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+(In thousands) 
+For the Years Ended 
+December 31, 
+2010 
+2009 
+2008 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+196,837 
+$ 
+(99,370 
+) 
+$ 
+87,348 
+Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
+Gain on divestiture activity 
+(155,277 
+) 
+(11,444 
+) 
+(63,557 
+) 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion 
+336,141 
+304,201 
+314,330 
+Exploratory dry hole expense 
+289 
+7,810 
+6,823 
+Impairment of proved properties 
+6,127 
+174,813 
+302,230 
+Abandonment and impairment of unproved properties 
+1,986 
+45,447 
+39,049 
+Impairment of materials inventory 
+— 
+14,223 
+— 
+Impairment of goodwill 
+— 
+— 
+9,452 
+Stock-based compensation expense 
+26,743 
+18,765 
+14,812 
+Bad debt expense (recovery) 
+— 
+(5,189 
+) 
+16,735 
+Change in Net Profits Plan liability 
+(34,441 
+) 
+(7,075 
+) 
+(34,040 
+) 
+Unrealized derivative (gain) loss 
+8,899 
+20,469 
+(11,209 
+) 
+Loss related to hurricanes 
+— 
+8,301 
+6,980 
+Loss on insurance settlement 
+— 
+— 
+2,296 
+Amortization of debt discount and deferred financing costs 
+13,464 
+12,213 
+9,344 
+Deferred income taxes 
+114,517 
+(39,735 
+) 
+38,164 
+Plugging and abandonment 
+(8,314 
+) 
+(26,396 
+) 
+(9,168 
+) 
+Other 
+(3,993 
+) 
+3,382 
+3,875 
+Changes in current assets and liabilities: 
+Accounts receivable 
+(47,153 
+) 
+46,743 
+(14,327 
+) 
+Refundable income taxes 
+24,291 
+(19,612 
+) 
+(12,228 
+) 
+Prepaid expenses and other 
+(35,363 
+) 
+(6,626 
+) 
+(1,504 
+) 
+Accounts payable and accrued expenses 
+53,198 
+(4,814 
+) 
+(12,348 
+) 
+Excess income tax benefit from the exercise of stock awards 
+(854 
+) 
+— 
+(13,867 
+) 
+Net cash provided by operating activities 
+497,097 
+436,106 
+679,190 
+Cash flows from investing activities: 
+Net proceeds from sale of oil and gas properties 
+311,504 
+39,898 
+178,867 
+Proceeds from insurance settlement 
+— 
+16,789 
+— 
+Capital expenditures 
+(668,288 
+) 
+(379,253 
+) 
+(746,586 
+) 
+Acquisition of oil and gas properties 
+(664 
+) 
+(76 
+) 
+(81,823 
+) 
+Receipts from (deposits to) restricted cash 
+— 
+14,398 
+(14,398 
+) 
+Other 
+(4,125 
+) 
+4,152 
+(9,814 
+) 
+Net cash used in investing activities 
+(361,573 
+) 
+(304,092 
+) 
+(673,754 
+) 
+Cash flows from financing activities: 
+Proceeds from credit facility 
+571,559 
+2,072,500 
+2,571,500 
+Repayment of credit facility 
+(711,559 
+) 
+(2,184,500 
+) 
+(2,556,500 
+) 
+Debt issuance costs related to credit facility 
+— 
+(11,074 
+) 
+— 
+Proceeds from sale of common stock 
+6,440 
+3,110 
+11,888 
+Repurchase of common stock 
+— 
+— 
+(77,202 
+) 
+Dividends paid 
+(6,297 
+) 
+(6,247 
+) 
+(6,186 
+) 
+Excess income tax benefit from the exercise of stock awards 
+854 
+— 
+13,867 
+Other 
+(2,093 
+) 
+(1,285 
+) 
+(182 
+) 
+Net cash used in financing activities 
+(141,096 
+) 
+(127,496 
+) 
+(42,815 
+) 
+Net change in cash and cash equivalents 
+(5,572 
+) 
+4,518 
+(37,379 
+) 
+Cash and cash equivalents at beginning of period 
+10,649 
+6,131 
+43,510 
+Cash and cash equivalents at end of period 
+$ 
+5,077 
+$ 
+10,649 
+$ 
+6,131 
+The accompanying notes are an integral part of these consolidated financial statements. 
+F-5 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) 
+Supplemental schedule of additional cash flow information and noncash investing and financing activities: 
+For the Years Ended 
+December 31, 
+2010 
+2009 
+2008 
+(In thousands) 
+Cash paid for interest 
+$ 
+13,340 
+$ 
+17,884 
+$ 
+21,976 
+Cash paid (refunded) for income taxes 
+$ 
+(25,578 
+) 
+$ 
+(9,857 
+) 
+$ 
+17,326 
+For the years ended December 31, 2010, 2009 and 2008, $238.5 million, $109.0 million, $116.5 million, respectively, are included as additions to oil and gas properties and accounts payable and accrued expenses. These oil and gas property additions are reflected in cash used in investing activities in the periods that the payables are settled. 
+For the years ended December 31, 2010, 2009, and 2008, the Company issued 24,258, 50,094, and 23,113 shares, respectively, of common stock from treasury to its non-employee directors pursuant to the Company’s Equity Incentive Compensation Plan. The Company recorded compensation expense related to these issuances of approximately $781,000, $688,000, and $1.0 million for the years ended December 31, 2010, 2009, and 2008, respectively. 
+For the years ended December 31, 2010, 2009, and 2008, the Company issued 160,381, 215,700, and 678,197 of common stock upon the settlement of RSU’s relating to awards granted in previous years. The Company and a majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholding as provided for in the plan documents and award agreements. As a result, the Company issued 113,103, 156,252, and 482,602 net shares of common stock associated with these grants for the years ended December 31, 2010, 2009, and 2008, respectively. The remaining 47,278, 59,448, and 195,595 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon the delivery of the shares underlying those RSU’s. 
+In December 2008 the Company closed a transaction whereby it exchanged non-core oil and gas properties located in Coupee Parish, Louisiana fair valued at $30.4 million for an increased interest in properties located in Upton and Midland Counties, Texas and $17.6 million in cash. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+F-6 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+Note 1—Summary of Significant Accounting Policies 
+Description of Operations 
+SM Energy Company (“SM Energy” or the “Company”), formerly named St. Mary Land & Exploration Company, is an independent energy company engaged in the acquisition, exploration, exploitation, development and production of natural gas and crude oil in North America, with a focus on oil and liquids-rich resource plays. 
+Basis of Presentation 
+The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the United States and the instructions to Form 10-K and regulation S-X. Subsidiaries that are not wholly-owned are accounted for using the equity or cost methods as appropriate. Equity method investments are included in other noncurrent assets in the accompanying consolidated balance sheets. Intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2010, through the filing date of this report. 
+Use of Estimates in the Preparation of Financial Statements 
+The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization (“DD&A”), impairment of proved properties, asset retirement obligations, and the Net Profits Plan liability, each of which represents a significant component of the accompanying consolidated financial statements. 
+Cash and Cash Equivalents 
+The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. 
+Accounts Receivable and Concentration of Credit Risk 
+The Company’s accounts receivables consist mainly of receivables from oil and gas purchasers and from partners with interests in common properties operated by the Company. Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. The Company records an allowance for doubtful accounts on a case-by-case basis once there is evidence that collection is not probable. Receivables are not collateralized. As of December 31, 2010, and 2009, the Company had no allowance for doubtful accounts recorded. 
+The Company has accounts in the following locations under two national banks: Denver, Colorado; Shreveport, Louisiana; Houston, Texas; Midland, Texas; and Billings, Montana. The Company has accounts with local banks in Tulsa, Oklahoma and Billings, Montana. The Company’s policy is to invest in highly-rated instruments and to limit the amount of credit exposure at each individual institution. 
+The Company currently uses eight separate counterparties for its oil and gas commodity derivatives. The counterparties to the Company’s derivative instruments are highly-rated entities with corporate credit ratings at or 
+F-7 
+Table of Contents 
+exceeding BBB+ and Baa1 classifications by Standard & Poor’s and Moody’s, respectively. Ratings represent minimum investment grade ratings. 
+Oil and Gas Producing Activities 
+The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. Exploratory dry hole costs are included in cash flows from investing activities as part of capital expenditures within the accompanying consolidated statements of cash flows. The costs of development wells are capitalized whether those wells are successful or unsuccessful. 
+Geological and geophysical costs and the costs of carrying and retaining unproved properties are expensed as incurred. DD&A of capitalized costs related to proved oil and gas properties is calculated on a pool-by-pool basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. As of December 31, 2010, and 2009, the Company’s estimated salvage value was $67.9 million and $77.8 million, respectively. 
+In December 2008 the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which was developed by several petroleum industry organizations and is a widely accepted standard for the management of petroleum resources. Key revisions include a requirement to use 12-month average pricing determined by averaging the first of the month prices for the preceding 12 months rather than year-end pricing for estimating proved reserves, the ability to include nontraditional resources in reserves, the ability to use new technology for determining proved reserves, and permitting disclosure of probable and possible reserves. The Company adopted these new rules and interpretations as of December 31, 2009. 
+Impairment of Proved and Unproved Properties 
+Proved oil and gas property costs are evaluated for impairment and reduced to fair value, which is expected future discounted cash flows, when there is an indication that the carrying costs may not be recoverable. Expected future cash flows are calculated on all proved reserves using a discount rate and price forecasts selected by the Company’s management. The discount rate is a rate that management believes is representative of current market conditions. The price forecast is based on NYMEX strip pricing for the first five years, adjusted for basis differentials. At the end of the first five years a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. An impairment write down is recorded on unproved property when the Company determines that either the property will not be developed or the carrying value is not realizable. 
+For the years ended December 31, 2010, 2009, and 2008, the Company recorded proved property impairment expense of $6.1 million, $174.8 million, and $302.2 million, respectively. In 2009, the Company incurred impairment on proved properties of $97.3 million related to assets located in our Mid-Continent region due to a significant decrease in the market price for natural gas and wider than normal differentials, $20.4 million related to assets located in our ArkLaTex region due to decreased natural gas prices and engineering revisions, and $14.0 million related to the write-down of certain assets located in the Gulf of Mexico in which the Company relinquished its ownership interests in order to satisfy its abandonment obligations. Approximately $154.0 million of the 2008 impairment write-down relates to the Olmos assets in South Texas that were acquired as part of the 2007 Rockford and Catarina acquisitions. The remaining 2008 impairment came from proved properties in the Gulf of Mexico, the Greater Green River Basin in Wyoming, and the Company’s Hanging Woman Basin coalbed methane project. 
+For the years ended December 31, 2010, 2009, and 2008, the Company recorded expense related to the abandonment and impairment of unproved properties of $2.0 million, $45.4 million, and $39.0 million, respectively. The largest specific components of the 2009 impairment related to the Floyd Shale acreage located in Mississippi and acreage in Oklahoma. The largest specific component of the 2008 impairment related to acreage within the Olmos shallow gas formation in South Texas. 
+F-8 
+Table of Contents 
+Sales of Proved and Unproved Properties 
+The sale of a partial interest in a proved oil and gas property is accounted for as normal retirement, and no gain or loss is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. A gain or loss is recognized for all other sales of producing properties and is included in the accompanying consolidated statements of operations. 
+The sale of a partial interest in an unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to the ultimate recovery of the cost applicable to the interest retained. A gain on the sale is recognized to the extent that the sales price exceeds the carrying amount of the unproved property. A gain or loss is recognized for all other sales of nonproducing properties and is included in the accompanying consolidated statements of operations. For additional discussion, please refer to Note 3—Divestitures and Assets Held for Sale. 
+Materials Inventory 
+The Company’s materials inventory is primarily comprised of tubular goods to be used in future drilling operations. Materials inventory is valued at the lower of cost or market and totaled $22.5 million and $24.5 million at December 31, 2010, and 2009, respectively. There were no materials inventory write downs for the years ended December 31, 2010, and 2008. The Company incurred net materials inventory write-downs for year the ended December 31, 2009, of $14.2 million as a result of the decrease in value of tubular goods. 
+Assets Held for Sale 
+Any properties held for sale as of the date of presentation of the balance sheet have been classified as assets held for sale and are separately presented on the accompanying consolidated balance sheets at the lower of net book value or fair value less the cost to sell. The asset retirement obligation liabilities related to such properties have been reclassified to asset retirement obligations associated with oil and gas properties held for sale in the consolidated balance sheets. For additional discussion on assets held for sale, please refer to Note 3—Divestitures and Assets Held for Sale. 
+Other Property and Equipment 
+Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets which range from three to thirty years. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts. 
+Intangible Assets 
+As of December 31, 2010, and 2009, the Company’s other noncurrent assets in the accompanying consolidated balance sheets include $4.4 million and $380,000, respectively, of intangible assets. These assets arise from acquired oil and gas sale contracts with favorable pricing terms and acquired indefinite life water rights. They do not qualify as derivatives or hedges. All indefinite life intangible assets are evaluated for impairment at least annually and if such indicators arise. 
+Cash Settlement Balancing 
+The Company uses the sales method of accounting for gas revenue whereby sales revenue is recognized on all gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. An asset or liability is recognized to the extent that there is an imbalance in excess of the remaining gas reserves on the underlying properties. 
+The Company’s gas imbalance position at December 31, 2010, and 2009, resulted in the recording of $1.5 million and $1.8 million, respectively, to accounts receivable and $934,000 and $1.2 million, respectively, to accounts payable and accrued expenses. 
+F-9 
+Table of Contents 
+Derivative Financial Instruments 
+The Company seeks to manage or reduce commodity price risk on production by hedging cash flows. The Company intends for derivative instruments used for this purpose to qualify as and to be designated as cash flow hedges. The Company seeks to minimize its basis risk and indexes its oil hedges to NYMEX prices, its NGL hedges to Oil Price Information Service (“OPIS”) prices, and the majority of its gas hedges to various regional index prices associated with pipelines in proximity to the Company’s areas of gas production. For additional discussion on derivatives, please see Note 10—Derivative Financial Instruments. 
+Net Profits Plan 
+The Company records the estimated fair value of future payments under the Net Profits Plan as a noncurrent liability in the accompanying consolidated balance sheets. The estimated liability is a discounted calculation and has underlying assumptions including estimates of oil and gas reserves, recurring and workover lease operating expense, production and ad valorem tax rates, present value discount factors, and pricing assumptions. The estimates the Company uses in calculating the long-term liability are adjusted from period-to-period based on the most current information attributable to the underlying assumptions. Changes in the estimated liability of future payments associated with the Net Profits Plan are recorded as increases or decreases to expense in the current period as a separate line item in the accompanying consolidated statements of operations as these changes are considered changes in estimates. 
+The distribution amounts due to participants and payable in each period under the Net Profits Plan as cash compensation related to periodic operations are recognized as compensation expense and are included within general and administrative expense and exploration expense in the accompanying consolidated statements of operations. The corresponding current liability is included in accounts payable and accrued expenses in the accompanying consolidated balance sheets. This treatment provides for a consistent matching of cash expense with net cash flows from the oil and gas properties in each respective pool of the Net Profits Plan. For additional discussion, please refer to the heading Net Profits Plan in Note 7—Compensation Plans and Note 11—Fair Value Measurements. 
+Asset Retirement Obligations 
+The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. For additional discussion, please refer to Note 9—Asset Retirement Obligations. 
+Revenue Recognition 
+The Company derives revenue primarily from the sale of produced natural gas and crude oil. The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported as separate expenses and are included in oil and gas production expense in the accompanying consolidated statements of operations. Revenue is recorded in the month the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses its knowledge of its properties, their historical performance, NYMEX and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates. 
+F-10 
+Table of Contents 
+Major Customers 
+During 2010, the Company had one customer individually account for 11 percent of our total oil and gas production revenue. During 2009, the Company had one customer that individually accounted for 12 percent of the Company’s total oil and gas production revenue. During 2008, no customer individually accounted for ten percent or more of our total oil and gas production revenue. 
+Stock Based Compensation 
+At December 31, 2010, the Company had stock-based employee compensation plans that included RSUs, PSAs, stock awards, and stock options issued to employees and non-employee directors as more fully described in Note 7—Compensation Plans. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative guidance. The Company records compensation expense associated with the issuance of RSUs and PSAs based on the estimated fair value of these awards determined at the time of grant. 
+Income Taxes 
+The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amount on the financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. 
+Earnings per Share 
+Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the weighted-average basic common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company. 
+Diluted net income or loss per common share of stock is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested RSUs, in-the-money outstanding options to purchase the Company’s common stock, contingent PSAs, and shares into which the 3.50% Senior Convertible Notes are convertible. 
+The Company’s 3.50% Senior Convertible Notes have a net-share settlement right whereby each $1,000 principal amount of notes may be surrendered for conversion to cash in an amount equal to the principal amount and, if applicable, shares of common stock or cash or any combination of common stock and cash for the amount of conversion value in excess of the principal amount. The treasury stock method is used to measure the potentially dilutive impact of shares associated with this conversion feature. The 3.50% Senior Convertible Notes have not been dilutive for any reporting period that they have been outstanding and therefore do not impact the diluted earnings per share calculation for the years ended December 31, 2010, 2009, and 2008. 
+The PSAs represent the right to receive, upon settlement of the PSAs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSAs granted on the award date. The number of potentially dilutive shares related to PSAs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period. For additional discussion on PSAs, please refer to Note 7—Compensation Plans under the heading Performance Share Awards Under the Equity Incentive Compensation Plan . 
+The treasury stock method is used to measure the dilutive impact of stock options, RSUs, 3.50% Senior Convertible Notes, and PSAs. When there is a loss from continuing operations, all potentially dilutive shares will be anti-dilutive. There were no dilutive shares for the year ended December 31, 2009, because the Company recorded a loss for 
+F-11 
+Table of Contents 
+the year. Unvested RSUs, contingent PSAs, and in-the-money options had a dilutive impact for the years ended December 31, 2010, and 2008, as calculated in the basic and diluted earnings per share table below. 
+The following table details the weighted-average dilutive and anti-dilutive securities related to stock options, RSUs, and PSAs for the years presented: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+Dilutive 
+1,720,149 
+— 
+890,189 
+Anti-dilutive 
+— 
+1,152,127 
+330,231 
+The following table sets forth the calculations of basic and diluted earnings per share: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands, except per share amounts) 
+Net income (loss) 
+$ 
+196,837 
+$ 
+(99,370 
+) 
+$ 
+87,348 
+Basic weighted-average common shares outstanding 
+62,969 
+62,457 
+62,243 
+Add: dilutive effect of stock options, unvested RSUs, and contingent PSAs 
+1,720 
+— 
+890 
+Add: dilutive effect of 3.50% Senior Convertible Notes 
+— 
+— 
+— 
+Diluted weighted-average common shares outstanding 
+64,689 
+62,457 
+63,133 
+Basic net income (loss) per common share 
+$ 
+3.13 
+$ 
+(1.59 
+) 
+$ 
+1.40 
+Diluted net income (loss) per common share 
+$ 
+3.04 
+$ 
+(1.59 
+) 
+$ 
+1.38 
+Comprehensive Income (Loss) 
+Comprehensive income or loss consists of net income or loss, the unrealized gain or loss for the effective portion of derivative instruments classified as cash flow hedges, and the minimum pension liability adjustment that was recognized as a component of net periodic benefit cost. Comprehensive income or loss is presented net of income taxes in the accompanying consolidated statements of stockholders’ equity and comprehensive income (loss). 
+F-12 
+Table of Contents 
+The changes in the balances of components comprising other comprehensive income and loss are presented in the following table: 
+Pension 
+Other 
+Derivative 
+Liability 
+Comprehensive 
+Instruments 
+Adjustments 
+Income (Loss) 
+(in thousands) 
+For the year ended December 31, 2008 
+Before tax income (loss) 
+$ 
+358,632 
+$ 
+(1,941 
+) 
+$ 
+356,691 
+Tax benefit (expense) 
+(135,164 
+) 
+734 
+(134,430 
+) 
+After deferred tax income (loss) 
+$ 
+223,468 
+$ 
+(1,207 
+) 
+$ 
+222,261 
+For the year ended December 31, 2009 
+Before tax income (loss) 
+$ 
+(165,684 
+) 
+$ 
+119 
+$ 
+(165,565 
+) 
+Tax benefit (expense) 
+62,363 
+(45 
+) 
+62,318 
+After deferred tax income (loss) 
+$ 
+(103,321 
+) 
+$ 
+74 
+$ 
+(103,247 
+) 
+For the year ended December 31, 2010 
+Before tax income (loss) 
+$ 
+37,512 
+$ 
+(1,570 
+) 
+$ 
+35,942 
+Tax benefit (expense) 
+(14,060 
+) 
+590 
+(13,470 
+) 
+After deferred tax income (loss) 
+$ 
+23,452 
+$ 
+(980 
+) 
+$ 
+22,472 
+Fair Value of Financial Instruments 
+The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had $48.0 million and $188.0 million in loans outstanding under its revolving credit agreement as of December 31, 2010, and 2009, respectively. The Company’s 3.50% Senior Convertible Notes are recorded at cost, and the fair value is disclosed in Note 5—Long-Term Debt. The Company has derivative financial instruments that are recorded at fair value and changes in fair value are recorded to accumulated other comprehensive loss in the accompanying consolidated balance sheets to the extent they are effective. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. 
+Industry Segment and Geographic Information 
+The Company operates exclusively in the exploration and production segment and all of the Company’s operations are conducted entirely in the United States in North America. The Company reports as a single industry segment. The Company’s gas marketing function provides mostly internal services and acts as the first purchaser of natural gas and natural gas liquids produced by the Company in certain cases. We consider the Company’s marketing function as ancillary to the Company’s oil and gas producing activities. The amount of income these operations generate from marketing gas produced by third parties is not material to the Company’s financial position, and segmentation of such activity would not provide a better understanding of the Company’s performance. However, gross revenue and expense related to marketing activities for gas produced by third parties are presented discretely in the accompanying consolidated statements of operations. 
+Off-Balance Sheet Arrangements 
+As part of its ongoing business, the Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. The Company has not been involved in any unconsolidated SPE transactions. 
+F-13 
+Table of Contents 
+The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that SM Energy is the primary beneficiary of a variable interest entity, that entity is consolidated into SM Energy. 
+Recently Issued Accounting Standards 
+The Company partially adopted new fair value measurement authoritative guidance that requires additional disclosures surrounding transfers between Levels 1 and 2, inputs and valuation techniques used to value Level 2 and 3 measurements, and push down of previously prescribed fair value disclosures to each class of asset and liability for Levels 1, 2, and 3. These disclosures were effective for the Company for the quarter ended March 31, 2010. The partial adoption did not have a material impact on the Company’s consolidated financial statements. Please refer to Note 11—Fair Value Measurements for additional information on the recent adoption of new authoritative accounting guidance. 
+The Company will apply new fair value measurement authoritative guidance requiring that purchases, sales, issuances, and settlements for Level 3 measurements be disclosed. These disclosures are effective for interim and annual reporting periods beginning after December 15, 2010. The Company will apply this new guidance in the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2011. The adoption of this guidance is not expected to have a material impact on the Company’s financial statements. 
+Note 2—Accounts Receivable and Accounts Payable and Accrued Expenses 
+Accounts receivable are comprised of the following: 
+As of December 31, 
+2010 
+2009 
+(in thousands) 
+Accrued oil and gas sales 
+$ 
+108,393 
+$ 
+80,085 
+Due from joint interest owners 
+50,018 
+29,719 
+State severance tax refunds 
+2,114 
+4,638 
+Other 
+2,665 
+1,694 
+Total accounts receivable 
+$ 
+163,190 
+$ 
+116,136 
+F-14 
+Table of Contents 
+Accounts payable and accrued expenses are comprised of the following: 
+As of December 31, 
+2010 
+2009 
+(in thousands) 
+Accrued drilling costs 
+$ 
+235,975 
+$ 
+100,960 
+Revenue and severance tax payable 
+37,066 
+33,370 
+Accrued lease operating expense 
+17,643 
+13,760 
+Accrued property taxes 
+5,979 
+4,747 
+Joint owner advances 
+24,698 
+5,312 
+Accrued compensation 
+45,235 
+23,607 
+Trade payables 
+11,323 
+11,633 
+Plug and abandonment liability 
+11,679 
+23,665 
+Accrued marketed gas system expense 
+3,822 
+8,313 
+Settled hedge payable 
+6,371 
+1,637 
+Other 
+17,863 
+9,238 
+Total accounts payable and accrued expenses 
+$ 
+417,654 
+$ 
+236,242 
+Note 3—Divestitures and Assets Held for Sale 
+Permian Divestiture 
+In December 2010 the Company completed the divestiture of certain non-strategic oil properties located in our Permian region that were classified as held for sale at September 30, 2010. Total cash received, before commission costs and Net Profits Plan payments, was $56.3 million. The final sale price is subject to normal post-closing adjustments and is expected to be finalized during the first half of 2011. The estimated gain on divestiture activity is approximately $19.9 million and may be impacted by the forthcoming post-closing adjustments mentioned above. The Company determined that the sale did not qualify for discontinued operations accounting under financial statement presentation authoritative guidance. 
+Legacy Divestiture 
+In February 2010 the Company completed the divestiture of certain non-strategic oil properties located in Wyoming to Legacy Reserves Operating LP, a wholly-owned subsidiary of Legacy Reserves LP (“Legacy”). Total cash received, before commission costs and Net Profits Plan payments, was $125.3 million, of which $6.5 million was received as a deposit in December 2009. The final gain on sale related to the divestiture is approximately $66.7 million. These properties were classified as held for sale at December 31, 2009. The Company determined that the sale did not qualify for discontinued operations accounting. A portion of the transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”). 
+Sequel Divestiture 
+In March 2010 the Company completed the divestiture of certain non-strategic oil properties located in North Dakota to Sequel Energy Partners, LP, Bakken Energy Partners, LLC, and Three Forks Energy Partners, LLC (collectively referred to as “Sequel”). Total cash received, before commission costs and Net Profits Plan payments, was $129.1 million. The final gain on sale related to the divestiture is approximately $53.1 million. These properties were classified as held for sale at December 31, 2009. The Company determined that the sale did not qualify for discontinued operations accounting. A portion of the transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code. 
+F-15 
+Table of Contents 
+Hanging Woman Basin Divestiture 
+In December 2009 the Company completed the divestiture of certain non-strategic coalbed methane properties located in the Hanging Woman Basin in our Rocky Mountain region. Total cash received, before commission costs and Net Profits Plan payments, was $23.3 million. The final gain on sale related to the divestiture was approximately $12.9 million. The Company determined that the sale did not qualify for discontinued operations accounting under financial statement presentation authoritative guidance. 
+Abraxas Divestiture 
+In January 2008 the Company completed the divestiture of certain non-strategic oil and gas properties as the second step of a reverse 1031 exchange. The sold properties were located primarily in our Rocky Mountain and Mid-Continent regions, and were sold to Abraxas Petroleum Corporation and Abraxas Operating, LLC. The final sales price, net of commission costs, was $129.4 million. The final gain on sale related to the divestiture was approximately $53.4 million, net of commission costs and Net Profit Plan payments. The Company determined that the sale did not qualify for discontinued operations accounting under financial statement presentation authoritative guidance. 
+Assets Held for Sale 
+Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted and a measurement for impairment is performed to expense any excess of carrying value over fair value less costs to sell. Subsequent changes to estimated fair value less the cost to sell will impact the measurement of assets held for sale for assets for which fair value is determined to be less than the carrying value of the assets. 
+As of December 31, 2010, the accompanying consolidated balance sheets include $86.8 million in book value of assets held for sale, net of accumulated depletion, depreciation, and amortization. The corresponding asset retirement obligation liability of $2.1 million is also separately presented. The above assets held for sale and asset retirement obligation liability amounts include certain non-core properties located in Pennsylvania, and the Rocky Mountain and Mid-Continent regions. The Company began marketing these assets in the third quarter of 2010. The Company determined that these planned asset sales do not qualify for discontinued operations accounting under financial statement presentation authoritative guidance. 
+Subsequent to year end, the Company divested of the Rocky Mountain region properties that were classified as assets held for sale at December 31, 2010. The cash received at closing was $44.4 million before commission costs and Net Profit Plan payments. The final sales price is subject to normal post-closing adjustments and is expected to be finalized during the first half of 2011. 
+Additionally subsequent to year end, the Company plans to divest of a portion of the Company’s oil and gas assets located in our South Texas & Gulf Coast region. The net book value of these assets, net of accumulated depletion, depreciation, and amortization, is approximately $29 million. These assets were not classified as held for sale as of December 31, 2010. 
+Note 4—Income Taxes 
+The provision for income taxes consists of the following: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Current income tax expense (benefit) 
+Federal 
+$ 
+2,903 
+$ 
+(21,926 
+) 
+$ 
+17,863 
+State 
+639 
+1,567 
+1,361 
+Deferred income tax expense (benefit) 
+114,517 
+(39,735 
+) 
+38,164 
+Total income tax expense (benefit) 
+$ 
+118,059 
+$ 
+(60,094 
+) 
+$ 
+57,388 
+Effective tax rates 
+37.5 
+% 
+37.7 
+% 
+39.7 
+% 
+F-16 
+Table of Contents 
+As a result of the exercise of stock options, the Company reduced its income tax payable in 2010 and 2008. The excess income tax benefit to the Company associated with stock awards was $854,000 and $13.9 million in 2010 and 2008, respectively. There was no excess income tax benefit associated with stock awards in 2009. 
+The components of the net deferred income tax liabilities are as follows: 
+December 31, 
+2010 
+2009 
+(in thousands) 
+Deferred tax liabilities: 
+Oil and gas properties 
+$ 
+528,652 
+$ 
+419,585 
+Interest on Senior Convertible Notes 
+2,219 
+1,937 
+Other 
+2,723 
+1,378 
+Total deferred tax liabilities 
+533,594 
+422,900 
+Deferred tax assets: 
+Net Profits Plan liability 
+50,922 
+63,902 
+Stock compensation 
+13,143 
+9,647 
+State tax net operating loss carryforward or carryback 
+10,772 
+10,915 
+Unrealized derivative liability 
+6,929 
+21,107 
+Other long-term liabilities 
+19,740 
+17,277 
+Total deferred tax assets 
+101,506 
+122,848 
+Valuation allowance 
+(2,164 
+) 
+(3,203 
+) 
+Net deferred tax assets 
+99,342 
+119,645 
+Total net deferred tax liabilities 
+434,252 
+303,255 
+Less: current deferred income tax liabilities 
+(2,710 
+) 
+(1,366 
+) 
+Add: current deferred income tax assets 
+11,593 
+6,300 
+Non-current net deferred tax liabilities 
+$ 
+443,135 
+$ 
+308,189 
+Current federal income tax refundable 
+$ 
+8,482 
+$ 
+32,773 
+Current state income tax payable 
+$ 
+294 
+$ 
+168 
+At December 31, 2010, the Company had estimated state net operating loss carryforwards of approximately $259 million expiring between 2011 and 2030. The Company has other state tax credits of $349,000 which expire between 2011 and 2020. The majority of the Company’s valuation allowance relates to state net operating loss carryforwards, state tax credits, and state and federal income tax benefit amounts which the Company anticipates will expire before they can be utilized. Permanent items included in the calculation of income tax for certain states are anticipated to impact the Company’s ability to deduct operating losses and realize federal income tax deduction benefits in certain states and the Company adjusts its valuation allowances accordingly. The change in the valuation allowance from 2009 to 2010 indicated below reflects a change in the Company’s position regarding anticipated utilization of state net operating losses as a result of actual net income or loss occurring subsequent to a 2007 change in the Company’s operating structure and a review of expectations of contingent future performance. 
+F-17 
+Table of Contents 
+Federal income tax expense differs from the amount that would be provided by applying the statutory U.S. federal income tax rate to income before income taxes primarily due to the effect of state income taxes, percentage depletion, the estimated effect of the domestic production activities deduction, 2008 impairment of goodwill, changes in valuation allowances, and other permanent differences, as follows: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Federal statutory tax (benefit) 
+$ 
+110,214 
+$ 
+(55,812 
+) 
+$ 
+50,526 
+Increase (decrease) in tax resulting from State tax (benefit) (net of federal benefit) 
+7,750 
+(5,141 
+) 
+4,669 
+Change in valuation allowance 
+(1,039 
+) 
+56 
+(409 
+) 
+Statutory depletion 
+(266 
+) 
+(189 
+) 
+(294 
+) 
+Domestic production activities deduction 
+— 
+— 
+(275 
+) 
+Goodwill 
+— 
+— 
+3,308 
+Other 
+1,400 
+992 
+(137 
+) 
+Income tax expense (benefit) 
+$ 
+118,059 
+$ 
+(60,094 
+) 
+$ 
+57,388 
+Acquisitions, divestitures, drilling activity, and basis differentials impacting the prices received for crude oil and natural gas affect apportionment of taxable income to the states where the Company owns oil and gas properties. As its apportionment factors change, the Company’s blended state income tax rate changes. This change, when applied to the Company’s total temporary differences, impacts the total income tax reported in the current year and is reflected in state taxes in the table above. Items affecting state apportionment factors are evaluated after completion of the prior year income tax return and when significant acquisitions or divestitures are closed during the current year. 
+The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various states. With few exceptions, the Company is no longer subject to U.S. federal or state income tax examinations by these tax authorities for years before 2007. During the first quarter of 2010, the Internal Revenue Service initiated an audit of SM Energy for the 2006 tax year as a result of a net operating loss carryback from the Company’s 2008 tax year. The audit was focused primarily on compensation related issues. The audit was successfully concluded in the second quarter of 2010 with no changes to Company reported amounts. No amended Federal or state returns were required. The Joint Committee on Taxation has approved a $5.5 million refund, which is included in refundable income taxes on the accompanying balance sheets at December 31, 2010 and was received subsequent to year end. On July 20, 2010, the Company received $22.9 million related to an initial claim for net operating loss carry back from its 2009 tax year to its 2005 tax year. The Company’s remaining refundable income tax balance at December 31, 2010, reflects an additional net operating loss carry-back from filing a revised income tax return for the 2009 tax year prior to the extended return due date and an expected refund of tax paid in 2009. In the fourth quarter of 2010, the Internal Revenue Service began a full audit of the Company’s 2009 tax year. That audit was still in progress at December 31, 2010. 
+The Internal Revenue Service initiated an audit of the Company’s 2005 tax year in 2008 and concluded the audit in the first quarter of 2009 with a refund to the Company of $278,000 plus interest of $41,000. Related amended state income tax returns were filed in the second quarter of 2009. There was no change to the provision for income tax expense as a result of the examination. In the fourth quarter of 2009 the Company received a refund of $5.0 million related to its 2008 income tax return. 
+At December 31, 2008, the Company recognized an impairment of goodwill recorded as part of the Agate Petroleum, Inc. acquisition in 2005. The tax benefit is not calculated upon the recognition of this expense. This item resulted in a 2.2 percent increase in the Company’s effective tax rate for the year ended December 31, 2008. 
+The Company complies with uncertainty provisions of the income tax authoritative accounting guidance. The entire amount of unrecognized tax benefit would affect the Company’s effective tax rate if recognized. Interest expense in the 2010 accompanying consolidated statements of operations includes $42,000 associated with income tax. Penalties associated with income tax are recorded in general and administrative expense in the accompanying consolidated 
+F-18 
+Table of Contents 
+statements of operations. There were no penalties associated with income tax recorded for the years ended December 31, 2010, 2009, and 2008. 
+The total amount recorded for unrecognized tax benefits is presented below: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Beginning balance 
+$ 
+884 
+$ 
+994 
+$ 
+957 
+Additions for tax positions of prior years 
+244 
+231 
+173 
+Reductions for lapse of statute of limitations 
+(321 
+) 
+(341 
+) 
+(136 
+) 
+Ending balance 
+$ 
+807 
+$ 
+884 
+$ 
+994 
+Note 5—Long-term Debt 
+Revolving Credit Facility 
+The Company executed a Third Amended and Restated Credit Agreement on April 14, 2009. This amended revolving credit facility replaced the previous facility. The Company incurred $11.1 million of deferred financing costs in association with the amended credit facility. Borrowings under the facility are secured by a pledge, in favor of the lenders, of collateral that includes the majority of the Company’s oil and gas properties. The credit facility has a maturity date of July 31, 2012. The borrowing base under the credit facility is subject to regular semi-annual redeterminations. The borrowing base redetermination process considers the value of SM Energy’s oil and gas properties and other assets, as determined by the bank syndicate. In September 2010, the lending group redetermined our reserve-backed borrowing base under the credit facility at an amount of $1.1 billion, which was decreased to $1.0 billion subsequent to year end due to the issuance of the 6.625% Senior Notes as discussed below. The Company has an aggregate commitment amount of $678 million under the credit facility. The Company must comply with certain covenants under the terms of its credit facility agreement, including the limitation of the Company’s annual dividend rate to no more than $0.25 per share. The Company is in compliance with all covenants under the credit facility as of December 31, 2010, and through the date of this filing. Interest and commitment fees are accrued based on the borrowing base utilization grid below. Eurodollar loans accrue interest at the London Interbank Offered Rate (“LIBOR”) plus the applicable margin from the utilization table, and Alternative Base Rate (“ABR”) and swingline loans accrue interest at Prime plus the applicable margin from the utilization table. Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the accompanying consolidated statements of operations. 
+Borrowing Base Utilization Grid 
+Borrowing Base Utilization Percentage 
+<25% 
+³ 25% <50% 
+³ 50% <75% 
+³ 75% 
+Eurodollar Loans 
+2.000% 
+2.250% 
+2.500% 
+2.750% 
+ABR Loans or Swingline Loans 
+1.000% 
+1.250% 
+1.500% 
+1.750% 
+Commitment Fee Rate 
+0.500% 
+0.500% 
+0.500% 
+0.500% 
+The Company had $48.0 million and $188.0 million in outstanding loans under its revolving credit agreement on December 31, 2010, and 2009, respectively. There were no outstanding borrowings under the Company’s credit facility as of February 18, 2011. The Company had $677.5 million, $629.5 million, and $489.4 million of available borrowing capacity under this facility as of February 18, 2011, December 31, 2010, and 2009, respectively. The Company had a single letter of credit outstanding in the amount of $483,000 at February 18, 2011, and December 31, 2010, and $569,000 as of December 31, 2009. This letter of credit reduced the amount available under the commitment amount on a dollar-for-dollar basis. 
+3.50% Senior Convertible Notes Due 2027 
+On April 4, 2007, the Company issued $287.5 million in aggregate principal amount of 3.50% Senior Convertible Notes. The 3.50% Senior Convertible Notes mature on April 1, 2027, unless converted prior to maturity, redeemed, or 
+F-19 
+Table of Contents 
+purchased by the Company. The 3.50% Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. 
+Holders may convert their notes based on a conversion rate of 18.3757 shares of the Company’s common stock per $1,000 principal amount of the 3.50% Senior Convertible Notes (which is equal to an initial conversion price of approximately $54.42 per share), subject to adjustment and contingent upon and only under the following circumstances: (1) if the closing price of the Company’s common stock reaches specified thresholds or the trading price of the notes falls below specified thresholds, (2) if the notes are called for redemption, (3) if specified distributions to holders of the Company’s common stock are made or specified corporate transactions occur, (4) if a fundamental change occurs, or (5) during the ten trading days prior to but excluding the maturity date. As of December 31, 2009, the notes and underlying shares had been registered under a shelf registration statement. In 2010 the Company deregistered the shelf registration statement for the 3.50% Senior Convertible Notes. If the Company becomes involved in a material transaction or corporate development, it may suspend trading of the 3.50% Senior Convertible Notes under the prospectus. In the event the suspension period exceeds 45 days within any three-month period or 90 days within any twelve-month period, the Company will be required to pay additional interest to all holders of the 3.50% Senior Convertible Notes, not to exceed a rate per annum of 0.50 percent of the issue price of the 3.50% Senior Convertible Notes; provided that no such additional interest shall accrue after April 4, 2009. 
+Upon conversion of the 3.50% Senior Convertible Notes, holders will receive cash or common stock or any combination thereof as elected by the Company. At any time prior to the maturity date of the notes, the Company has the option to unilaterally and irrevocably elect to net share settle its obligations upon conversion of the notes in cash and, if applicable, shares of common stock. If the Company makes this election, then the Company will pay the following to holders for each $1,000 principal amount of notes converted in lieu of shares of common stock: (1) an amount in cash equal to the lesser of (i) $1,000 or (ii) the conversion value determined in the manner set forth in the indenture for the 3.50% Senior Convertible Notes, and (2) if the conversion value exceeds $1,000, the Company will also deliver, at its election, cash or common stock or a combination of cash and common stock with respect to the remaining value deliverable upon conversion. Currently, it is the Company’s intention to net share settle the 3.50% Senior Convertible Notes. However, the Company has not made this a formal legal irrevocable election and thereby reserves the right to settle the 3.50% Senior Convertible Notes in any manner allowed under the indenture as business conditions warrant. 
+If the holder elects to convert its notes in connection with certain events that constitute a change of control before April 1, 2012, the Company will pay, to the extent described in the related indenture, a make-whole premium by increasing the conversion rate applicable to the 3.50% Senior Convertible Notes. In addition, the Company will pay contingent interest in cash, commencing with any six-month period beginning on or after April 1, 2012, if the average trading price of a note for the five trading days ending on the third trading day immediately preceding the first day of the relevant six-month period equals 120 percent or more of the principal amount of the 3.50% Senior Convertible Notes. 
+On or after April 6, 2012, the Company may redeem for cash all or a portion of the 3.50% Senior Convertible Notes at a redemption price equal to 100 percent of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any, up to but excluding the applicable redemption date. Holders of the 3.50% Senior Convertible Notes may require the Company to purchase all or a portion of their notes on each of April 1, 2012, April 1, 2017, and April 1, 2022, at a purchase price equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. On April 1, 2012, the Company may pay the purchase price in cash, in shares of common stock, or in any combination of cash and common stock. On April 1, 2017, and April 1, 2022, the Company must pay the purchase price in cash. 
+Capitalized Interest 
+Capitalized interest costs for the Company for the years ended December 31, 2010, 2009, and 2008, were $4.3 million, $1.9 million, and $4.7 million, respectively. 
+F-20 
+6.625% Senior Notes Due 2019 
+On February 7, 2011, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes. The 6.625% Senior Notes mature on February 15, 2019. The Company received net proceeds of approximately $342.1 million after deducting discounts and fees. The net proceeds will be used to repay borrowings under the Company’s revolving credit facility and to fund the Company’s ongoing capital expenditure program. 
+The 6.625% Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the 6.625% Senior Notes. We are also subject to certain covenants under our 6.625% Senior Notes that limit the payment of dividends on our common stock to $6.5 million in any given calendar year during the eight year term of the notes. 
+Additionally, on February 7, 2011, the Company entered into a registration rights agreement that provides holders of the 6.625% Senior Notes certain rights relating to registration of the 6.625% Senior Notes under the Securities Act of 1933, as amended (the “Securities Act”). Pursuant to the registration rights agreement, the Company will file an exchange offer registration statement with the SEC with respect to an offer to exchange the 6.625% Senior Notes for substantially identical notes that are registered under the Securities Act. Under certain circumstances, in lieu of a registered exchange offer, the Company has agreed to file a shelf registration statement with respect to the 6.625% Senior Notes. If the exchange offer is not completed on or before February 7, 2012, or the shelf registration statement, if required, is not declared effective within the time periods specified in the registration rights agreement, then the Company agrees to pay additional interest with respect to the 6.625% Senior Notes in an amount not to exceed one percent of the principal amount of the 6.625% Senior Notes until the exchange offer is completed or the shelf registration statement is declared effective. 
+Note 6 — Commitments and Contingencies 
+The Company has entered into various agreements, which include drilling rig leasing contracts, of approximately $142.3 million, gas gathering through-put commitments of $181.1 million, office space leases including maintenance of approximately $33.2 million, hydraulic fracturing contracts of $42.7 million, and other miscellaneous contracts and leases of $9.0 million. The annual minimum payments for the next five years and thereafter are presented below: 
+Years Ending December 31, 
+(in thousands) 
+2011 
+$ 
+106,725 
+2012 
+61,956 
+2013 
+54,472 
+2014 
+44,046 
+2015 
+21,417 
+Thereafter 
+119,721 
+Total 
+$ 
+408,337 
+Subsequent to year end the Company entered into a hydraulic fracturing services contract. The total commitment is $180.0 million over a two year term provided however, our liability upon early termination of this contract may not exceed $24 million. The commitment amount is not reflected in the amounts above. 
+The Company leases office space under various operating leases with terms extending as far as May 31, 2022. Rent expense for 2010 was $2.7 million. Rent expense, net of sub lease rent of $185,000 per year, for 2009 and 2008 was $2.3 million, and $2.4, respectively. The Company also leases office equipment under various operating leases. 
+The Company is subject to litigation and claims that have arisen in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such pending litigation and claims will not have a material effect on the results of operations, the financial position, or cash flows of the Company. 
+F-21 
+The Company is currently engaged in litigation regarding an overriding royalty interest in less than one percent of the Company’s net acreage in the Eagle Ford shale play in South Texas. The Company believes that the lawsuit is without merit and will continue to contest the litigation. However, the Company is not able to accurately predict the final outcome of the lawsuit, and if the plaintiffs were to prevail the overriding royalty interest would reduce the Company’s net revenue interest in the affected acreage. The Company does not believe that an unfavorable outcome is probable, nor that if the plaintiffs prevail there would be a material adverse effect on the financial position of the Company. As a result of the current facts and circumstances of the case, no accrual has been made for such loss. 
+Note 7 — Compensation Plans 
+Cash Bonus Plan 
+The Company has a cash bonus plan based on a performance measurement framework whereby selected eligible employee participants may be awarded an annual cash bonus. The plan document provides that no participant may receive an annual bonus under the plan of more than 200 percent of his or her base salary. As the plan is currently administered, any awards under the plan are based on Company and regional performance, and are then further refined by individual performance. The Company accrues cash bonus expense based upon the Company’s current year’s performance. Included in general and administrative and exploration expense in the accompanying consolidated statements of operations are $21.6 million, $7.8 million, and $6.4 million of cash bonus expense related to the specific performance year for the years ended December 31, 2010, 2009, and 2008, respectively. 
+Equity Incentive Compensation Plan 
+There are several components to the equity compensation plan that are described in this section. Various types of equity awards have been granted by the Company in different periods. 
+In May 2006 the stockholders approved the 2006 Equity Incentive Compensation Plan, which was subsequently renamed the Equity Incentive Compensation Plan (the “Equity Plan”) Plan to authorize the issuance of restricted stock, RSUs, non-qualified stock options, incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and members of the Board of Directors of SM Energy or any affiliate of SM Energy. The Equity Plan serves as the successor to the St. Mary Land & Exploration Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock Option Plan, the St. Mary Land & Exploration Company Restricted Stock Plan, and the St. Mary Land & Exploration Company Non-Employee Director Stock Compensation Plan (collectively referred to as the “Predecessor Plans”). All grants of equity are now made pursuant to the Equity Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under the Predecessor Plans prior to the effective date of the Equity Plan continues to be governed solely by the terms and conditions of the instruments evidencing such grants or issuances. An amendment and restatement of the Equity Plan was approved by the Company’s stockholders at the 2008 annual stockholders’ meeting held on May 21, 2008. The Equity Plan was further amended at the 2009 annual stockholders’ meeting held on May 20, 2009, and again on July 30, 2010, primarily to reflect the change in the name of the Company from St. Mary Land & Exploration Company to SM Energy Company. 
+As of December 31, 2010, 2.6 million shares of common stock remained available for grant under the Equity Plan. The issuance of a direct share benefit such as an outright grant of common stock, a grant of a restricted share, a RSU grant, or a PSA grant, counts as 1.43 shares against the number of shares available to be granted under the Equity Plan. At the end of a three-year performance period a final multiplier ranging between zero and two is applied to each PSA so that each performance share granted has the potential to result in the issuance of two shares of common stock. Consequently, each performance share granted may count as 2.86 shares against the number of shares available to be granted under the Equity Plan. Stock option grants count as one share for each instrument granted against the number of shares available to be granted under the Equity Plan. The Company has outstanding stock option awards under the Predecessor Plans. 
+Performance Share Awards Under the Equity Incentive Compensation Plan 
+PSAs are the primary form of long-term equity incentive compensation for the Company. The PSA factor is based on the Company’s performance after completion of a three-year performance period. The performance criteria for 
+F-22 
+the PSAs are based on a combination of the Company’s annualized TSR for the performance period and the relative measure of the Company’s TSR compared with the annualized TSR of an index comprised of certain peer companies for the performance period. PSAs are recognized as general and administrative and exploration expense over the vesting period of the award. 
+The Company granted 387,651 PSAs on July 1, 2010, 725,092 PSAs on August 1, 2009, and 465,751 PSAs on August 1, 2008. The fair value of these grants was $20.3 million, $25.8 million, and $12.3 million for the July 1, 2010, August 1, 2009, and August 1, 2008 grants, respectively. The PSAs vest 1/7 th , 2/7(ths), and 4/7(ths) on the first three anniversary dates of their issuances. 
+In measuring compensation expense related to the grant of PSAs, the Company estimates the fair value of the award on the grant date. The fair value of PSAs is measured by a stochastic process method using the Geometric Brownian Motion Model (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSAs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three-year performance period. By using a stochastic simulation the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences to the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSAs. 
+A summary of the status and activity of PSAs for the years ending December 31, 2010, 2009, and 2008 is presented in the following table: 
+2010 
+2009 
+2008 
+PSAs 
+Weighted- 
+Average 
+Grant- 
+Date Fair 
+Value 
+PSAs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+PSAs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+Non-vested at beginning of year 
+1,069,090 
+$ 
+32.52 
+464,333 
+$ 
+26.48 
+— 
+$ 
+— 
+Granted 
+387,651 
+$ 
+52.35 
+725,092 
+$ 
+35.59 
+465,751 
+$ 
+26.48 
+Vested(1) 
+(210,801 
+) 
+$ 
+31.18 
+(76,781 
+) 
+$ 
+27.20 
+— 
+$ 
+— 
+Forfeited 
+(135,274 
+) 
+$ 
+34.28 
+(43,554 
+) 
+$ 
+28.62 
+(1,418 
+) 
+$ 
+26.48 
+Non-vested at end of year 
+1,110,666 
+$ 
+39.48 
+1,069,090 
+$ 
+32.52 
+464,333 
+$ 
+26.48 
+(1) The number of awards vested assume a one multiplier. The final number of shares issued may vary depending on the ending three-year multiplier, which ranges from zero to two. 
+The total fair value of PSAs that vested during the years ended December 31, 2010, and 2009 was $6.6 million and $1.8 million, respectively. Total expense recorded for PSAs was $17.7 million, $9.3 million, and $2.5 million for the years ended December 31, 2010, 2009, and 2008, respectively. As of December 31, 2010, there was $22.6 million of total unrecognized expense related to PSAs, which is being amortized through 2013. 
+Restricted Stock Incentive Program Under the Equity Incentive Compensation Plan 
+The Company grants restricted stock or RSUs as part of the long-term incentive program to eligible employees, consultants, and members of the Board of Directors. Restrictions and vesting periods for the awards are determined by the Board of Directors and are set forth in the award agreements. Each RSU represents a right for one share of the Company’s common stock to be delivered upon settlement of the award at the end of a specified period. These grants are determined annually based on the results of the PSA awards. RSUs are recognized as general and administrative and exploration expense over the vesting period of the award. 
+F-23 
+The Company issued 126,821 RSUs on July 1, 2010, and 241,745 RSUs on August 1, 2009. The fair value associated with these issuances was $5.1 million and $5.8 million, respectively. These RSUs vest 1/7 th , 2/7(ths), and 4/7(ths) on the first three anniversary dates of their issuances. 
+SM Energy issued 265,373 RSUs on June 30, 2008, as a transitional award to employees when the Company moved from the standalone RSU equity incentive compensation plan to the PSA program. The total fair value associated with this issuance was $17.2 million as measured on the grant date. The granted RSUs vest one third on each date of December 15 th 2008, 2009, and 2010. 
+The Company issued 158,744 RSUs on February 28, 2008, with a fair value of $6.0 million. These RSUs vested 25 percent immediately upon grant and 25 percent on each of the first three anniversary dates of the grant. 
+The Company issued an additional 2,044 and 4,290 RSUs to certain employees during 2010 and 2008, respectively. There were no additional RSUs issued in 2009. The total fair value associated with the 2010 and 2008 issuances was $100,000 and $164,000, respectively, as measured on the respective grant dates. These grants have various vesting schedules. 
+As of December 31, 2010, a total of 333,359 RSUs were outstanding, of which none were vested. The total expense associated with RSUs for the years ended December 31, 2010, 2009, and 2008, was $7.7 million, $7.9 million, and $11.0 million, respectively. As of December 31, 2010, there was $6.6 million of total unrecognized expense related to unvested RSU awards and is being amortized through 2013. 
+During 2010, 2009, and 2008, the Company settled 160,381, 215,700, and 678,197 RSUs, respectively. The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, the Company issued net shares of common stock of 113,103, 156,252, and 482,602 for 2010, 2009, and 2008, respectively. The remaining 47,278, 59,448, and 195,595 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon the delivery of the shares underlying those RSUs for 2010, 2009, and 2008, respectively. 
+Stock Awards Under the Equity Incentive Compensation Plan 
+As part of hiring a new senior executive in the second quarter of 2006, the Company granted a special common stock award of 20,000 shares that vested immediately upon commencement of employment. The fair value associated with this award was $727,600. In addition to this award, the employee was eligible to earn an additional 5,000 shares over a four-year period and an additional 15,000 shares contingent on the Company meeting certain net asset growth performance conditions over a four-year period. In 2010, 2009, and 2008, the Company issued 1,250, 1,250, and 3,750 shares with fair values of $43,000, $45,000, and $142,000, respectively related to these service-based and performance-based awards. The fair value of these awards is being recorded as compensation expense over the vesting period. 
+As part of hiring a new senior executive in the third quarter of 2008, the Company granted a special restricted stock award of 15,496 shares that vested one half on December 15, 2009, and the other half on December 15, 2010. The fair value of this award was $600,005 and was recorded as compensation expense over the vesting period. For the years ended December 31, 2010, 2009, and 2008 the Company recorded expense of $126,000, $358,000, and $115,000, respectively, related to this award. 
+F-24 
+A summary of the status and activity of non-vested stock awards and RSUs for the years ending December 31, 2010, 2009, and 2008, is presented below: 
+2010 
+2009 
+2008 
+Stock 
+Awards 
+and RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+Stock 
+Awards 
+and RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+Stock 
+Awards 
+and RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+Non-vested at beginning of year 
+407,123 
+$ 
+34.67 
+402,297 
+$ 
+48.24 
+289,385 
+$ 
+32.26 
+Granted 
+128,865 
+$ 
+40.31 
+241,745 
+$ 
+23.87 
+443,903 
+$ 
+53.81 
+Vested 
+(160,398 
+) 
+$ 
+46.30 
+(211,092 
+) 
+$ 
+46.26 
+(291,659 
+) 
+$ 
+22.92 
+Forfeited 
+(42,231 
+) 
+$ 
+35.43 
+(25,827 
+) 
+$ 
+50.35 
+(39,332 
+) 
+$ 
+37.82 
+Non-vested at end of year 
+333,359 
+$ 
+31.16 
+407,123 
+$ 
+34.67 
+402,297 
+$ 
+48.24 
+The total fair value of RSUs that vested during the years ended December 31, 2010, 2009, and 2008, was $7.4 million, $4.9 million, and $9.4 million, respectively. 
+Cash flows resulting from excess tax benefits are to be classified as part of cash flows from financing activities. Excess tax benefits are realized tax benefits from tax deductions for vested RSUs and exercised options in excess of the deferred tax asset attributable to stock compensation costs for such RSUs and options. The Company recorded $854,000 and $13.9 million of excess tax benefits for the years ended December 31, 2010, and 2008, respectively, as cash inflows from financing activities. The Company recorded no excess tax benefits for the year ended December 31, 2009. Cash received from exercises under all share-based payment arrangements for the years ended December 31, 2010, 2009, and 2008, was $4.8 million, $1.6 million, and $10.8 million, respectively. 
+Stock Option Grants Under the Equity Incentive Compensation Plan 
+The Company has previously granted stock options under the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan. The last issuance of stock options was December 31, 2004. Stock options to purchase shares of the Company’s common stock had been granted to eligible employees and members of the Board of Directors. All options granted under the option plans have been granted at exercise prices equal to the respective closing market price of the Company’s underlying common stock on the grant dates. All stock options granted under the option plans are exercisable for a period of up to ten years from the date of grant. 
+During the year ended December 31, 2008, the Company recognized general and administrative and exploration expense of $17,000 related to stock options that were outstanding and unvested. There was no expense associated with stock options or unvested stock options outstanding for the years ended December 31, 2010 and 2009. 
+F-25 
+A summary of activity associated with the Company’s Stock Option Plans during the last three years is presented in the following table: 
+Shares 
+Weighted - 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+For the year ended December 31, 2008 
+Outstanding, start of year 
+2,385,500 
+$ 
+12.62 
+Exercised 
+(868,372 
+) 
+$ 
+12.47 
+Forfeited 
+(7,418 
+) 
+$ 
+13.39 
+Outstanding, end of year 
+1,509,710 
+$ 
+12.69 
+$ 
+11,529,600 
+Vested at end of year 
+1,509,710 
+$ 
+12.69 
+$ 
+11,529,600 
+Exercisable, end of year 
+1,509,710 
+$ 
+12.69 
+$ 
+11,529,600 
+For the year ended December 31, 2009 
+Outstanding, start of year 
+1,509,710 
+$ 
+12.69 
+Exercised 
+(189,740 
+) 
+$ 
+8.40 
+Forfeited 
+(45,050 
+) 
+$ 
+13.38 
+Outstanding, end of year 
+1,274,920 
+$ 
+13.31 
+$ 
+26,684,106 
+Vested at end of year 
+1,274,920 
+$ 
+13.31 
+$ 
+26,684,106 
+Exercisable, end of year 
+1,274,920 
+$ 
+13.31 
+$ 
+26,684,106 
+For the year ended December 31, 2010 
+Outstanding, start of year 
+1,274,920 
+$ 
+13.31 
+Exercised 
+(346,377 
+) 
+$ 
+13.77 
+Forfeited 
+(7,778 
+) 
+$ 
+16.66 
+Outstanding, end of year 
+920,765 
+$ 
+13.11 
+$ 
+42,192,057 
+Vested at end of year 
+920,765 
+$ 
+13.11 
+$ 
+42,192,057 
+Exercisable, end of year 
+920,765 
+$ 
+13.11 
+$ 
+42,192,057 
+F-26 
+A summary of additional information related to options outstanding as of December 31, 2010, follows: 
+Options Outstanding and Exercisable 
+Range of 
+Exercise Prices 
+Number 
+Of Options 
+Outstanding 
+and 
+Exercisable 
+Weighted- 
+Average 
+Remaining 
+Contractual 
+Life 
+Weighted- 
+Average 
+Exercise 
+Price 
+$ 
+7.97 
+— 
+$ 
+10.60 
+94,456 
+0.9 years 
+$ 
+9.72 
+10.86 
+— 
+11.95 
+99,230 
+1.5 years 
+11.45 
+12.03 
+— 
+12.08 
+74,209 
+1.5 years 
+12.04 
+12.50 
+— 
+12.50 
+117,765 
+2.0 years 
+12.50 
+12.53 
+— 
+12.53 
+90,067 
+2.3 years 
+12.53 
+12.66 
+— 
+12.66 
+74,239 
+2.8 years 
+12.66 
+13.39 
+— 
+13.39 
+27,617 
+2.8 years 
+13.39 
+13.65 
+— 
+13.65 
+113,045 
+2.5 years 
+13.65 
+14.25 
+— 
+14.25 
+171,505 
+3.0 years 
+14.25 
+20.87 
+— 
+20.87 
+58,632 
+4.0 years 
+20.87 
+Total 
+920,765 
+The fair value of options was measured at the date of grant using the Black-Scholes Merton option-pricing model. 
+Director Shares 
+In 2010, 2009, and 2008, the Company issued 24,258, 50,094, and 23,113 shares, respectively, of restricted common stock from treasury to its non-employee directors pursuant to the Company’s Equity Plan. The Company recorded expense related to the issuances of shares to non-employee directors of $781,000, $688,000, and $1.0 million for the years ended December 31, 2010, 2009, and 2008, respectively. 
+Employee Stock Purchase Plan 
+Under the Company’s Employee Stock Purchase Plan (“the ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the six-month offering period, and shares issued under the ESPP through December 31, 2009, are restricted for a period of 18 months from the date issued. Effective January 1, 2010, shares issued under the ESPP are restricted for a six month period from the date issued. The ESPP is intended to qualify under Section 423 of the IRC. The Company has set aside 2,000,000 shares of its common stock to be available for issuance under the ESPP, of which 1,415,327 shares are available for issuance as of December 31, 2010. Shares issued under the ESPP totaled 52,948 in 2010, 86,308 in 2009, and 45,228 in 2008. Total proceeds to the Company for the issuance of these shares were $1.7 million in 2010, $1.5 million in 2009, and $1.1 million in 2008, respectively. 
+F-27 
+The fair value of ESPP shares are measured at the date of grant using the Black-Scholes option-pricing model. The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+Risk free interest rate 
+0.2 
+% 
+0.3 
+% 
+1.2 
+% 
+Dividend yield 
+0.3 
+% 
+0.5 
+% 
+0.2 
+% 
+Volatility factor of the expected market price of the Company’s common stock 
+46.3 
+% 
+95.1 
+% 
+81.5 
+% 
+Expected life (in years) 
+0.5 
+0.5 
+0.5 
+The Company expensed $550,000, $848,000, and $307,000 for the years ended December 31, 2010, 2009, and 2008, respectively, based on the estimated fair value of grants. 
+401(k) Plan 
+The Company has a defined contribution pension plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute up to 60 percent of their base salaries up to the contribution limits established under the IRC. The Company matches each employee’s contribution up to six percent of the employee’s base salary and may make additional contributions at its discretion. The Company’s contributions to the 401(k) Plan were $2.5 million, $2.5 million, and $2.0 million for the years ended December 31, 2010, 2009, and 2008, respectively. No discretionary contributions were made by the Company to the 401(k) Plan for any of these years. 
+Net Profits Plan 
+Under the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during a year were designated within a specific pool. Key employees recommended by senior management and designated as participants by the Company’s Compensation Committee of the Board of Directors and employed by the Company on the last day of that year became entitled to payments under the Net Profits Plan after the Company has received net cash flows returning 100 percent of all costs associated with that pool. Thereafter, ten percent of future net cash flows generated by the pool are allocated among the participants and distributed at least annually. The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the Company has recovered 200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the ten percent level. In December 2007 the Board discontinued the creation of new pools under the Net Profits Plan. Consequently, the 2007 Net Profits Plan pool was the last pool established by the Company. All pools are fully vested as of December 31, 2010. 
+Cash payments made under the Net Profits Plan that have been recorded as either general and administrative expense or exploration expense are detailed in the table below: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+General and administrative expense 
+$ 
+19,798 
+$ 
+18,399 
+$ 
+29,713 
+Exploration expense 
+2,633 
+1,463 
+6,604 
+Total 
+$ 
+22,431 
+$ 
+19,862 
+$ 
+36,317 
+F-28 
+Additionally, the Company made cash payments under the Net Profits Plan of $26.1 million, $724,000, and $15.1 million for the years ended December 31, 2010, 2009, and 2008, respectively, as a result of sales proceeds from divestitures. The cash payments are accounted for as a reduction in the gain on divestiture activity in the accompanying consolidated statements of operations. 
+The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate line item in the accompanying consolidated statements of operations. The change in the estimated liability is recorded as a non-cash expense or benefit in the current period. The amount recorded as an expense or benefit associated with the change in the estimated liability is not allocated to general and administrative expense or exploration expense because it is associated with the future net cash flows from oil and gas properties in the respective pools rather than results being realized through current period production. The table below presents the estimated allocation of the change in the liability if the Company did allocate the adjustment to these specific functional line items based on the current allocation of actual distributions made by the Company. As time progresses, less of the distributions relate to prospective exploration efforts as more of the distributions are made to employees that have terminated employment and do not provide ongoing exploration support to the Company. 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+General and administrative benefit 
+$ 
+30,399 
+$ 
+6,572 
+$ 
+29,672 
+Exploration benefit 
+4,042 
+503 
+4,368 
+Total 
+$ 
+34,441 
+$ 
+7,075 
+$ 
+34,040 
+Note 8 — Pension Benefits 
+Pension Plans 
+The Company has a non-contributory defined benefit pension plan covering substantially all employees who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan”). 
+The Company recognizes the funded status (i.e., the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s pension plan in the accompanying consolidated balance sheets as either an asset or a liability and recognizes a corresponding adjustment to accumulated other comprehensive income, net of tax. The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31. 
+F-29 
+Obligations and Funded Status for Both Pension Plans 
+For the Years Ended December 31, 
+2010 
+2009 
+(in thousands) 
+Change in benefit obligations 
+Projected benefit obligation at beginning of year 
+$ 
+18,550 
+$ 
+14,786 
+Service cost 
+3,392 
+2,500 
+Interest cost 
+1,120 
+934 
+Actuarial loss 
+2,480 
+1,275 
+Benefits paid 
+(1,675 
+) 
+(945 
+) 
+Projected benefit obligation at end of year 
+$ 
+23,867 
+$ 
+18,550 
+Change in plan assets 
+Fair value of plan assets at beginning of year 
+$ 
+9,101 
+$ 
+6,552 
+Actual return on plan assets 
+1,181 
+1,466 
+Employer contribution 
+1,725 
+2,028 
+Benefits paid 
+(1,675 
+) 
+(945 
+) 
+Fair value of plan assets at end of year 
+$ 
+10,332 
+$ 
+9,101 
+Funded status at end of year 
+$ 
+(13,535 
+) 
+$ 
+(9,449 
+) 
+The Company’s funded status for the Pension Plans for the years ended December 31, 2010, and 2009, is $13.5 million and $9.4 million, respectively, and is recognized in the accompanying consolidated balance sheets as a portion of other noncurrent liabilities. No plan assets of the Qualified Pension Plan were returned to the Company during the fiscal year ended December 31, 2010. There are no plan assets in the Nonqualified Pension Plan. 
+Information for Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets for Both Plans 
+As of December 31, 
+2010 
+2009 
+(in thousands) 
+Projected benefit obligation 
+$ 
+23,867 
+$ 
+18,550 
+Accumulated benefit obligation 
+$ 
+17,457 
+$ 
+13,278 
+Less: Fair value of plan assets 
+10,332 
+9,101 
+Underfunded accumulated benefit obligation 
+$ 
+7,125 
+$ 
+4,177 
+Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the interest cost on those liabilities, less the expected return on plan assets. The expected long-term rate on plan assets is applied to a calculated value of plan assets that recognizes changes in fair value over a five-year period. This practice is intended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences between actual returns on assets and expected returns based on long-term rate of return assumptions. Amortization of unrecognized net gain or loss resulting from experience different from that assumed and from changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of net periodic benefit cost for a year. If, as of the beginning of the year, that unrecognized net gain or loss exceeds ten percent of the greater of the projected benefit obligation and the market-related value of plan assets, the amortization is that excess divided by the average remaining service period of participating employees expected to receive benefits under the plan. 
+F-30 
+Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated other comprehensive income as of December 31, 2010, and 2009, consist of: 
+As of December 31, 
+2010 
+2009 
+(in thousands) 
+Unrecognized actuarial losses 
+$ 
+5,892 
+$ 
+4,322 
+Unrecognized prior service costs 
+— 
+— 
+Unrecognized transition obligation 
+— 
+— 
+Accumulated other comprehensive income 
+$ 
+5,892 
+$ 
+4,322 
+The estimated net loss that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year is $366,000. 
+Other pre-tax changes recognized in other comprehensive income during 2010, 2009, and 2008, were as follows: 
+As of December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Net actuarial loss 
+$ 
+(1,937 
+) 
+$ 
+(239 
+) 
+$ 
+(2,181 
+) 
+Less: Amortization of: 
+Prior service cost 
+— 
+— 
+— 
+Actuarial loss 
+(367 
+) 
+(358 
+) 
+(240 
+) 
+Total other comprehensive income 
+$ 
+(1,570 
+) 
+$ 
+119 
+$ 
+(1,941 
+) 
+Components of Net Periodic Benefit Cost for Both Pension Plans 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Components of net periodic benefit cost 
+Service cost 
+$ 
+3,392 
+$ 
+2,500 
+$ 
+2,229 
+Interest cost 
+1,120 
+934 
+889 
+Expected return on plan assets that reduces periodic pension cost 
+(638 
+) 
+(430 
+) 
+(565 
+) 
+Amortization of prior service cost 
+— 
+— 
+— 
+Amortization of net actuarial loss 
+367 
+372 
+248 
+Net periodic benefit cost 
+$ 
+4,241 
+$ 
+3,376 
+$ 
+2,801 
+Gains and losses in excess of ten percent of the greater of the benefit obligation and the market-related value of assets are amortized over the average remaining service period of active participants. 
+F-31 
+Pension Plan Assumptions 
+Weighted-average assumptions to measure the Company’s projected benefit obligation and net periodic benefit cost are as follows: 
+As of December 31, 
+2010 
+2009 
+2008 
+Projected benefit obligation 
+Discount rate 
+5.3 
+% 
+6.1 
+% 
+6.6 
+% 
+Rate of compensation increase 
+6.2 
+% 
+6.2 
+% 
+6.2 
+% 
+Net periodic benefit cost 
+Discount rate 
+6.1 
+% 
+6.6 
+% 
+6.1 
+% 
+Expected return on plan assets 
+7.5 
+% 
+7.5 
+% 
+7.5 
+% 
+Rate of compensation increase 
+6.2 
+% 
+6.2 
+% 
+6.2 
+% 
+The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans. The policy does not permit the direct investment of plan assets in the Company’s securities. The Company’s investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of diversification, assessment of risk, and targeting the optimal expected returns for given levels of risk are applied. 
+The Company’s investment portfolio contains a diversified blend of common stocks and bonds, which may reflect varying rates of return. The investments are further diversified within each asset classification. The portfolio diversification provides protection against a single security or class of securities having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a periodic basis to maintain the target allocations. The Company’s weighted-average asset allocation for the Qualified Pension Plan is as follows: 
+Target 
+As of December 31, 
+Asset Category 
+2011 
+2010 
+2009 
+Equity securities 
+60 
+% 
+60.8 
+% 
+61.3 
+% 
+Debt securities 
+40 
+% 
+39.2 
+% 
+38.7 
+% 
+Total 
+100.0 
+% 
+100.0 
+% 
+100.0 
+% 
+There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in that plan. An expected return on plan assets of 7.5 percent was used to calculate the Company’s obligation under the Qualified Pension Plan for 2010 and 2009. Factors considered in determining the expected return include the 60 percent equity and 40 percent debt securities mix of investment of plan assets and the long-term historical rate of return provided by the equity and debt securities markets. The difference in investment income using the projected rate of return compared to the actual rates of return for the past two years was not material and will not have a material effect on the statements of operations or cash flows from operating activities in future years. 
+F-32 
+Fair Value Assumptions 
+The Company’s pension plan assets consist of funds that have quoted net asset values within active markets. The individual funds are derived from quoted equity and debt securities within active markets with no judgment involved. As such, the funds are deemed to be Level 1. The fair value of the Company’s pension plan assets as of December 31, 2010, utilizing the fair value hierarchy discussed in Note 11 — Fair Value Measurements is as follows: 
+Assets: 
+Level 1 
+Level 2 
+Level 3 
+(in thousands) 
+Cash and Money Market Funds 
+$ 
+4 
+$ 
+— 
+$ 
+— 
+Equity Securities 
+Foreign Large Blend (1) 
+1,444 
+— 
+— 
+U.S. Small Blend (2) 
+1,647 
+— 
+— 
+U.S. Large Blend (3) 
+3,185 
+— 
+— 
+Fixed Income Securities 
+Intermediate Term Bond (4) 
+4,052 
+— 
+— 
+Total 
+$ 
+10,332 
+$ 
+— 
+$ 
+— 
+(1) 
+International equities are invested in companies that trade on active exchanges outside the U.S. and are well diversified among a dozen or more developed markets. Active and passive strategies are employed. 
+(2) 
+U.S. equities are invested in companies that are well diversified by industry sector and equity style, such as growth and value strategies, that trade on active exchanges within the U.S. Active and passive management strategies are employed. At least 80% of this fund is invested in equity securities of small companies. 
+(3) 
+U.S. equities include companies that are well diversified by industry sector and equity style, such as growth and value strategies, that trade on active exchanges within the U.S. Active and passive management strategies are employed. At least 80% of this fund is invested in equity securities designed to replicate the holdings and weightings of the stocks listed in the S&P 500 index. 
+(4) 
+Intermediate term bonds seek total return. At least 80% of this fund is invested in a diversified portfolio of bonds, which include all types of securities. It invests primarily in bonds of corporate and governmental issues located in the U.S. and foreign countries, including emerging markets all of which trade on active exchanges. 
+The fair value of the Company’s pension plan assets as of December 31, 2009, is as follows (see footnotes above): 
+Assets: 
+Level 1 
+Level 2 
+Level 3 
+(in thousands) 
+Cash and Money Market Funds 
+$ 
+4 
+$ 
+— 
+$ 
+— 
+Equity Securities 
+Foreign Large Blend (1) 
+1,365 
+— 
+— 
+U.S. Small Blend (2) 
+1,406 
+— 
+— 
+U.S Large Blend (3) 
+2,802 
+— 
+— 
+Fixed Income Securities 
+Intermediate Term Bond (4) 
+3,524 
+— 
+— 
+Total 
+$ 
+9,101 
+$ 
+— 
+$ 
+— 
+Contributions 
+The Company contributed $1.7 million, $2.0 million, and $2.5 million, to the Pension Plans in the years ended December 31, 2010, 2009, and 2008, respectively. The Company is required to make a $4.4 million contribution to the Pension Plans in 2011. 
+F-33 
+Benefit Payments 
+The Pension Plans made actual benefit payments of $1.7 million, $945,000, and $2.9 million in the years ended December 31, 2010, 2009, and 2008, respectively. Expected benefit payments over the next ten years are as follows (in thousands): 
+Years Ended December 31, 
+2011 
+$ 
+1,304 
+2012 
+1,377 
+2013 
+2,553 
+2014 
+2,697 
+2015 
+2,151 
+2016 through 2019 
+$ 
+20,512 
+Note 9 — Asset Retirement Obligations 
+The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement obligations is included in the operating section of the Company’s accompanying consolidated statements of cash flows. 
+The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s abandonment liabilities range from 6.5 percent to 12.0 percent. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives or if federal or state regulators enact new requirements regarding the abandonment of wells. 
+A reconciliation of the Company’s asset retirement obligation liability is as follows: 
+As of December 31, 
+2010 
+2009 
+(in thousands) 
+Beginning asset retirement obligation 
+$ 
+102,080 
+$ 
+116,274 
+Liabilities incurred 
+4,738 
+2,784 
+Liabilities settled 
+(30,523 
+) 
+(28,958 
+) 
+Accretion expense 
+5,583 
+8,673 
+Revision to estimated cash flows 
+971 
+3,307 
+Ending asset retirement obligation 
+$ 
+82,849 
+$ 
+102,080 
+As of December 31, 2010, and 2009, the Company had $2.1 million and $18.1 million, respectively, of asset retirement obligation associated with the oil and gas properties held for sale included in a separate line item on the Company’s consolidated balance sheets. Additionally, as of December 31, 2010, and 2009, accounts payable and accrued expenses contain $11.7 million and $23.7 million, respectively, related to the Company’s current asset retirement obligation liability associated with the estimated plugging and abandonment costs associated with one offshore platform that was destroyed during Hurricane Ike and multiple Gulf of Mexico platforms that are being relinquished or plugged. 
+F-34 
+Note 10 — Derivative Financial Instruments 
+Oil, Natural Gas and NGL Commodity Hedges 
+To mitigate a portion of the exposure to potentially adverse market changes in oil, gas, and NGL prices and the associated impact on cash flows, the Company has entered into various derivative contracts. The Company’s derivative contracts in place include swap and collar arrangements for oil, natural gas, and NGLs. As of December 31, 2010, the Company has hedge contracts in place through the third quarter of 2013 for a total of approximately 6 million Bbls of anticipated crude oil production, 35 million MMBtu of anticipated natural gas production, and 2 million Bbls of anticipated natural gas liquids production. As of February 18, 2011, the Company had hedge contracts in place through the fourth quarter of 2013 for a total of approximately 9 million Bbls of anticipated crude oil production, 44 million MMBtu of anticipated natural gas production, and 2 million Bbls of anticipated natural gas liquids production. 
+The Company attempts to qualify its oil, natural gas, and NGL derivative instruments as cash flow hedges for accounting purposes. The Company formally documents all relationships between the derivative instruments and the hedged production, as well as the Company’s risk management objective and strategy for the particular derivative contracts. This process includes linking all derivatives that are designated as cash flow hedges to the specific forecasted sale of oil, natural gas or NGLs. The Company also formally assesses (both at the derivative’s inception and on an ongoing basis) whether the derivatives being utilized have been highly effective in offsetting changes in the cash flows of hedged production and whether those derivatives may be expected to remain highly effective in future periods. If it is determined that a derivative has ceased to be highly effective as a hedge, the Company will discontinue hedge accounting for that derivative prospectively. If hedge accounting is discontinued and the derivative remains outstanding, the Company will recognize all subsequent changes in its fair value in the Company’s consolidated statements of operations for the period in which the change occurs. As of December 31, 2010, all oil, natural gas, and NGL derivative instruments qualified as cash flow hedges for accounting purposes. The Company anticipates that all forecasted transactions will occur by the end of their originally specified periods. All contracts are entered into for other than trading purposes. 
+Effective January 1, 2011 the Company has elected to de-designate all commodity hedges that had previously been designated as cash flow hedges as of December 31, 2010. Also, the Company has elected to discontinue hedge accounting prospectively. 
+The Company’s oil, natural gas, and NGL hedges are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The Company derives internal valuation estimates taking into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. Those internal valuations are then compared to the counterparties’ mark-to-market statements. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, natural gas, and NGL derivative markets are highly active. The fair value of oil, gas and NGL derivative contracts designated and qualifying as cash flow hedges was a net liability of $52.3 million and $80.9 million at December 31, 2010, and 2009, respectively. 
+F-35 
+The following table details the fair value of derivatives recorded in the consolidated balance sheets, by category: 
+Location on 
+Consolidated Balance 
+Sheets 
+Fair Value at 
+December 31, 2010 
+Fair Value at 
+December 31, 2009 
+(in thousands) 
+Derivative assets designated as cash flow hedges: 
+Commodity contracts 
+Current assets — 
+Derivative asset 
+$ 
+43,491 
+$ 
+30,295 
+Commodity contracts 
+Other noncurrent assets 
+— Derivative asset 
+18,841 
+8,251 
+Total derivative assets designated as cash flow hedges 
+$ 
+62,332 
+$ 
+38,546 
+Derivative liabilities designated as cash flow hedges: 
+Commodity contracts 
+Current liabilities — 
+Derivative liability 
+$ 
+(82,044 
+) 
+$ 
+(53,929 
+) 
+Commodity contracts 
+Noncurrent liabilities — 
+Derivative liability 
+(32,557 
+) 
+(65,499 
+) 
+Total derivative liabilities designated as cash flow hedges 
+$ 
+(114,601 
+) 
+$ 
+(119,428 
+) 
+Realized gains or losses from the settlement of oil, gas and NGL derivative contracts are reported in the total operating revenues section of the accompanying consolidated statements of operations. The Company realized a net gain of $23.5 million, a net gain of $140.6 million, and a net loss of $101.1 million from its oil, gas, and NGL derivative contracts for the years ended December 31, 2010, 2009, and 2008, respectively. 
+For the years ended December 31, 2010, 2009, and 2008, after-tax changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they were effective in offsetting cash flows attributed to the hedged risk, were recorded in accumulated other comprehensive income in the accompanying consolidated balance sheets until the hedged item was realized in earnings upon the sale of the associated hedged production. When hedges are de-designated from forecasted production, the amount of deferred gain or loss in Accumulated Other Comprehensive Income will freeze and will gradually decrease until the hedges once designated expire and are settled in cash. As of December 31, 2010, the amount of unrealized loss net of deferred income taxes to be reclassified from accumulated other comprehensive income to realized oil and gas hedge gain (loss) in the Company’s accompanying consolidated statements of operations in the next twelve months is $13.4 million. 
+Under cash flow hedge accounting, the Company attempted to minimize ineffectiveness by entering into oil derivative contracts indexed to the New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”) index, natural gas derivative contracts indexed to regional index prices associated with pipelines in proximity to the Company’s areas of production, and NGL derivative contracts indexed to OPIS Mont Belvieu. As the Company’s derivative contracts contain the same index as the Company’s sales contracts, this results in derivative contracts that are highly correlated with the underlying hedged item. 
+F-36 
+The following table details the effect of derivative instruments on other comprehensive income (loss) and the accompanying consolidated balance sheets (net of income tax): 
+Derivatives 
+Qualifying 
+as Cash 
+Flow 
+Hedges 
+Location on 
+Consolidated 
+Balance Sheets 
+For the Years 
+Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Amount of (gain) loss on derivatives recognized in OCI during the period (effective portion) 
+Commodity hedges 
+Accumulated 
+other 
+comprehensive 
+loss 
+$ 
+(16,811 
+) 
+$ 
+35,977 
+$ 
+(177,005 
+) 
+The following table details the effect of derivative instruments on other comprehensive income (loss) and the accompanying consolidated statements of operations (net of income tax): 
+Derivatives 
+Qualifying 
+as Cash 
+Flow 
+Hedges 
+Location on 
+Consolidated 
+Statements of 
+Operations 
+For the Years 
+Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Amount of (gain) loss reclassified from AOCI to realized oil and gas hedge gain (loss) (effective portion) 
+Commodity hedges 
+Realized oil 
+and gas hedge 
+gain (loss) 
+$ 
+6,641 
+$ 
+(67,344 
+) 
+$ 
+46,463 
+Any change in fair value resulting from hedge ineffectiveness is recognized in unrealized derivative (gain) loss in the accompanying consolidated statements of operations. The following table details the effect of derivative instruments on the accompanying consolidated statements of operations: 
+Derivatives Qualifying 
+as Cash Flow Hedges 
+Location on 
+Consolidated Statements 
+of Operations 
+(Gain) Loss Recognized in Earnings 
+(Ineffective Portion) 
+For the Years 
+Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Commodity hedges 
+Unrealized derivative 
+(gain) loss 
+$ 
+8,899 
+$ 
+20,469 
+$ 
+(11,209 
+) 
+Convertible Note Derivative Instrument 
+The contingent interest provision of the 3.50% Senior Convertible Notes is a derivative instrument. As of December 31, 2010 and 2009, the value of this derivative was determined to be immaterial. 
+F-37 
+Note 11 — Fair Value Measurements 
+The Company follows fair value measurement authoritative guidance for all assets and liabilities measured at fair value. That guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs: 
+· Level 1 — Quoted prices in active markets for identical assets or liabilities 
+· Level 2 — Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable 
+· Level 3 — Significant inputs to the valuation model are unobservable 
+The following is a listing of the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and where they are classified within the hierarchy as of December 31, 2010: 
+Level 1 
+Level 2 
+Level 3 
+(in thousands) 
+Assets: 
+Derivatives 
+$ 
+— 
+$ 
+62,332 
+$ 
+— 
+Liabilities: 
+Derivatives 
+$ 
+— 
+$ 
+114,601 
+$ 
+— 
+Net Profits Plan 
+$ 
+— 
+$ 
+— 
+$ 
+135,850 
+There were no nonfinancial assets or liabilities measured at fair value on a nonrecurring basis at December 31, 2010. 
+The following is a listing of the Company’s assets and liabilities that are measured at fair value and where they are classified within the hierarchy as of December 31, 2009: 
+Level 1 
+Level 2 
+Level 3 
+(in thousands) 
+Assets: 
+Derivatives(a) 
+$ 
+— 
+$ 
+38,546 
+$ 
+— 
+Proved oil and gas properties(b) 
+$ 
+— 
+$ 
+— 
+$ 
+11,740 
+Materials inventory(b) 
+$ 
+— 
+$ 
+13,882 
+$ 
+— 
+Liabilities: 
+Derivatives(a) 
+$ 
+— 
+$ 
+119,428 
+$ 
+— 
+Net Profits Plan(a) 
+$ 
+— 
+$ 
+— 
+$ 
+170,291 
+(a) 
+This represents a financial asset or liability that is measured at fair value on a recurring basis. 
+(b) 
+This represents a nonfinancial asset or liability that is measured at fair value on a nonrecurring basis. 
+Both financial and non-financial assets and liabilities are categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the hierarchy. 
+F-38 
+Derivatives 
+The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL hedges. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration the counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. 
+Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may ask counterparties to post collateral if their ratings deteriorate. In some instances the Company will attempt to novate the trade to a more stable counterparty. 
+Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any liability position with a counterparty. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date. The majority of the Company’s derivative counterparties are members of SM Energy’s credit facility bank syndicate. 
+The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with accounting authoritative guidance and with other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date. 
+Net Profits Plan 
+The Net Profits Plan is a standalone liability for which there is no available market price, principal market, or market participants. The inputs available for this instrument are unobservable, and therefore classified as Level 3 inputs. The Company employs the income approach, which converts expected future cash flow amounts to a single present value amount. This technique uses the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value. There is a direct correlation between realized oil and gas commodity prices driving net cash flows and the Net Profits Plan liability. Generally, higher commodity prices result in a larger Net Profits Plan liability and vice versa. 
+The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool. The calculation of this liability is a significant management estimate. For those pools currently in payout, a discount rate of 12 percent is used to calculate this liability. A discount rate of 15 percent is being used to calculate the liability for pools that have not reached payout. These rates are intended to represent the best estimate of the present value of expected future payments under the Net Profits Plan. 
+The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions, and the discount rates used in the calculations. The Company continually evaluates the assumptions used in this calculation in order to consider the current market environment for oil and gas prices, costs, discount rates, and overall market conditions. The Net Profits Plan liability was determined using price assumptions of five one-year strip prices with the fifth year’s pricing then carried out indefinitely. The average price was adjusted for realized price differentials and to include the effects of hedging for the percentage of forecasted production hedged in the relevant periods. The non-cash expense associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the crude oil, natural gas, and NGL commodity markets. 
+If the commodity prices used in the calculation changed by five percent, the liability recorded at December 31, 2010, would differ by approximately $12 million. A one percentage point decrease in the discount rate would result in an 
+F-39 
+increase to the liability of approximately $7 million, while a one percentage point increase in the discount rate would result in a decrease to the liability of approximately $6 million. Actual cash payments to be made to participants in future periods are dependent on realized actual production, realized commodity prices, and costs associated with the properties in each individual pool of the Net Profits Plan. Consequently, actual cash payments are inherently different from the amounts estimated. 
+No published market quotes exist on which to base the Company’s estimate of fair value of the Net Profits Plan liability. As such, the recorded fair value is based entirely on management estimates that are described within this footnote. While some inputs to the Company’s calculation of fair value on the Net Profits Plan’s future payments are from published sources, others, such as the discount rate and the expected future cash flows, are derived from the Company’s own calculations and estimates. The following table reflects the activity for the liabilities measured at fair value using Level 3 inputs: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Beginning balance 
+$ 
+170,291 
+$ 
+177,366 
+$ 
+211,406 
+Net increase in liability (a) 
+14,063 
+13,511 
+17,421 
+Net settlements (a) (b) 
+(48,504 
+) 
+(20,586 
+) 
+(51,461 
+) 
+Transfers in (out) of Level 3 
+— 
+— 
+— 
+Ending balance 
+$ 
+135,850 
+$ 
+170,291 
+$ 
+177,366 
+(a) 
+Net changes in the Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations. 
+(b) 
+Settlements represent cash payments made or accrued under the Net Profits Plan. Settlements for the year ended December 31, 2010, 2009, and 2008, include $26.1 million, $724,000, and $15.1 million respectively, of cash payments made related to divestitures. 
+3.50% Senior Convertible Notes Due 2027 
+Based on the market price of the 3.50% Senior Convertible Notes, the estimated fair value of the notes was approximately $351 million and $290 million as of December 31, 2010 and 2009, respectively. The fair value of the embedded contingent interest derivative was zero as of December 31, 2010, and 2009. 
+Proved Oil and Gas Properties 
+Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the Company’s management. The calculation of the discount rate is a significant management estimate based on the best information available and estimated to be 12 percent for the year ended December 31, 2010. Management believes that the discount rate is representative of current market conditions and includes the following factors: estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on NYMEX strip pricing, adjusted for basis differentials, for the first five years. Future operating costs are also adjusted as deemed appropriate for these estimates. There were no proved oil and gas properties measured at fair value within the accompanying consolidated balance sheets at December 31, 2010. There was $11.7 million of the $1.7 billion of proved oil and gas properties measured at fair value within the accompanying consolidated balance sheets at December 31, 2009. 
+Materials Inventory 
+Materials inventory is valued at the lower of cost or market. The Company uses Level 2 inputs to measure the fair value of materials inventory, which is primarily comprised of tubular goods. The Company uses third party market quotes and compares the quotes to the book value of the materials inventory. If the book value exceeds the quoted market price, the Company reduces the book value to the market price. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing materials inventory. There were no materials inventory measured at fair value within the accompanying consolidated balance sheets at 
+F-40 
+December 31, 2010. There was $13.9 million of the $24.5 million of materials inventory measured at fair value within the accompanying balance sheets at December 31, 2009. 
+Asset Retirement Obligations 
+The income valuation technique is utilized by the Company to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value within the accompanying consolidated balance sheets at December 31, 2010 and 2009. 
+Please refer to Note 10 — Derivative Financial Instruments, Note 9 — Asset Retirement Obligations, and Note 8 — Pension Benefits for more information regarding the Company’s hedging instruments, asset retirement obligations, and pension benefits. 
+Note 12 — Carry and Earning Agreement 
+On April 29, 2010, the Company entered into a Carry and Earning Agreement (the “CEA”), which effectively provides for a third party to earn 95 percent of SM Energy’s interest in approximately 8,400 net acres in a portion of the Company’s East Texas Haynesville shale acreage, as well as an interest in several wells and five percent of SM Energy’s interest in approximately 23,400 net acres in a separate portion of the Company’s Haynesville acreage in East Texas. In exchange for these interests, the third party has agreed to invest $91.3 million to fund the drilling and completion costs of horizontal wells in the portion of the leases where the Company is retaining 95 percent of its interest. Of this, $86.7 million represents SM Energy’s carried drilling and completion costs, which is 95 percent of the total well costs to be invested by the third party. The Company received an initial payment of $45.6 million on April 29, 2010, and a final payment of $45.1 million on December 30, 2010, after the completion of the fourth commitment well. Once SM Energy has completed the expenditure of the total carry amount, the parties will share all costs of operations within the area of joint ownership in accordance with their respective ownership interests. 
+Note 13 — Repurchase and Retirement of Common Stock 
+Stock Repurchase Program 
+In July 2006 the Company’s Board of Directors approved an increase of 5,473,182 shares to the remaining authorized number of shares that can be repurchased under the Company’s original authorization approved in August 1998, for a total number of shares authorized to be repurchased under the plan of 6,000,000. As of the date of this filing, the Company has Board authorization to repurchase up to 3,072,184 shares of common stock. The shares may be repurchased from time to time in open market transactions or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of SM Energy’s existing credit facility agreement, provisions under our 6.625 % Senior Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flows, and borrowings under the credit facility. The details for shares repurchased and retired are summarized as follows: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+Number of shares repurchased 
+— 
+— 
+2,135,600 
+Total purchase price, including commissions 
+$ 
+— 
+$ 
+— 
+$ 
+77,149,451 
+Weighted-average price, including commissions 
+$ 
+— 
+$ 
+— 
+$ 
+36.13 
+Number of shares retired 
+— 
+— 
+2,945,212 
+Remaining shares authorized to be repurchased 
+3,072,184 
+3,072,184 
+3,072,184 
+F-41 
+Note 14 — Oil and Gas Activities 
+Costs Incurred in Oil and Gas Producing Activities 
+Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Development costs 
+$ 
+299,308 
+$ 
+213,971 
+$ 
+581,615 
+Facility costs (1) 
+80,328 
+9,137 
+5,933 
+Exploration costs 
+443,888 
+154,122 
+92,199 
+Acquisitions 
+Proved properties 
+664 
+76 
+51,567 
+Unproved properties — acquisitions of proved properties 
+— 
+— 
+43,274 
+Unproved properties — other 
+53,192 
+41,677 
+83,078 
+Total, including asset retirement obligation(2)(3) 
+$ 
+877,380 
+$ 
+418,983 
+$ 
+857,666 
+(1) 
+Beginning December 31, 2010, facility costs are being disclosed separately within the development section of cost incurred. 
+(2) 
+Includes capitalized interest of $4.3 million, $1.9 million, and $4.7 million for the years ended December 31, 2010, 2009, and 2008, respectively. 
+(3) 
+Includes amounts relating to estimated asset retirement obligations of $5.8 million, $(805,000), and $15.4 million for the years ended December 31, 2010, 2009, and 2008, respectively. 
+Suspended Well Costs 
+The following table reflects the net changes in capitalized exploratory well costs during 2010, 2009, and 2008. The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same period: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Beginning balance on January 1, 
+$ 
+34,384 
+$ 
+9,437 
+$ 
+42,930 
+Additions to capitalized exploratory well costs pending the determination of proved reserves 
+35,862 
+34,384 
+9,437 
+Reclassifications to wells, facilities, and equipment based on the determination of proved reserves 
+(34,384 
+) 
+(7,569 
+) 
+(36,842 
+) 
+Capitalized exploratory well costs charged to expense 
+— 
+(1,868 
+) 
+(6,088 
+) 
+Ending balance at December 31, 
+$ 
+35,862 
+$ 
+34,384 
+$ 
+9,437 
+F-42 
+The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Exploratory well costs capitalized for one year or less 
+$35,862 
+$34,384 
+$9,437 
+Exploratory well costs capitalized for more than one year 
+— 
+— 
+— 
+Ending balance at December 31, 
+$35,862 
+$34,384 
+$9,437 
+Number of projects with exploratory well costs that have been capitalized more than a year 
+— 
+— 
+— 
+Note 15 — Disclosures about Oil and Gas Producing Activities (Unaudited) 
+Oil and Gas Reserve Quantities 
+Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. With respect to reserves as of dates prior to December 31, 2009, the applicable SEC definition of proved reserves was the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, meaning prices and costs as of the date the estimate is made. All of the Company’s proved reserves are located in North America. 
+F-43 
+The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. 
+Presented below is a summary of the changes in estimated proved reserves of the Company: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+Oil or 
+Condensate 
+Gas 
+Oil or 
+Condensate 
+Gas 
+Oil or 
+Condensate 
+Gas 
+(MMBbl) 
+(Bcf) 
+(MMBbl) 
+(Bcf) 
+(MMBbl) 
+(Bcf) 
+Total Proved Reserves 
+Beginning of year 
+53.8 
+449.5 
+51.4 
+557.4 
+78.8 
+613.5 
+Revisions of previous estimate(a) 
+3.1 
+6.1 
+4.5 
+(76.8 
+) 
+(22.6 
+) 
+(108.3 
+) 
+Discoveries and extensions 
+16.2 
+172.9 
+3.4 
+51.9 
+0.7 
+41.1 
+Infill reserves in an existing proved field 
+2.8 
+97.2 
+1.2 
+29.9 
+5.4 
+92.4 
+Purchases of minerals in place 
+— 
+0.2 
+— 
+— 
+0.4 
+27.0 
+Sales of reserves (b) 
+(12.1 
+) 
+(14.0 
+) 
+(0.4 
+) 
+(41.8 
+) 
+(4.7 
+) 
+(33.4 
+) 
+Production 
+(6.4 
+) 
+(71.9 
+) 
+(6.3 
+) 
+(71.1 
+) 
+(6.6 
+) 
+(74.9 
+) 
+End of year 
+57.4 
+640.0 
+53.8 
+449.5 
+51.4 
+557.4 
+Proved developed reserves 
+Beginning of year 
+48.1 
+342.0 
+47.1 
+433.2 
+68.3 
+426.6 
+End of year 
+46.0 
+411.0 
+48.1 
+342.0 
+47.1 
+433.2 
+Proved undeveloped reserves 
+Beginning of year 
+5.7 
+107.5 
+4.3 
+124.2 
+10.6 
+186.8 
+End of year 
+11.4 
+229.0 
+5.7 
+107.5 
+4.3 
+124.2 
+(a) 
+For the year ended December 31, 2010, of the 24.7 BCFE upward revision of previous estimate, 42.6 BCFE and (17.9) BCFE relate to price and performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2010, were $79.43 per Bbl and $4.38 per MMBTU for oil and natural gas, respectively. These prices were 30 percent and 13 percent higher, respectively, than the prices used in 2009. Performance revisions in 2010 resulted in a net 11.2 BCFE decrease in our estimate of proved reserves. While the company recognized positive performance revisions in every region on proved developed properties, we had approximately 19.3 BCFE of negative performance revisions related to estimated proved undeveloped reserves in primarily dry gas assets, resulting from lower gas prices and higher well costs on the economics of these assets. Lastly, the Company reduced estimated proved reserves by 6.7 BCFE by removing proved undeveloped reserves related to assets that reached aging limitations, as mandated by the SEC. For the year ended December 31, 2009, of the 49.6 BCFE downward revision of previous estimate, 12.0 BCFE and (61.6) BCFE relate to price and performance revisions, respectively. The largest portion of the performance revision related to producing properties in the Company’s Wolfberry tight oil program in the Permian Basin in West Texas. The Company also saw a downward performance revision related to certain Cotton Valley assets in our ArkLaTex region. For the year ended December 31, 2008, of the 244.2 BCFE downward revision of previous estimate, 199.7 BCFE and 44.5 BCFE relate to price and performance revisions, respectively. 
+(b) 
+The Company divested of certain non-core assets during 2010, 2009, and 2008. Please refer to Note 3 - Divestitures and Assets Held for Sale for additional information. 
+(c) 
+For the years ended December 31, 2010, 2009, and 2008, amounts included approximately 356, 370, and 659 MMcf respectively, representing the Company’s net underproduced gas balancing position. 
+Standardized Measure of Discounted Future Net Cash Flows 
+The Company follows applicable authoritative accounting guidance for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated quantities of oil and gas to be produced in the future. Each property the Company operates is also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are 
+F-44 
+computed using the current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. 
+Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved oil and gas reserves in place at the end of the period using year-end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by the central administrative office attributable to operating activities. 
+The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the standardized measure: 
+2010 
+2009 
+2008 
+Gas (per Mcf) 
+$ 
+5.54 
+$ 
+3.82 
+$ 
+4.88 
+Oil (per Bbl) 
+$ 
+70.60 
+$ 
+53.94 
+$ 
+33.91 
+The following summary sets forth the Company’s future net cash flows relating to proved oil and gas reserves based on the standardized measure. 
+As of December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Future cash inflows 
+$ 
+7,598,159 
+$ 
+4,620,735 
+$ 
+4,463,894 
+Future production costs 
+(2,512,091 
+) 
+(1,968,096 
+) 
+(1,866,821 
+) 
+Future development costs 
+(789,493 
+) 
+(387,722 
+) 
+(393,620 
+) 
+Future income taxes 
+(1,335,576 
+) 
+(515,953 
+) 
+(419,544 
+) 
+Future net cash flows 
+2,960,999 
+1,748,964 
+1,783,909 
+10 percent annual discount 
+(1,294,632 
+) 
+(732,997 
+) 
+(724,840 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+1,666,367 
+$ 
+1,015,967 
+$ 
+1,059,069 
+F-45 
+The principle sources of change in the standardized measure of discounted future net cash flows are: 
+For the Years Ended December 31, 
+2010 
+2009 
+2008 
+(in thousands) 
+Standardized measure, beginning of year 
+$ 
+1,015,967 
+$ 
+1,059,069 
+$ 
+2,706,914 
+Sales of oil and gas produced, net of production costs 
+(641,213 
+) 
+(409,153 
+) 
+(988,045 
+) 
+Net changes in prices and production costs 
+557,681 
+154,008 
+(2,033,674 
+) 
+Extensions, discoveries and other including infill reserves in an existing proved field, net of production costs 
+989,365 
+166,666 
+288,162 
+Purchase of minerals in place 
+804 
+— 
+33,215 
+Development costs incurred during the year 
+43,900 
+33,742 
+105,031 
+Changes in estimated future development costs 
+49,531 
+75,134 
+213,554 
+Revisions of previous quantity estimates 
+66,759 
+(96,354 
+) 
+(363,908 
+) 
+Accretion of discount 
+128,408 
+126,538 
+386,118 
+Sales of reserves in place 
+(151,315 
+) 
+(44,823 
+) 
+(198,514 
+) 
+Net change in income taxes 
+(409,848 
+) 
+(61,801 
+) 
+947,955 
+Changes in timing and other 
+16,328 
+12,941 
+(37,739 
+) 
+Standardized measure, end of year 
+$ 
+1,666,367 
+$ 
+1,015,967 
+$ 
+1,059,069 
+F-46 
+Note 16 — Quarterly Financial Information (Unaudited) 
+The Company’s quarterly financial information for fiscal 2010 and 2009 is as follows (in thousands, except per share amounts): 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Year Ended December 31, 2010 
+Total operating revenues 
+$ 
+360,135 
+$ 
+211,697 
+$ 
+226,884 
+$ 
+294,118 
+Total operating expenses 
+152,384 
+174,908 
+195,832 
+230,939 
+Income from operations 
+$ 
+207,751 
+$ 
+36,789 
+$ 
+31,052 
+$ 
+63,179 
+Income before income taxes 
+$ 
+201,093 
+$ 
+30,500 
+$ 
+24,798 
+$ 
+58,505 
+Net income 
+$ 
+126,178 
+$ 
+18,068 
+$ 
+15,452 
+$ 
+37,139 
+Basic net income per common share 
+$ 
+2.01 
+$ 
+0.29 
+$ 
+0.25 
+$ 
+0.59 
+Diluted net income per common share 
+$ 
+1.96 
+$ 
+0.28 
+$ 
+0.24 
+$ 
+0.56 
+Dividends declared per common share 
+$ 
+0.05 
+$ 
+— 
+$ 
+0.05 
+$ 
+— 
+Year Ended December 31, 2009 
+Total operating revenues 
+$ 
+199,220 
+$ 
+205,198 
+$ 
+185,787 
+$ 
+241,996 
+Total operating expenses 
+334,685 
+211,059 
+185,330 
+231,962 
+Income (loss) from operations 
+$ 
+(135,465) 
+$ 
+(5,861) 
+$ 
+457 
+$ 
+10,034 
+Income (loss) before income taxes 
+$ 
+(141,539) 
+$ 
+(13,419) 
+$ 
+(7,018) 
+$ 
+2,512 
+Net income (loss) 
+$ 
+(87,623) 
+$ 
+(8,322) 
+$ 
+(4,415) 
+$ 
+990 
+Basic net income (loss) per common share 
+$ 
+(1.41) 
+$ 
+(0.13) 
+$ 
+(0.07) 
+$ 
+0.02 
+Diluted net income (loss) per common share 
+$ 
+(1.41) 
+$ 
+(0.13) 
+$ 
+(0.07) 
+$ 
+0.02 
+Dividends declared per common share 
+$ 
+0.05 
+$ 
+— 
+$ 
+0.05 
+$ 
+— 
+F-47 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+SM ENERGY COMPANY 
+(Registrant) 
+Date: February 25, 2011 
+By: 
+/s/ ANTHONY J. BEST 
+Anthony J. Best 
+President, Chief Executive Officer, 
+and Director 
+GENERAL POWER OF ATTORNEY 
+KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints each of Anthony J. Best and A. Wade Pursell his or her true and lawful attorney-in-fact and agent with full power of substitution and resubstitution, and each with full power to act alone, for the undersigned and in his or her name, place and stead, in any and all capacities, to sign any amendments to this Annual Report on Form 10-K for the fiscal year ended December 31, 2010, and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorney-in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof. 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signature 
+Title 
+Date 
+/s/ ANTHONY J. BEST 
+President and Chief Executive Officer 
+February 25, 2011 
+Anthony J. Best 
+/s/ A. WADE PURSELL 
+Executive Vice President and Chief Financial Officer 
+February 25, 2011 
+A. Wade Pursell 
+/s/ MARK T. SOLOMON 
+Controller 
+February 25, 2011 
+Mark T. Solomon 
+/s/ WILLIAM D. SULLIVAN 
+Chairman of the Board of Directors 
+February 25, 2011 
+William D. Sullivan 
+Signature 
+Title 
+Date 
+/s/ BARBARA M. BAUMANN 
+Director 
+February 25, 2011 
+Barbara M. Baumann 
+/s/ LARRY W. BICKLE 
+Director 
+February 25, 2011 
+Larry W. Bickle 
+/s/ WILLIAM J. GARDINER 
+Director 
+February 25, 2011 
+William J. Gardiner 
+/s/ JULIO M. QUINTANA 
+Director 
+February 25, 2011 
+Julio M. Quintana 
+/s/ JOHN M. SEIDL 
+Director 
+February 25, 2011 
+John M. Seidl
\ No newline at end of file
diff --git a/raw/filings/0000893538/2010/0001104659-11-010268/filing_metadata.csv b/raw/filings/0000893538/2010/0001104659-11-010268/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..eb30c0d7543ef114599df1a34d3d1f5bbc691f5b
--- /dev/null
+++ b/raw/filings/0000893538/2010/0001104659-11-010268/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000893538,SM,SM Energy Co,10-K,2011-02-25,2010-12-31,2011-02-25T20:07:07.000Z,0001104659-11-010268,a11-3036_110k.htm,10-K,12782409,1,0,https://www.sec.gov/Archives/edgar/data/893538/000110465911010268/a11-3036_110k.htm,https://www.sec.gov/Archives/edgar/data/893538/000110465911010268/,2010,2010,1
diff --git a/raw/filings/0000893538/2010/0001104659-11-010268/item1.txt b/raw/filings/0000893538/2010/0001104659-11-010268/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2010/0001104659-11-010268/item13.txt b/raw/filings/0000893538/2010/0001104659-11-010268/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..1721e8d98331017267157836711665eef805441b
--- /dev/null
+++ b/raw/filings/0000893538/2010/0001104659-11-010268/item13.txt
@@ -0,0 +1,5 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+The information required by this Item is incorporated by reference to the information provided under the caption “Certain Relationships and Related Transactions,” and “Corporate Governance,” in SM Energy’s definitive proxy statement for the 2011 annual meeting of stockholders to be filed within 120 days from December 31, 2010. 
+89 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000893538/2010/0001104659-11-010268/item9a.txt b/raw/filings/0000893538/2010/0001104659-11-010268/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..6145ff61d1e50404d5e95a6f04a873b3f2d44707
--- /dev/null
+++ b/raw/filings/0000893538/2010/0001104659-11-010268/item9a.txt
@@ -0,0 +1,43 @@
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+We maintain a system of disclosure controls and procedures that are designed to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. 
+85 
+Table of Contents 
+We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures are effective for the purpose discussed above as of the end of the period covered by this Annual Report on Form 10-K. There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 
+86 
+Table of Contents 
+MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 
+To the Stockholders’ of SM Energy Company 
+Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that: 
+(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements. 
+Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. 
+Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework. 
+Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2010. 
+The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal controls over financial reporting. That report immediately follows this report. 
+/s/ ANTHONY J. BEST 
+/s/ A. WADE PURSELL 
+Anthony J. Best 
+A. Wade Pursell 
+President and Chief Executive Officer 
+Executive Vice President and Chief Financial Officer 
+February 25, 2011 
+February 25, 2011 
+87 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Board of Directors and Stockholders of 
+SM Energy Company and Subsidiaries 
+Denver, Colorado 
+We have audited the internal control over financial reporting of SM Energy Company and subsidiaries (the “Company”) as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2010, of the Company and our report dated February 25, 2011, expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company’s adoption of new accounting guidance. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 25, 2011 
+88 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000893538/2010/0001104659-11-010268/rp_note.txt b/raw/filings/0000893538/2010/0001104659-11-010268/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2010/0001104659-11-010268/rpt_disclosure.txt b/raw/filings/0000893538/2010/0001104659-11-010268/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..7e5a72e31030efc7104c7e8cb5288316fa7f424b
--- /dev/null
+++ b/raw/filings/0000893538/2010/0001104659-11-010268/rpt_disclosure.txt
@@ -0,0 +1,42 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+Policies and Procedures on Transactions with Related Persons 
+We have adopted a Policy and Procedures With Respect to Related Person Transactions (the "Related Person Policy"), which sets forth the
+policies and procedures for the Audit Committee's review of any transaction, arrangement, or relationship (including any indebtedness or guarantee of indebtedness) or series of similar transactions,
+arrangements, or relationships in which (1) we are a participant, (2) the aggregate amount involved will or may be expected to exceed $120,000, and (3) a related person has or
+will have a direct or indirect material interest. For purposes of the Related Person Policy, a "related person" means (1) any of our directors, executive officers, or nominees for director,
+(2) any stockholder that beneficially owns more than 5% of our outstanding shares of common stock, and (3) any immediate family member of any of the foregoing. The Audit
+Committee approves or ratifies only those transactions that it determines in good faith are in, or are not inconsistent with, the best interests of our company and its stockholders. 
+In
+determining whether to approve or ratify a transaction with a related person, the Audit Committee takes into account the factors it deems appropriate, which may include, among others,
+the benefits to us, the availability of other sources for comparable products or services, the impact on a director's independence in the event the related person is a director, and the extent of the
+related person's interest in the transaction. The policy also provides for the delegation of Audit Committee authority to the Chairman of the Audit Committee for any related person transaction
+requiring pre-approval or ratification between meetings of the Audit Committee. The Audit Committee reviews and assesses ongoing relationships with a related person on at least an annual
+basis to see that they are in compliance with the policy and remain appropriate. 
+In
+addition, our By-Laws provide that a director, officer, or employee of our company may not pursue for his or her own account a business or investment opportunity that he
+or she learned about through his or her affiliation with our company. Our By-Laws also provide that our officers or employees may not pursue for his or her own account an oil and gas
+opportunity that he or she independently learned about unless (1) with respect to an officer of our company, the officer's pursuit of the opportunity has been approved by the Board, and
+(2) with respect to a non-officer of our company, the employee's pursuit of the opportunity has been approved by a senior officer of our company with full knowledge of that
+opportunity. These restrictions do not apply to the acquisition of less than 1% of the publicly traded stock of another company. 
+Related Person Transactions 
+We recognize that transactions with related persons may raise questions among stockholders as to whether those transactions are
+consistent with our best interests and the interests of our stockholders. It is our policy to enter into or ratify such transactions only when the Board, acting through the Audit Committee or as
+otherwise described herein, determines that the transaction in question is in, or is not inconsistent with, the best interests of our company and its stockholders, including but not limited to
+situations where we may obtain products or services of a nature, quantity or quality, or on other terms, that are not readily available from alternative sources or when we provide products or services
+to related persons on an arm's length basis on terms comparable to those provided to unrelated third parties or on terms comparable to those provided to employees generally. Set forth below is a
+description of all transactions between our company and related persons since the beginning of January 1, 2010. 
+11 
+Table of Contents 
+Mr. Quintana
+is the President, Chief Executive Officer, and a director of TESCO Corporation, which designs, manufactures, and delivers technology based solutions for the upstream
+energy industry, including oilfield drilling technology, services, and equipment. We have an agreement with TESCO for the provision of services to us in connection with our drilling and completion
+operations. This agreement continues until canceled by either us or TESCO on 30 days advance written notice. Pursuant to this agreement, we are obligated to pay TESCO only for services actually
+performed. This agreement does not require us to make any other payments to TESCO. Prior to 2010, the services provided by TESCO and the amounts we paid did not exceed the threshold amount for review
+under our Related Person Policy. In May 2010, as part of its annual review of related party transactions, the Audit Committee reviewed the relationship between TESCO and our company and determined at
+such time that we had not paid any amounts to TESCO during 2010. During August 2010 through December 2010, TESCO provided services to us in our ArkLaTex region. In December 2010, the Audit Committee
+again reviewed the relationship between our company and TESCO, but the final 2010 amounts paid to or incurred to be paid to TESCO were not then available for review. Upon the later calculation of the
+final 2010 amounts paid to TESCO, we determined that we had paid TESCO $346,683 for services rendered after August 2010. In addition, as of March 31, 2011, we had paid TESCO $291,635 for
+services in 2011. Based upon these amounts, the Audit Committee reviewed the relationship between our company and TESCO and determined that the relationship is in the best interests of our company and
+its stockholders. 
+12 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000893538/2011/0000893538-12-000012/filing.txt b/raw/filings/0000893538/2011/0000893538-12-000012/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..cdf5d6a7c6df89c08da4dbcf399d26b6718a7a5d
--- /dev/null
+++ b/raw/filings/0000893538/2011/0000893538-12-000012/filing.txt
@@ -0,0 +1,7836 @@
+10-K
+1
+sm-20111231x10k.htm
+FORM 10-K
+SM-2011.12.31-10K 
+Table of Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+þ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 
+For the fiscal year ended December 31, 2011 
+or 
+o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 
+Commission file number 001-31539 
+SM ENERGY COMPANY 
+(Exact name of registrant as specified in its charter) 
+Delaware 
+(State or other jurisdiction 
+of incorporation or organization) 
+41-0518430 
+(I.R.S. Employer Identification No.) 
+1775 Sherman Street, Suite 1200, Denver, Colorado 
+(Address of principal executive offices) 
+80203 
+(Zip Code) 
+(303) 861-8140 
+(Registrant’s telephone number, including area code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+Common stock, $.01 par value 
+New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer þ 
+Accelerated filer o 
+Non-accelerated filer o (Do not check if a smaller reporting company) 
+Smaller reporting company o 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ 
+The aggregate market value of the 63,229,780 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the Company’s common stock on June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, of $73.48 per share, as reported on the New York Stock Exchange; was $4,646,124,234. Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the Company to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes. 
+As o f February 16, 2012 , the registrant had 64,114,366 shares of common stock outstanding, which is net of 81,067 treasury shares held by the registrant. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its 2012 annual meeting of stockholders to be filed within 120 days after December 31, 2011. 
+1 
+Table of Contents 
+TABLE OF CONTENTS 
+ITEM 
+PAGE 
+PART I 
+ITEMS 1. and 2. 
+BUSINESS and PROPERTIES 
+4 
+General 
+4 
+Strategy 
+4 
+Significant Developments in 2011 
+4 
+Outlook for 2012 
+5 
+Core Operational Areas 
+6 
+Reserves 
+9 
+Production 
+12 
+Productive Wells 
+13 
+Drilling Activity 
+13 
+Acreage 
+14 
+Delivery Commitments 
+15 
+Major Customers 
+15 
+Employees and Office Space 
+15 
+Title to Properties 
+16 
+Seasonality 
+16 
+Competition 
+16 
+Government Regulations 
+17 
+Cautionary Information about Forward-Looking Statements 
+20 
+Available Information 
+22 
+Glossary of Oil and Gas Terms 
+23 
+ITEM 1A. 
+RISK FACTORS 
+28 
+ITEM 1B. 
+UNRESOLVED STAFF COMMENTS 
+48 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+48 
+ITEM 4. 
+MINE SAFETY DISCLOSURES 
+48 
+PART II 
+49 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, 
+RELATED STOCKHOLDER MATTERS AND ISSUER 
+PURCHASES OF EQUITY SECURITIES 
+49 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+50 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF 
+FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+53 
+Overview of the Company 
+53 
+Financial Results of Operations and Additional Comparative Data 
+61 
+Comparison of Financial Results and Trends between 2011 and 2010 
+64 
+Comparison of Financial Results and Trends between 2010 and 2009 
+68 
+Overview of Liquidity and Capital Resources 
+71 
+Critical Accounting Policies and Estimates 
+81 
+Accounting Matters 
+84 
+Environmental 
+84 
+2 
+Table of Contents 
+TABLE OF CONTENTS 
+(Continued) 
+ITEM 
+PAGE 
+ITEM 7A. 
+QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT 
+MARKET RISK (included with the content of ITEM 7) 
+85 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+85 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS 
+ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+132 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+132 
+ITEM 9B. 
+OTHER INFORMATION 
+135 
+PART III 
+135 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE 
+GOVERNANCE 
+135 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+137 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL 
+OWNERS AND MANAGEMENT AND RELATED 
+STOCKHOLDER MATTERS 
+137 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, 
+AND DIRECTOR INDEPENDENCE 
+138 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+138 
+PART IV 
+140 
+ITEM 15. 
+EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
+140 
+3 
+Table of Contents 
+PART I 
+When we use the terms “SM Energy,” “the Company,” “we,” “us,” or “our,” we are referring to SM Energy Company and its subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business under Glossary of Oil and Gas Terms. Throughout this document we make statements that may be classified as “forward-looking.” Please refer to the Cautionary Information about Forward-Looking Statements section of this document for an explanation of these types of statements. 
+ITEMS 1. and 2. BUSINESS and PROPERTIES 
+General 
+We are an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids (also referred to as "oil", "gas", and "NGLs" throughout the document) in onshore North America, with a current focus on oil and liquids-rich resource plays. We were founded in 1908 and incorporated in Delaware in 1915. Our initial public offering of common stock was in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.” 
+Our principal offices are located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is (303) 861-8140. 
+Strategy 
+Our business strategy is focused on the early capture of resource plays in order to create and then enhance value for our shareholders, while maintaining a strong balance sheet. We strive to leverage industry leading exploration and leasehold acquisition teams to quickly acquire and test new resource play concepts at a reasonable cost. Once we have captured potential value through these efforts, our goal is to develop such potential through top tier operational and project execution. We continually examine our portfolio for opportunities to improve the quality of our asset base in order to improve our returns and preserve our financial strength. 
+Significant Developments in 2011 
+• 
+Resource Play Delineation and Development Results in Record Production and Increase in Year-End Proved Reserve Estimates. Our estimated proved reserves increased 28 percent to 1,259.2 BCFE at December 31, 2011, from 984.5 BCFE at December 31, 2010. We added 526.1 BCFE through drilling activity during the year, which was primarily led by our efforts in the Eagle Ford shale in South Texas, the Bakken/Three Forks plays in North Dakota, and the Haynesville shale in East Texas. We achieved record levels of production in 2011. Our average daily production was composed of 274.8 MMcf of gas, 22.1 MBbl of oil, and 9.6 MBbl of NGLs for an average equivalent production rate of 465.0 MMCFE per day, which was an increase of 54 percent from 301.4 MMCFE per day in 2010. Costs incurred in 2011 for drilling and exploration activities and acquisitions increased 77 percent , to $1.6 billion , compared with $877.4 million in 2010. The increase in capital investment reflects increased confidence in our drilling inventory, particularly in plays with significant oil and NGL-rich gas components, such as our Eagle Ford shale and Bakken/Three Forks plays. Please refer to Core Operational Areas below for additional discussion concerning our 2011 estimated proved reserves, production, and capital investment. 
+• 
+Acquisition and Development Agreement. In December 2011, we closed on our Acquisition and Development Agreement with Mitsui E&P Texas LP ("Mitsui"), an indirect subsidiary of Mitsui & Co. Ltd., which transferred 12.5 percent of our working interest in certain non-operated oil and gas assets in South Texas. Under the agreement, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs for wells targeting the Eagle Ford shale attributable to our remaining interests in these assets, until Mitsui has expended an aggregate of $680.0 million on our behalf. Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement in Part II, Item 8 of this report for additional discussion concerning this transaction. 
+• 
+Financing Activities. During 2011, our financing activities consisted of the following transactions: 
+4 
+Table of Contents 
+• 
+issuance of $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2019 ("6.625% Senior Notes"); 
+• 
+issuance of $350.0 million in aggregate principal amount of 6.50% Senior Notes due 2021 ("6.50% Senior Notes"); and 
+• 
+execution of a $2.5 billion Fourth Amended and Restated Credit Agreement with a borrowing base of $1.3 billion and lender commitments of $1.0 billion , as of December 31, 2011. 
+Please refer to Note 5 - Long-term Debt in Part II, Item 8 of this report for additional discussion regarding our financing arrangements. 
+• 
+Impairments. We recognized $219.0 million of proved property impairments for the year ended December 31, 2011. A significant decrease in natural gas prices during the second half of 2011 led to the impairment of certain dry gas assets in our ArkLaTex region. 
+• 
+Divestiture Activity. We continuously look to improve the quality of our asset portfolio through the divestiture of non-strategic properties. Our divestiture activity helps to generate cash that can be used to fund the development of assets with higher potential value and for other general corporate purposes. Often, but not always, we divest of properties with higher operating costs and/or limited future drilling or development potential. During 2011, we sold 93.1 BCFE of reserves, the majority of which related to assets located in our South Texas & Gulf Coast region. The following transactions represent our most significant divestitures during 2011: 
+• 
+Eagle Ford Shale Divestiture. In August 2011 , we completed the divestiture of certain operated Eagle Ford shale assets located in our South Texas & Gulf Coast region. This position comprised our entire operated acreage in LaSalle County, Texas, as well as an immaterial adjacent block of our operated acreage in Dimmit County, Texas. Total divestiture proceeds, before marketing costs, Net Profits Interest Bonus Plan ("Net Profits Plan") payments, and legal fees (referred to subsequently as "divestiture proceeds"), were $230.8 million . The estimated gain on this divestiture was $194.6 million and post-closing adjustments, if any, are expected to be finalized in the first quarter of 2012. 
+• 
+Mid-Continent Divestiture. In June 2011 , we completed the divestiture of certain non-strategic assets located in our Mid-Continent region. Total divestiture proceeds were $35.8 million . The estimated gain on this divestiture was $28.5 million and post-closing adjustments, if any, are expected to be finalized in the first quarter of 2012. 
+• 
+Rocky Mountain Divestiture. In January 2011 , we completed the divestiture of certain non-strategic assets located in our Rocky Mountain region. Total divestiture proceeds were $45.5 million . The final gain on this divestiture was $27.2 million . 
+Outlook for 2012 
+We enter 2012 with a capital program expected to be in the range of approximately $1.4 billion to $1.5 billion, of which approximately $1.2 billion to $1.3 billion will be allocated to drilling and completion activities focused primarily on the development of our inventory of resource play opportunities. Please refer to Core Operational Areas below for detailed discussion of our 2012 capital budget by region and Outlook for 2012 under Part II, Item 7 of this report for additional discussion surrounding our capital plans for 2012. 
+As we enter 2012, we are well positioned both financially and operationally. From a financial perspective, we believe that we are adequately capitalized and have sufficient liquidity to fund our planned capital expenditures for this year. Operationally, we have secured the majority of the drilling rigs and services required to execute our 2012 business plan. 
+5 
+Table of Contents 
+Core Operational Areas 
+Our operations are concentrated in five core operating areas in the onshore United States. The following table summarizes estimated proved reserves, PV-10 reserve value, and production for the year ended December 31, 2011, for our core operating areas: 
+ArkLaTex 
+Mid- 
+Continent 
+South Texas & Gulf Coast 
+Permian 
+Rocky 
+Mountain 
+Total (1) 
+Proved Reserves 
+Oil (MMBbl) 
+0.3 
+0.8 
+14.6 
+12.4 
+43.7 
+71.7 
+Gas (Bcf) 
+124.0 
+223.9 
+243.0 
+31.7 
+41.5 
+664.0 
+NGLs (MMBbl) 
+0.9 
+1.0 
+25.5 
+0.2 
+— 
+27.5 
+Equivalents (BCFE) 
+130.6 
+234.6 
+483.6 
+107.0 
+303.4 
+1,259.2 
+Relative percentage 
+10 
+% 
+19 
+% 
+38 
+% 
+9 
+% 
+24 
+% 
+100 
+% 
+Proved Developed % 
+76 
+% 
+75 
+% 
+54 
+% 
+86 
+% 
+71 
+% 
+67 
+% 
+PV-10 Values (in millions) (2) 
+Proved Developed 
+$ 
+173.7 
+$ 
+353.9 
+$ 
+857.7 
+$ 
+459.8 
+$ 
+991.2 
+$ 
+2,836.3 
+Proved Undeveloped (3) 
+16.9 
+42.3 
+294.5 
+51.4 
+219.8 
+624.9 
+Total Proved 
+$ 
+190.6 
+$ 
+396.2 
+$ 
+1,152.2 
+$ 
+511.2 
+$ 
+1,211 
+$ 
+3,461.2 
+Relative percentage 
+6 
+% 
+11 
+% 
+33 
+% 
+15 
+% 
+35 
+% 
+100 
+% 
+Production 
+Oil (MMBbl) 
+0.1 
+0.4 
+2.6 
+1.3 
+3.7 
+8.1 
+Gas (Bcf) 
+29.3 
+28.6 
+34.7 
+3.5 
+4.2 
+100.3 
+NGLs (MMBbl) 
+0.1 
+0.1 
+3.2 
+— 
+— 
+3.5 
+Equivalent (BCFE) 
+30.1 
+31.6 
+69.7 
+11.5 
+26.7 
+169.7 
+Avg. Daily Equivalents 
+(MMCFE/d) 
+82.5 
+86.7 
+191.1 
+31.5 
+73.3 
+465.0 
+Relative percentage 
+18 
+% 
+19 
+% 
+41 
+% 
+6 
+% 
+16 
+% 
+100 
+% 
+(1) 
+Totals may not sum due to rounding. 
+(2) 
+The standardized measure PV-10 calculation is presented in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown in the Reserves section below. 
+(3) 
+We record estimates of proved undeveloped reserves for locations with a positive PV-0 value when we have the intent to drill the location and it meets our economic criteria. 
+South Texas & Gulf Coast Region. Operations for the South Texas & Gulf Coast region are managed from our office in Houston, Texas. Our current operations in this region focus primarily on our Eagle Ford shale program. Our acreage position covers a significant portion of the western Eagle Ford shale play, including acreage in the oil, the NGL-rich gas, and the dry gas windows of the play. We entered 2011 with approximately 250,000 net acres in the play, which was comprised of an approximate 165,000 net acre operated position in Webb, Dimmit, and LaSalle Counties, Texas and an approximate 85,000 net acre non-operated position in Maverick, Dimmit, LaSalle, and Webb Counties, Texas. During the year we reduced our acreage in two separate transactions. The first transaction was a sale of approximately 15,400 net operated acres in LaSalle and Dimmit Counties, Texas to Talisman Energy USA Inc. and Statoil Texas Onshore Properties LLC (collectively, "Talisman/Statoil") for $225.0 million, which closed in August 2011. The second transaction, which reduced our working interest from approximately 27.0 percent to approximately 14.5 percent, was our assignment of approximately 39,000 net acres in our non-operated program to Mitsui in exchange for Mitsui's agreement to carry 90 percent of our drilling and completion costs until Mitsui has expended $680.0 million for our benefit. This transaction closed in December 2011. These two transactions allowed us to consolidate our operating foot print in the play and, by divesting of a significant piece of our non-operated program, put a greater percentage of our capital expenditures in this play under our operational control. As of December 31, 2011, we have roughly 196,000 net acres in the play. 
+6 
+Table of Contents 
+Approximately 75 percent of this acreage is operated by us with an average working interest of nearly 100 percent. On our operated acreage position, we increased our rig count over the course of the year from two rigs at the beginning of the year to five drilling rigs by year end. During the year, we also increased our contracted firm transportation capacity for our operated wet gas volumes to approximately 225 MMcf from approximately 100 MMcf. In 2012, our firm transportation capacity will continue to increase, which we expect will allow us to exit the year with approximately 270 MMcf of gross wet gas firm transportation capacity. In our non-operated Eagle Ford shale program, the operator of the program increased its rig count from seven at the beginning of 2011 to ten by year-end. We participated in substantially all of the drilling activity in the non-operated Eagle Ford shale program during the year. Additionally, we participated as a co-owner in the construction of midstream assets that service our non-operated acreage in the play. 
+Nearly all of our capital deployed in the South Texas & Gulf Coast region in 2011 targeted our Eagle Ford shale program. Our capital investment, production, and reserves all increased significantly in 2011 as a result of our focused efforts in our Eagle Ford shale program, which has become a critical growth driver of production and reserve growth for the Company. Our capital expenditures for exploration, development, and acquisition activities in our South Texas & Gulf Coast region increased significantly from $456.2 million in 2010 to $932.3 million in 2011. Production in 2011 was 69.7 BCFE, an increase of 207 percent over the 22.7 BCFE produced in 2010. Estimated proved reserves at the end of 2011 increased 133 percent to 483.6 BCFE from 207.3 BCFE in the prior year, while reflecting the reduction of 70.2 BCFE of proved reserves as a result of our transactions with Mitsui and Talisman/Statoil. Of the reserve additions in the region, approximately 353.3 BCFE of proved reserves were added through drilling activities. The increase in production and proved reserves reflects the significant increase in activity in our Eagle Ford shale program throughout the year. 
+Our plan for 2012 in the South Texas & Gulf Coast region is to continue focusing primarily on the Eagle Ford shale. At the beginning of 2012, we had five operated rigs, two of which are designed for pad drilling. We expect to operate five to six drilling rigs throughout 2012, with an increasing number of those rigs being capable of pad drilling. We believe that we have sufficient access to drilling rigs and completion services to execute our plan for the year. A significant portion of the gas takeaway capacity we will need for 2012 has been secured under firm transportation contracts. In the non-operated portion of our Eagle Ford shale position, the operator has indicated that it plans to operate approximately ten drilling rigs throughout 2012. 
+We have allocated a range of $650 million to $700 million of our 2012 capital budget to our operated Eagle Ford shale drilling program. Most of our drilling and completion costs in the non-operated portion of our Eagle Ford shale program will be carried by Mitsui during 2012 under the terms of our Acquisition and Development Agreement with Mitsui, although we will be responsible for our proportionate share of any infrastructure investments made in this program. 
+Rocky Mountain Region. Operations for our Rocky Mountain region are managed from our office in Billings, Montana. Our capital expenditures in 2011 primarily targeted the Bakken/Three Forks formations in the North Dakota portion of the Williston Basin, where we have approximately 87,000 net acres. In 2011, we were successful in testing prospects farther west and north of our prior development activity in North Dakota. In our Raven and Bear Den prospects, our efforts have largely centered on optimizing our completions and spacing for development of the Bakken formation. In our Gooseneck prospect in Divide County, North Dakota, our efforts have been focused on the Three Forks formation. Elsewhere in the Rocky Mountain region, we drilled several test wells in the Niobrara formation in Wyoming during the year. At year-end 2011, we had 91,000 net acres with potential for the Niobrara and other formations in the northern DJ and Powder River Basins. 
+Our capital expenditures for exploration, development, and acquisition activity in our Rocky Mountain region increased from $158.5 million in 2010 to $288.0 million in 2011, as we accelerated our activity in the Bakken/Three Forks formations and commenced testing of our Niobrara acreage. Estimated proved reserves for our Rocky Mountain region were 303.4 BCFE at year-end 2011, compared with 231.8 BCFE as of the end of 2010, a 31 percent increase over 2010. During the year, we added approximately 105.3 BCFE of proved reserves through drilling activities. Our program targeting the Bakken/Three Forks formations contributed the majority of our proved reserve additions in this region. Total regional production for 2011 was up seven percent to 26.7 BCFE, 
+7 
+Table of Contents 
+despite weather related delays throughout the region, including unusually severe spring flooding and wet weather which hindered production and drilling activity through the summer. As these issues subsided, we were able to increase activity and complete most of our planned activity for the year. 
+Our capital budget for operated Bakken/Three Forks activity in 2012 is a range of $160 million and $185 million. We expect to operate four rigs in the play, up from three rigs at the end of 2011. Our drilling activity will be focused on holding our acreage in the Raven and Gooseneck prospects and will also include infill wells in our Bear Den prospect along the Nesson Anticline. We also expect to participate in a number of Bakken/Three Forks projects with other operators. In addition to Bakken/Three Forks drilling, we plan to split one operated rig between our two prospect areas located in the northern DJ Basin and the Powder River Basin in Wyoming. 
+Mid-Continent Region. Operations for our Mid-Continent region are managed from our office in Tulsa, Oklahoma. Our current operations in the Mid-Continent region are primarily focused on the horizontal development of the Granite Wash formation in western Oklahoma. Our Mid-Continent region also manages our Woodford shale assets, on which we have minimized activity due to the low natural gas price environment. Our 2011 Granite Wash program targeted the shallower, more NGL-rich washes of our approximate 29,000 net acres in the play, the majority of which is held by production. In 2011, we incurred costs of $87.8 million in the Mid-Continent region for exploration, development, and acquisition activity, which is a 30 percent decrease from the $124.5 million incurred in 2010 for the region. In 2011, our Mid-Continent region's production was 31.6 BCFE, a decrease from the 33.4 BCFE produced in 2010. Proved reserves at the end of 2011 were 234.6 BCFE, a decrease of 20 percent from the 293.7 BCFE reported for 2010. 
+We plan to invest between $60 million and $70 million in 2012 in our operated horizontal Granite Wash program, with three operated drilling rigs planned to execute our drilling program for the year. No meaningful activity is required or expected in our Woodford shale program in 2012 due to our current outlook for natural gas prices. However, an increase in natural gas prices or a decrease in the costs of drilling and completing these wells could result in increased activity in the Woodford shale program. 
+ArkLaTex Region. Operations for our ArkLaTex region have historically been managed from our office in Shreveport, Louisiana. In the second half of 2011, we began consolidating our ArkLaTex and Mid-Continent regional offices into our office in Tulsa, Oklahoma. Our recent focus of the ArkLaTex region has been the horizontal development of our Haynesville shale acreage and achieving held by production status on our operated acreage position in East Texas. From a strategic standpoint, we believe holding this acreage, which is prospective for the Haynesville and Bossier shales, will provide value for us in the future if the economics for natural gas improve. 
+In 2011, we incurred costs of $159.2 million in the ArkLaTex region for exploration, development, and acquisition activity, which is a 234 percent increase from the $47.6 million incurred in 2010 for the region and is a result of our significant increase in capital expenditures in our operated Haynesville shale program to achieve held by production status. In 2011, production in our ArkLaTex region was 30.1 BCFE, a 109 percent increase from the 14.4 BCFE produced in 2010. Proved reserves at the end of 2011 were 130.6 BCFE, a decrease from the 137.9 BCFE reported for the prior year. 
+With the recent decline in natural gas prices, we have reduced our planned level of operated drilling activity in the Haynesville shale. Several operated wells that were previously planned for have been cut from the drilling schedule and we now expect to only invest between $35 million and $40 million on operated Haynesville shale drilling in 2012. This will result in the forfeiture of a small amount of operated acreage. After completing currently planned activity, we think that nearly 80 percent of our Haynesville acreage will be held by production, and we then plan to limit activity until gas prices recover or drilling costs lessen to a point that drilling projects meet our internal economic hurdles. 
+Permian Region. Operations for our Permian region are managed from our office in Midland, Texas. Our Permian region covers western Texas and eastern New Mexico. Our primary area of development focus in this region is the Wolfberry tight oil play, and we are actively working to delineate a newer exploratory play targeting 
+8 
+Table of Contents 
+the Mississippian limestone play. 
+We incurred costs of $80.7 million in the region for exploration, development, and acquisition activity in 2011 compared to $85.4 million in 2010. During the year, downspacing activity continued across our Wolfberry acreage. In addition, during 2011 we began testing acreage in Lynn, Borden, and Garza Counties, Texas targeting the vertical and horizontal development of the Mississippian limestone play. The region’s 2011 production was 11.5 BCFE, a decrease from 2010 production of 14.7 BCFE. The decrease in production was due to natural decline in the Wolfberry play as the field development matured and the number of remaining drilling locations on our acreage decreased. Proved reserves in this region as of the end of 2011 were 107.0 BCFE, which was a slight decline from 2010 year-end reserves of 113.9 BCFE. 
+During 2012, we plan to focus our Permian investment on further delineation of the Mississippian limestone play. A portion of our remaining capital allocated to this region will be spent on the development of our Wolfberry acreage. 
+Reserves 
+The table below presents summary information with respect to the estimates of our proved reserves for each of the years in the three-year period ended December 31, 2011. We engaged Ryder Scott Company, L.P. (“Ryder Scott”) to audit internal engineering estimates for at least 80 percent of the PV-10 value of our estimated proved reserves in each year presented. The prices used in the calculation of proved reserve estimates as of December 31, 2011, were $96.19 per Bbl for oil, $4.12 per MMBtu for natural gas, and $59.37 per Bbl for NGLs. 
+We emphasize that reserve estimates are inherently imprecise and that reserve estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved reserves owned by us. Neither prices nor costs have been escalated. The following table should be read along with the section entitled Risk Factors – Risks Related to Our Business contained herein. The actual quantities and present values of our estimated proved reserves may be less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year. 
+Our ability to replace our production is important to our sustainability. Please refer to the reserve replacement terms in the Glossary of Oil and Gas Terms section of this report for information describing how our reserve replacement metrics are calculated. Our reserve replacement percentages are calculated using information from the Oil and Gas Reserve Quantities section of Supplemental Oil and Gas Information located in Part II, Item 8 of this report. 
+9 
+Table of Contents 
+We believe the concept of reserve replacement as described in the Glossary of Oil and Gas Terms section of this report, as well as permutations which may include other captions of the Oil and Gas Reserve Quantities section of Supplemental Oil and Gas Information located in Part II, Item 8 of this report, are widely understood by those who make investment decisions related to the oil and gas exploration business. 
+As of December 31, 
+2011 
+2010 
+2009 
+Reserve data: 
+Proved developed 
+Oil (MMBbl) 
+50.3 
+46.0 
+48.1 
+Gas (Bcf) 
+451.2 
+411.0 
+342.0 
+NGLs (MMBbl) 
+15.2 
+- 
+- 
+BCFE 
+844.0 
+687.3 
+630.3 
+Proved undeveloped 
+Oil (MMBbl) 
+21.4 
+11.4 
+5.7 
+Gas (Bcf) 
+212.8 
+229.0 
+107.5 
+NGLs (MMBbl) 
+12.3 
+- 
+- 
+BCFE 
+415.2 
+297.2 
+141.9 
+Total Proved 
+Oil (MMBbl) 
+71.7 
+57.4 
+53.8 
+Gas (Bcf) 
+664.0 
+640.0 
+449.5 
+NGLs (MMBbl) 
+27.5 
+- 
+- 
+BCFE 
+1,259.2 
+984.5 
+772.2 
+Proved developed reserves % 
+67 
+% 
+70 
+% 
+82 
+% 
+Proved undeveloped reserves % 
+33 
+% 
+30 
+% 
+18 
+% 
+Reserve value data (in millions): 
+Proved developed PV-10 
+$ 
+2,836.3 
+$ 
+2,053.5 
+$ 
+1,253.1 
+Proved undeveloped PV-10 
+624.9 
+290.8 
+31.0 
+Total proved PV-10 
+$ 
+3,461.2 
+$ 
+2,344.3 
+$ 
+1,284.1 
+Standardized measure of discounted future cash flows 
+$ 
+2,580.0 
+$ 
+1,666.4 
+$ 
+1,016.0 
+Reserve replacement – drilling , excluding revisions 
+310 
+% 
+349 
+% 
+100 
+% 
+All in – including sales of reserves 
+262 
+% 
+293 
+% 
+14 
+% 
+All in – excluding sales of reserves 
+317 
+% 
+372 
+% 
+55 
+% 
+Reserve life (years) (1) 
+7.4 
+8.9 
+7.1 
+(1) Reserve life represents the estimated proved reserves at the dates indicated divided by actual production for the preceding 12-month period. 
+Note: NGL reserve data, production volumes, revenues, and prices for prior periods have not been reclassified to conform to the current presentation given the immateriality of the volumes in prior periods. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices under Part II, Item 7 of this report. 
+10 
+Table of Contents 
+The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 value (Non-GAAP). The difference is a result of the PV-10 value measure excluding the impact of income taxes. Please see the definitions of standardized measure of discounted future net cash flows and PV-10 value in the Glossary of Oil and Gas Terms . 
+As of December 31, 
+2011 
+2010 
+2009 
+(in millions) 
+Standardized measure of discounted future net cash flows 
+$ 
+2,580.0 
+$ 
+1,666.4 
+$ 
+1,016.0 
+Add: 10 percent annual discount, net of income taxes 
+1,727.6 
+1,294.6 
+733.0 
+Add: future undiscounted income taxes 
+1,740.4 
+1,335.5 
+515.9 
+Undiscounted future net cash flows 
+$ 
+6,048.0 
+$ 
+4,296.5 
+$ 
+2,264.9 
+Less: 10 percent annual discount without tax effect 
+(2,586.8 
+) 
+(1,952.2 
+) 
+(980.8 
+) 
+PV-10 value 
+$ 
+3,461.2 
+$ 
+2,344.3 
+$ 
+1,284.1 
+Proved Undeveloped Reserves 
+As of December 31, 2011, we had 415.2 BCFE of proved undeveloped reserves, which is an increase of 118.0 BCFE, or 40 percent, over proved undeveloped reserves of 297.2 BCFE at December 31, 2010. We added 202.2 BCFE of proved undeveloped reserves through our drilling program, 187.5 BCFE of which were extensions and discoveries, primarily in the Eagle Ford shale and the Bakken/Three Forks plays, as well as an additional 14.7 BCFE of infill proved undeveloped reserves that were mostly concentrated in our assets in the Bakken/Three Forks formations, the Eagle Ford shale, and in our Wolfberry properties in our Permian region. A negative price revision of 33.4 BCFE was primarily due to gas weighted projects in our ArkLaTex and Mid-continent regions that no longer met internal economic investment hurdles for projects in which we would invest due to lower natural gas prices or that no longer generate positive cash flow utilizing 12-month average benchmark pricing required by the SEC. We had a net positive performance revision of 8.5 BCFE, which includes the impact of our conversion to three stream production reporting, as well as negative engineering revisions due primarily to higher than expected well costs in the Woodford shale in our Mid-Continent region, causing those projects to no longer meet our internal investment hurdles. During the year, we sold assets comprising 24.5 BCFE from our South Texas & Gulf Coast region. We invested $86.2 million to convert 34.6 BCFE of proved undeveloped reserves to proved reserves in 2011, mainly in the Eagle Ford and Haynesville shales and the Bakken/Three Forks formations. 
+As of December 31, 2011, we had no material proved undeveloped reserves that have been on our books in excess of five years, and we had recorded no material proved undeveloped locations that were more than one direct offset from an existing producing well. As of December 31, 2011, estimated future development costs relating to our proved undeveloped reserves are approximately $285 million, $289 million, and $266 million in 2012, 2013, and 2014, respectively. 
+Internal Controls Over Reserves Estimate 
+Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with the SEC’s regulations. Our process for managing and monitoring the Company's proved reserves is delegated to our reservoir engineering group, which is managed by Dennis A. Zubieta, our Vice President - Engineering and Evaluation, subject to the oversight of our management and the Audit Committee of our Board of Directors, as discussed below. 
+Mr. Zubieta joined us in June 2000 as a Corporate Acquisition & Divestiture Engineer, assumed the role of Reservoir Engineer in February 2003, was appointed Reservoir Engineering Manager in August 2005, and was 
+11 
+Table of Contents 
+appointed Vice President - Engineering and Evaluation in August 2008. Mr. Zubieta was employed by Burlington Resources Oil and Gas Company from June 1988 to May 2000 in various operations and reservoir engineering capacities. Mr. Zubieta received a Bachelor of Science degree in Petroleum Engineering from Montana Tech in May 1988. Technical reviews are performed throughout the year by regional staff who evaluate geological and engineering data. This data, in conjunction with economic data and our ownership information, is used in making a determination of estimated proved reserve quantities. The regional technical staff does not report directly to Mr. Zubieta; they report to either regional technical managers or directly to the regional manager in their respective regions. This is intended to promote objective and independent analysis, within our regions as part of the reserves estimation process. 
+Third-party Reserves Audit 
+An independent audit is performed by Ryder Scott using their own engineering assumptions and economic and ownership data provided by us. A minimum of 80 percent of our total calculated proved reserve PV-10 value is audited by Ryder Scott. In the aggregate, the proved reserve values of our audited properties are required to be within ten percent of our valuations for the total company as well as for each respective region. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world for over seventy years. The technical person at Ryder Scott primarily responsible for overseeing our reserve audit is a Senior Vice President, who received a Bachelor of Science degree in Petroleum Engineering from the University of Missouri at Rolla in 1970 and who is a registered Professional Engineer in Colorado and Utah. He is also a member of the Society of Petroleum Engineers. The Ryder Scott 2011 report concerning our reserves is included as Exhibit 99.1. 
+In addition to a third party audit, our reserves are reviewed by management and the Audit Committee of our Board of Directors. Management, which includes the President and Chief Executive Officer, the Executive Vice President and Chief Operating Officer, and the Executive Vice President and Chief Financial Officer, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews the final reserves estimate in conjunction with Ryder Scott’s audit report. They may also meet with Ryder Scott representatives to discuss its processes and findings. 
+Production 
+The following table summarizes the volumes and realized prices of oil, gas, and NGLs produced from properties in which we held an interest during the periods indicated. Realized prices presented below exclude the effects of hedges and derivative contracts. Also presented is a summary of production costs per MCFE: 
+12 
+Table of Contents 
+Years Ended December 31, 
+2011 
+2010 
+2009 
+Net production (1) 
+Oil (MMBbl) 
+8.1 
+6.4 
+6.3 
+Gas (Bcf) 
+100.3 
+71.9 
+71.1 
+NGLs (MMBbl) 
+3.5 
+— 
+— 
+BCFE 
+169.7 
+110.0 
+109.1 
+Average net daily production (1) 
+Oil (MBbl per day) 
+22.1 
+17.4 
+17.3 
+Gas (MMcf per day) 
+274.8 
+196.9 
+194.8 
+NGLs (MBbl per day) 
+9.6 
+— 
+— 
+MMCFE per day 
+465.0 
+301.4 
+298.8 
+Realized price 
+Oil (per Bbl) 
+$ 
+88.23 
+$ 
+72.65 
+$ 
+54.40 
+Gas (per Mcf) 
+$ 
+4.32 
+$ 
+5.21 
+$ 
+3.82 
+NGLs (per Bbl) 
+$ 
+53.32 
+$ 
+— 
+$ 
+— 
+Per MCFE 
+$ 
+7.85 
+$ 
+7.60 
+$ 
+5.65 
+Production costs per MCFE 
+Lease operating expense 
+$ 
+0.88 
+$ 
+1.10 
+$ 
+1.33 
+Transportation costs 
+$ 
+0.51 
+$ 
+0.19 
+$ 
+0.19 
+Production taxes 
+$ 
+0.32 
+$ 
+0.48 
+$ 
+0.37 
+(1) 
+In 2011 and 2010, total estimated proved reserves for our Eagle Ford shale properties equated to greater than 15 percent of our total proved reserves expressed on an equivalent basis. During 2011, our net production from the Eagle Ford shale was 32.9 Bcf of gas, 2.5 MMBbl of oil, and 3.1 MMBbl of NGLs or 66.6 BCFE. Our average daily production from the Eagle Ford shale was 90.1 MMcf of gas, 6.8 MBbl of oil, and 8.6 MBbl of NGLs, for an average production rate of 182.5 MMCFE per day. During 2010, our net production from the Eagle Ford shale was 13.0 Bcf of gas and 0.8 MMBbl of oil, or 17.6 BCFE. Our average daily production from the Eagle Ford shale was 35.6 MMcf of gas and 2.1 MBbl of oil, for an average production rate of 48.3 MMCFE per day. No fields contained 15 percent or greater of our total proved reserves expressed on an equivalent basis in 2009. 
+Note: NGL reserve data, production volumes, revenues, and prices for prior periods have not been reclassified to conform to the current presentation given the immateriality of the volumes in prior periods. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices under Part II, Item 7 of this report. 
+Productive Wells 
+As of December 31, 2011, we had working interests in 1,353 gross (741 net) productive oil wells and 2,928 gross (1,060 net) productive gas wells. Productive wells are either wells producing in commercial quantities or wells mechanically capable of commercial production, but are currently shut-in. Multiple completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production. 
+Drilling Activity 
+All of our drilling activities are conducted using independent drilling contractors. We do not own any drilling equipment. The following table summarizes the number of operated and non-operated wells drilled and recompleted on our properties in 2011, 2010, and 2009, excluding any wells in which we own only a royalty interest: 
+13 
+Table of Contents 
+Years Ended December 31, 
+2011 
+2010 
+2009 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development wells: 
+Oil 
+125 
+32.1 
+191 
+36.5 
+103 
+29.6 
+Gas 
+273 
+81.0 
+72 
+17.0 
+74 
+18.2 
+Non-productive 
+11 
+4.0 
+4 
+1.1 
+3 
+1.3 
+409 
+117.1 
+267 
+54.6 
+180 
+49.1 
+Exploratory wells: 
+Oil 
+16 
+6.3 
+36 
+11.5 
+2 
+0.4 
+Gas 
+48 
+8.6 
+83 
+37.9 
+18 
+9.1 
+Non-productive 
+3 
+1.0 
+1 
+0.8 
+5 
+2.9 
+67 
+15.9 
+120 
+50.2 
+25 
+12.4 
+Total 
+476 
+133.0 
+387 
+104.8 
+205 
+61.5 
+A productive well is an exploratory, development, or extension well that is producing oil, gas, and/or NGLs or that is capable of commercial production of those products. A dry well (hole) is an exploratory, development, or extension well that proves to be incapable of producing either oil, gas, and/or NGLs in commercial quantities. 
+As defined by the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive and is part of a development project, which is defined as the means by which petroleum resources are brought to economically producible status. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for production of oil, gas, and/or NGLs, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned. 
+In addition to the wells drilled and completed in 2011 included in the table above, as of February 16, 2012 , we were participating in the drilling of 34 gross wells. We operate 12 of these wells on a gross basis, seven on a net basis, with the remaining 22 gross wells, four on a net basis, being operated by others. With respect to completion activity, at such date, there were 156 gross wells in which we have an interest that were being completed. We operate 28 of these completion activities on a gross basis, 16 on a net basis, and were participating in 128 gross, 18 net non-operated completion activities. The vast majority, if not all, of these operations relate to the drilling of wells for primary production. 
+Acreage 
+The following table sets forth the gross and net acres of developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held by us as of December 31, 2011. Undeveloped acreage includes leasehold interests that may already be classified as containing proved undeveloped reserves. 
+14 
+Table of Contents 
+Developed Acres (1) 
+Undeveloped Acres (2) 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Louisiana 
+70,632 
+26,049 
+16,367 
+4,716 
+86,999 
+30,765 
+Montana 
+59,071 
+40,655 
+315,582 
+212,371 
+374,653 
+253,026 
+Nevada 
+- 
+- 
+197,634 
+197,634 
+197,634 
+197,634 
+North Dakota 
+134,647 
+88,865 
+158,543 
+87,186 
+293,190 
+176,051 
+Oklahoma 
+257,348 
+82,962 
+39,280 
+14,334 
+296,628 
+97,296 
+Pennsylvania 
+346 
+346 
+49,676 
+39,749 
+50,022 
+40,095 
+Texas 
+211,525 
+135,211 
+489,922 
+226,543 
+701,447 
+361,754 
+Wyoming 
+62,936 
+28,305 
+304,603 
+166,371 
+367,539 
+194,676 
+Other (3) 
+4,430 
+2,011 
+53,418 
+34,351 
+57,848 
+36,362 
+800,935 
+404,404 
+1,625,025 
+983,255 
+2,425,960 
+1,387,659 
+Louisiana Fee Properties 
+10,499 
+10,499 
+14,415 
+14,415 
+24,914 
+24,914 
+Louisiana Mineral Servitudes 
+7,426 
+4,217 
+4,769 
+4,407 
+12,195 
+8,624 
+17,925 
+14,716 
+19,184 
+18,822 
+37,109 
+33,538 
+Total (4) 
+818,860 
+419,120 
+1,644,209 
+1,002,077 
+2,463,069 
+1,421,197 
+(1) 
+Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but have only been included as developed acreage in the presentation above. 
+(2) 
+Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves. 
+(3) 
+Includes interest in Arkansas, Colorado, Illinois, Kansas, Mississippi, New Mexico, and Utah. 
+(4) 
+As of the filing date, we had approximately 50,000, 73,000, and 65,000 net acres scheduled to expire by December 31, 2012, 2013, and 2014, respectively, if production is not established or we take no other action to extend the terms. 
+Delivery Commitments 
+As of December 31, 2011, we had gathering, processing, and transportation through-put commitments with various parties that require us to deliver a fixed determinable quantity of product. We have an aggregate minimum commitment to deliver 1,766 Bcf of natural gas and 9 MMBbls of oil. These contracts expire at various dates through 2023. We will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. If a shortfall in the minimum volume commitment for natural gas is projected, we have certain rights to arrange for third party gas to be delivered into the gathering lines and such volume will count towards our minimum commitment. At the current time, we do not have enough proved developed reserves to offset these contractual liabilities, but we expect to fulfill the delivery commitments with production from development of our proved reserves, as well as the development of resources not yet characterized as proved reserves, from our Eagle Ford shale and Haynesville shale resource plays. Therefore, we currently do not expect any shortfalls. 
+Major Customers 
+During 2011 and 2010, sales to Regency Gas Services LLC ("Regency") individually accounted for approximately 18 percent and 11 percent, respectively, of our total oil, gas, and NGL production revenue. During 2009, sales to Teppco Crude Oil LLC individually accounted for 12 percent of our total oil and gas production revenue. 
+Employees and Office Space 
+As of February 16, 2012, we had 639 full-time employees. None of our employees are subject to a collective bargaining agreement, and we consider our relations with our employees to be good. As of December 31, 2011, we leased approximately 84,000 square feet of office space in Denver, Colorado for our executive and administrative offices; approximately 39,000 square feet of office space in Tulsa, Oklahoma; 
+15 
+Table of Contents 
+approximately 30,000 square feet in Houston, Texas; approximately 30,000 square feet in Billings, Montana; approximately 25,000 square feet in Shreveport, Louisiana; approximately 22,000 square feet in Midland, Texas; approximately 7,000 total square feet in Williston and Watford City, North Dakota; and approximately 2,000 square feet in Casper, Wyoming. 
+Title to Properties 
+Substantially all of our interests are held pursuant to leases from third parties. A title opinion is usually obtained prior to the commencement of initial drilling operations. We have obtained title opinions or have conducted a title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. The majority of our producing properties are subject to mortgages securing indebtedness under our credit facility, royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere with the use of, or affect the value of, such properties. We typically perform only minimal title investigation before acquiring undeveloped leasehold acreage. 
+Seasonality 
+Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. The impact of seasonality on oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of worldwide production capacity in excess of existing worldwide demand for oil. Certain of our drilling and completion operations are also subject to seasonal limitations. Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. See Risk Factors - Risks Related to Our Business for additional discussion. 
+Competition 
+The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We believe our leasehold position provides a sound foundation for a solid drilling program and our future growth. Our competitive position also depends on our geological, geophysical, and engineering expertise, as well as our financial resources. We believe the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams enable us to compete in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies, which in some cases have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs and other equipment, and generate electricity. 
+We also compete with other oil and gas companies in attempting to secure drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells. Consequently, we may face shortages or delays in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may be affected by future new energy, climate-related, financial, and/or other policies, legislation, and regulations. 
+In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other 
+16 
+Table of Contents 
+professionals. Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the availability of individuals with these skills is becoming more limited due to demographics in our industry. We are not insulated from the competition for quality people, and we must compete effectively in order to be successful. 
+Government Regulations 
+Our business is extensively regulated by numerous federal, state, and local laws and governmental regulations. These laws and regulations may be changed from time to time in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations have the potential of increasing our cost of doing business and, consequently, could affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry. 
+Energy Regulations. Many of the states in which we conduct our operations have adopted laws and regulations governing the exploration for and production of oil, gas, and NGLs, including laws and regulations requiring permits for the drilling of wells, imposing bonding requirements in order to drill or operate wells, and governing the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to various state conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the unitization or pooling of oil and gas properties. In addition, state conservation laws sometimes establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. 
+Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of Land Management ("BLM"). These leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may suspend or terminate our operations on federal leases. 
+In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes may increase the amount of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM. 
+Our sales of gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission ("FERC") has jurisdiction over the transportation and sale for resale of gas in interstate commerce. FERC's current regulatory framework generally provides for a competitive and open access market for sales and transportation of natural gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for gas production. In addition, the less stringent regulatory approach currently pursued by FERC and the United States Congress may not continue indefinitely. 
+Environmental, Health and Safety Matters 
+General. Our operations are subject to stringent and complex federal, state, tribal and local laws and regulations governing protection of the environment and worker health and safety as well as the discharge of materials into the environment. These laws and regulations may, among other things: 
+• 
+require the acquisition of various permits before drilling commences; 
+17 
+Table of Contents 
+• 
+restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities; 
+• 
+limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and 
+• 
+require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells. 
+These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes that result in more stringent and costly permitting, waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs. 
+The following is a summary of some of the existing laws, rules and regulations to which our business is subject. 
+Waste handling. The Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA's non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. 
+Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. 
+18 
+Table of Contents 
+Water discharges. The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, U.S. Army Corps of Engineers or analogous state agencies. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. 
+The Oil Pollution Act of 1990 (“OPA”) addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil liability. 
+Air emissions. The federal Clean Air Act (“CAA”), and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. 
+Climate change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change could have an adverse effect on our operatives and the demand for oil and gas. See “ Risk Factors - Risks Related to Our Business - Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas and NGLs .” In addition to the effects of regulation, the meteorological effects of global climate change could pose additional risks to our operations, including physical damage risks associated with more frequent, more intensive storms and flooding, and could adversely affect the demand for our products. 
+Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our well drilling operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas. 
+National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (the “NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay development of some of our oil and natural gas projects. 
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+OSHA and other laws and regulation. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe that we are in substantial compliance with the applicable requirements of OSHA and comparable laws. 
+Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of our drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act's Underground Injection Control Program. The federal Safe Drinking Water Act protects the quality of the nation's public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas activities using hydraulic fracturing techniques which could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and delays which could adversely affect our financial position, results of operations and cash flows. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. 
+We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. While we believe that we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We cannot give any assurance that we will not be adversely affected in the future. 
+Cautionary Information about Forward-Looking Statements 
+This Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear in a number of places in this Form 10-K, and include statements about such matters as: 
+• 
+the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures; 
+• 
+the drilling of wells and other exploration and development activities and plans, as well as possible future acquisitions; 
+• 
+the possible divestiture or farm-down of, or joint venture relating to, certain properties; 
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+• 
+proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those proved reserve estimates; 
+• 
+future oil, gas, and NGL production estimates; 
+• 
+our outlook on future oil, gas, and NGL prices, well costs, and service costs; 
+• 
+cash flows, anticipated liquidity, and the future repayment of debt; 
+• 
+business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and 
+• 
+other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in Item 7 of this report. 
+Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. These risks are described in the Risk Factors section of this report, and include such factors as: 
+• 
+the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves; 
+• 
+the continued weakness in economic conditions and uncertainty in financial markets; 
+• 
+our ability to replace reserves in order to sustain production; 
+• 
+our ability to raise the substantial amount of capital that is required to replace our reserves; 
+• 
+our ability to compete against competitors that have greater financial, technical, and human resources; 
+• 
+our ability to attract and retain key personnel; 
+• 
+the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves; 
+• 
+the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities; 
+• 
+the possibility that exploration and development drilling may not result in commercially producible reserves; 
+• 
+our limited control over activities on non-operated properties; 
+• 
+our reliance on the skill and expertise of third-party service providers on our operated properties; 
+• 
+the possibility that title to properties in which we have an interest may be defective; 
+• 
+the possibility that our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production; 
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+• 
+the uncertainties associated with divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate; 
+• 
+the uncertainties associated with enhanced recovery methods; 
+• 
+our commodity derivative contracts may result in financial losses or may limit the prices that we receive for oil, gas, and NGL sales; 
+• 
+the inability of one or more of our vendors, customers, or contractual counterparties to meet their obligations; 
+• 
+price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values; 
+• 
+the impact that lower oil, gas, or NGL prices could have on our ability to borrow under our credit facility; 
+• 
+the possibility that our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt; 
+• 
+operating and environmental risks and hazards that could result in substantial losses; 
+• 
+complex laws and regulations, including environmental regulations, that result in substantial costs and other risks; 
+• 
+the availability and capacity of gathering, transportation, processing, and/or refining facilities; 
+• 
+our ability to sell and/or receive market prices for our oil, gas, and NGLs; 
+• 
+new technologies may cause our current exploration and drilling methods to become obsolete; 
+• 
+the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and 
+• 
+litigation, environmental matters, the potential impact of government regulations, and the use of management estimates regarding such matters. 
+We caution you that forward-looking statements are not guarantees of future performance and that actual results or performance may be materially different from those expressed or implied in the forward-looking statements. The forward-looking statements in this report speak as of the filing date of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws. 
+Available Information 
+Our internet website address is www.sm-energy.com. We routinely post important information for investors on our website. Within our website’s investor relations section we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. We also make available through our website’s corporate governance section our Corporate Governance Guidelines, Code of Business Conduct and Ethics, and the Charters for our Board of Directors’ Audit Committee, Compensation Committee, Executive Committee, and Nominating and Corporate Governance Committee. Information on our 
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+website is not incorporated by reference into this report and should not be considered part of this document. 
+Glossary of Oil and Gas Terms 
+The oil and gas terms defined in this section are used throughout this report. The definitions of the terms developed reserves, exploratory well, field, proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under SEC Rule 4-10(a) of Regulation S-X, as amended effective for fiscal years ending on or after December 31, 2009. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located through the SEC’s website at www.sec.gov. 
+Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used in reference to oil or other liquid hydrocarbons. 
+Bcf . Billion cubic feet, used in reference to natural gas. 
+BCFE. Billion cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs. 
+BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs. 
+BTU. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit. 
+Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production. 
+Developed reserves. Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. 
+Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+Dry hole. A well found to be incapable of producing either oil, natural gas, and/or NGLs in commercial quantities. 
+Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. 
+Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil and natural gas) rights. 
+Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. 
+Finding and development cost. Expressed in dollars per MCFE. Finding and development cost metrics provide information as to the cost of adding proved reserves from various activities, and are widely utilized within the exploration and production industry, as well as by investors. The information used to calculate these metrics is included in the Supplemental Oil and Gas Information section in Part II, Items 8 of this report. It should be noted that finding and development cost metrics have limitations. For example, exploration efforts related to a particular set of proved reserve additions may extend over several years. As a result, the exploration costs incurred in earlier periods are not included in the amount of exploration costs incurred during the period in which that set of proved reserves is added. In addition, consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred. Since the additional development costs that will need to be incurred in 
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+the future before the proved undeveloped reserves are ultimately produced are not included in the amount of costs incurred during the period in which those reserves were added, those development costs in future periods will be reflected in the costs associated with adding a different set of reserves. The calculations of various finding and development cost metrics are explained below. 
+Finding and development cost – Drilling, excluding revisions. Calculated by dividing the amount of costs incurred for development and exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, and infill drilling, during the same period. 
+Finding and development cost – Drilling, including revisions. Calculated by dividing the amount of costs incurred for development and exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, and revisions of previous estimates, during the same period. 
+Finding and development cost – Drilling and acquisitions, excluding revisions. Calculated by dividing the amount of costs incurred for development, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, and acquisitions, during the same period. 
+Finding and development cost – Drilling and acquisitions, including revisions. Calculated by dividing the amount of costs incurred for development, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, revisions of previous estimates, and acquisitions, during the same period. 
+Finding and development cost –All in, including sales of reserves. Calculated by dividing the amount of total capital expenditures for oil and natural gas activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates less sales of reserves, during the same period. 
+Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions. 
+Gross acre. An acre in which a working interest is owned. 
+Gross well. A well in which a working interest is owned. 
+Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical. 
+Lease operating expenses. The expenses incurred in the lifting of crude oil, natural gas, and/or associated liquids from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs. 
+MBbl. One thousand barrels of crude oil or other liquid hydrocarbons. 
+MMBbl. One million barrels of crude oil or other liquid hydrocarbons. 
+Mcf. One thousand cubic feet, used in reference to natural gas. 
+MCFE. One thousand cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs. 
+MMcf. One million cubic feet, used in reference to natural gas. 
+MMCFE. One million cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs. 
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+MMBtu. One million British thermal units. 
+Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells. 
+Net asset value per share. The result of the fair market value of total assets less total liabilities, divided by the total number of outstanding shares of common stock. 
+NGLs. The combination of ethane, propane, butane, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressures and lower temperatures. 
+NYMEX WTI. New York Mercantile Exchange West Texas Intermediate. 
+OPIS . Oil Price Information Service Mont Belvieu. 
+PV-10 value (Non-GAAP). The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual discount rate of ten percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period. This is a Non-GAAP measure. 
+Productive well. A well that is producing crude oil, natural gas, and/or NGLs or that is capable of commercial production of those products. 
+Proved reserves. Those quantities of oil, gas, and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 
+Recompletion. The completion in an existing wellbore in a formation other than that in which the well has previously been completed. 
+Reserve life. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period. 
+Reserve replacement. Reserve replacement metrics are used as indicators of a company’s ability to replenish annual production volumes and grow its reserves, and provide information related to how successful a company is at growing its proved reserve base. These are believed to be useful non-GAAP measures that are widely utilized within the exploration and production industry, as well as by investors. They are easily calculable metrics, and the information used to calculate these metrics is included in the Supplemental Oil and Gas Information section of Part II, Item 8 of this report. It should be noted that reserve replacement metrics have limitations. They are limited because they typically vary widely based on the extent and timing of new discoveries and property acquisitions. Their predictive and comparative value is also limited for the same reasons. In addition, because the metrics do not embed the cost or timing of future production of new reserves, they cannot be used as a measure of value creation. 
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+The calculations of various reserve replacement metrics are explained below. 
+Reserve replacement – Drilling, excluding revisions. Calculated as a numerator comprised of the sum of reserve extensions and discoveries and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling activity. 
+Reserve replacement – Drilling, including revisions. Calculated as a numerator comprised of the sum of reserve extensions, discoveries, and infill reserves, and revisions of previous estimates in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling activity. 
+Reserve replacement – Drilling and acquisitions, excluding revisions. Calculated as a numerator comprised of the sum of reserve acquisitions and reserve extensions and discoveries and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities. 
+Reserve replacement – Drilling and acquisitions, including revisions. Calculated as a numerator comprised of the sum of reserve acquisitions and reserve extensions, discoveries, and infill reserves, and revisions of previous estimates in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities. 
+Reserve replacement percentage – All in, excluding sales of reserves. The sum of reserve extensions and discoveries, infill drilling, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period. 
+Reserve replacement percentage –All in, including sales of reserves. The sum of sales of reserves, infill drilling, reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period. 
+Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude oil, natural gas, and/or associated liquid resources that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 
+Resource play. A term used to describe an accumulation of crude oil, natural gas, and/or associated liquid resources known to exist over a large areal expanse, which when compared to a conventional play typically has a lower expected geological and/or commercial development risk. 
+Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil, natural gas, and NGLs produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well. 
+Royalty interest. An interest in an oil and natural gas property entitling the owner to shares of crude oil, natural gas, and NGL production free of costs of exploration, development, and production operations. 
+Seismic. The sending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape, and depth of subsurface rock formations. 
+Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock. 
+Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a ten percent 
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+annual discount rate. The information for this calculation is included in the supplemental information regarding disclosures about oil and gas producing activities following the Notes to Consolidated Financial Statements included in this report. 
+Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves. 
+Undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. 
+Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share in the production, sales, and costs. 
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+ITEM 1A. RISK FACTORS 
+In addition to the other information included in this report, the following risk factors should be carefully considered when evaluating an investment in us. 
+Risks Related to Our Business 
+Crude oil, natural gas, and NGL prices are volatile, and declines in prices adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow. 
+Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and natural gas properties depend heavily on the prices we receive for crude oil, natural gas and NGL sales. Crude oil, natural gas, and NGL prices also affect our cash flows available for capital expenditures and other items, our borrowing capacity, and the amount and value of our crude oil, natural gas, and NGL reserves. For example, the amount of our borrowing base under our credit facility is subject to periodic redeterminations based on crude oil, natural gas, and NGL prices specified by our bank group at the time of redetermination. In addition, we may have crude oil and natural gas property impairments or downward revisions of estimates of proved reserves if prices fall significantly. 
+Historically, the markets for crude oil, natural gas, and NGLs have been volatile, and they are likely to continue to be volatile. Wide fluctuations in crude oil, natural gas, and NGL prices may result from relatively minor changes in the supply of and demand for crude oil, natural gas, and NGLs, market uncertainty, and other factors that are beyond our control, including: 
+• 
+global and domestic supplies of crude oil, natural gas, and NGLs, and the productive capacity of the industry as a whole; 
+• 
+the level of consumer demand for crude oil, natural gas, and NGLs; 
+• 
+overall global and domestic economic conditions; 
+• 
+weather conditions; 
+• 
+the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas that may affect the realized price for crude oil, natural gas, or NGLs; 
+• 
+the price and level of foreign imports of crude oil, refined petroleum products, and liquefied natural gas; 
+• 
+the price and availability of alternative fuels; 
+• 
+technological advances affecting energy consumption; 
+• 
+the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain crude oil price and production controls; 
+• 
+political instability or armed conflict in crude oil or natural gas producing regions; 
+• 
+strengthening and weakening of the United States dollar relative to other currencies; and 
+• 
+governmental regulations and taxes. 
+These factors and the volatility of crude oil, natural gas, and NGL markets make it extremely difficult to predict future crude oil, natural gas, and NGL price movements with any certainty. Declines in crude oil, natural gas, and NGL prices would reduce our revenues and could also reduce the amount of crude oil, natural gas, and 
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+NGLs that we can produce economically, which could have a materially adverse effect on us. 
+Continued weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict. 
+United States and global economies and financial systems have recently experienced turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, increased levels of unemployment, and an unprecedented level of intervention by the United States federal government and other governments. Although some portions of the economy appear to have stabilized and there have been signs of the beginning of a recovery, the extent and timing of a recovery, and whether it can be sustained, are uncertain. Continued weakness in the United States or other large economies could materially adversely affect our business and financial condition. For example: 
+• 
+the demand for crude oil, natural gas, and NGLs in the United States has declined and may remain at low levels or further decline if economic conditions remain weak, and continue to negatively impact our revenues, margins, profitability, operating cash flows, liquidity, and financial condition; 
+• 
+natural gas prices have recently been lower than at various times in the last decade because of increased supply resulting from, among other things, increased drilling in unconventional reservoirs, reduced demand in connection with the recent recession, and an unusually warm winter, which sustained low prices could affect our financial condition and results of operations; 
+• 
+the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables; 
+• 
+the liquidity available under our credit facility could be reduced if any lender is unable to fund its commitment; 
+• 
+our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for exploration and/or development of our reserves; 
+• 
+our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; and 
+• 
+variable interest rate spread levels, including for LIBOR and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our credit facility. 
+If we are unable to replace reserves, we will not be able to sustain production. 
+Our future operations depend on our ability to find, develop, or acquire crude oil, natural gas, and NGL reserves that are economically producible. Our properties produce crude oil, natural gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate and develop or acquire new crude oil, natural gas, and NGL reserves to replace those being depleted by production. In addition, competition for crude oil and natural gas properties is intense and many of our competitors have financial, technical, human, and other resources needed to evaluate and integrate acquisitions that are substantially greater than those available to us. 
+In the event we do complete an acquisition, its successful impact on our business will depend on a number of factors, many of which are beyond our control. These factors include the purchase price, future crude oil, natural gas, and NGL prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and development activities on the acquired properties, and future abandonment and 
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+possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates, and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems. 
+Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited. 
+Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions. Without successful drilling or acquisition activities, our reserves and production will decline over time. 
+Substantial capital is required to replace our reserves. 
+We must make substantial capital expenditures to find, acquire, develop, and produce crude oil, natural gas, and NGL reserves. Future cash flows and the availability of financing are subject to a number of factors, such as the level of production from existing wells, prices received for crude oil, natural gas, and NGL sales, our success in locating and developing and acquiring new reserves, and the orderly functioning of credit and capital markets. If crude oil, natural gas, and NGL prices decrease or if we encounter operating difficulties that result in our cash flows from operations being less than expected, we must reduce our capital expenditures unless we can raise additional funds through debt or equity financing or the divestment of assets. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms, and the proceeds offered to us for potential divestitures may not always be of acceptable value to us. 
+If our revenues decrease due to lower crude oil, natural gas, or NGL prices, decreased production, or other reasons, and if we cannot obtain capital through our credit facility, other acceptable debt or equity financing arrangements, or through the sale of assets, our ability to execute development plans, replace our reserves, maintain our acreage, or maintain production levels could be greatly limited. 
+Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do. 
+We face intense competition from major oil and gas companies, independent oil and natural gas exploration and production companies, financial buyers, and institutional and individual investors who seek crude oil and natural gas property investments throughout the world, as well as the equipment, expertise, labor, and materials required to operate crude oil and natural gas properties. Many of our competitors have financial, technical, and other resources vastly exceeding those available to us, and many crude oil and natural gas properties are sold in a competitive bidding process in which our competitors may be able and willing to pay more for development prospects and productive properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for the properties. In addition, shortages of equipment, labor, or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. We may not be successful in acquiring and developing profitable properties in the face of this competition. 
+We also compete for human resources. Over the last few years, the need for talented people across all disciplines in the industry has grown, while the number of talented people available has not grown at the same pace, and in many cases, is declining due to the demographics of the industry. 
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+The loss of key personnel could adversely affect our business. 
+We depend to a large extent on the efforts and continued employment of our executive management team and other key personnel. The loss of the services of these or other key personnel could adversely affect our business. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen and other professionals. Competition for many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed. 
+The actual quantities and present value of our proved crude oil, natural gas, and NGL reserves may be less than we have estimated. 
+This report and other of our SEC filings contain estimates of our proved crude oil, natural gas, and NGL reserves and the estimated future net revenues from those reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to crude oil, natural gas, and NGL prices, drilling and completion costs, operating expenses, capital expenditures, taxes, timing of operations, and availability of funds. The process of estimating crude oil, natural gas, and NGL reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent on many variables, and therefore changes often occur as our knowledge of these variables evolve. Therefore, these estimates are inherently imprecise. In addition, the reserve estimates we make for fields that do not have a lengthy production history may be less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing of development expenditures. 
+Actual future production, prices for crude oil, natural gas, and NGLs, revenues, production taxes, development expenditures, operating expenses, and quantities of producible crude oil, natural gas, and NGL reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities of and present value related to proved reserves disclosed by us, and the actual quantities and present value may be less than we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development activity, prevailing crude oil, natural gas, and NGL prices, costs to develop and operate properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties. 
+As of December 31, 2011, 33 percent, or 415.2 BCFE, of our estimated proved reserves were proved undeveloped, and four percent, or 54.3 BCFE, were proved developed non-producing. In order to develop our proved undeveloped reserves, as of December 31, 2011, we estimate approximately $939 million of capital expenditures would be required. Production revenues from proved developed non-producing reserves will not be realized until sometime in the future and after some investment of capital. In order to bring production on-line for our proved developed non-producing reserves, as of December 31, 2011, we estimate capital expenditures of approximately $41 million will be deployed in future years. Although we have estimated our proved reserves and the costs associated with these proved reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled, and actual results may not occur as estimated. A significant portion of our anticipated capital expenditures for 2012 is directed toward projects that are not yet classified within the construct of proved reserves as defined by Regulation S-X promulgated by the SEC. 
+You should not assume that the PV-10 value and standardized measure of discounted future net cash flows included in this report represent the current market value of our estimated proved crude oil, natural gas, and NGL reserves. Management has based the estimated discounted future net cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. For example, values of our reserves as of December 31, 2011, were estimated using a calculated 12-month average sales price of $4.12 per MMBtu of natural gas (NYMEX Henry Hub spot price), $96.19 per Bbl of oil (NYMEX WTI spot price), and $59.37 per Bbl of NGL (OPIS spot price). We then adjust these base prices to reflect appropriate basis, quality, and location differentials over that period in estimating our proved reserves. During 
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+2011, our monthly average realized natural gas prices, excluding the effect of derivative cash settlements, were as high as $4.79 per Mcf and as low as $3.58 per Mcf. For the same period, our monthly average realized crude oil prices before the effect of derivative cash settlements were as high as $104.75 per Bbl and as low as $78.95 per Bbl, and were as high as $75.57 per Bbl and as low as $41.14 per Bbl for NGLs. Many other factors will affect actual future net cash flows, including: 
+• 
+amount and timing of actual production; 
+• 
+supply and demand for crude oil, natural gas, and NGLs; 
+• 
+curtailments or increases in consumption by oil purchasers and natural gas pipelines; and 
+• 
+changes in government regulations or taxes, including severance and excise taxes. 
+The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing the PV-10 value. In addition, the ten percent discount factor required by the SEC to be used to calculate the PV-10 value for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and natural gas industry in general are subject. 
+Proved reserve estimates as of December 31, 2011, 2010, and 2009 have been prepared under the SEC’s new rules for oil and gas reporting that were effective for fiscal years ending on or after December 31, 2009. These new rules require SEC reporting companies to prepare their proved reserve estimates using, among other things, revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing, instead of the prior requirement to use pricing at the end of the period. The SEC has released only limited interpretive guidance regarding reporting of proved reserve estimates under the new rules and may not issue further interpretive guidance on the new rules in the near future. The interpretation of these rules and their applicability in different situations remains unclear in many respects. Changing interpretations of the rules or disagreements with our interpretations could result in revisions to our proved reserve estimates, which could be significant. 
+Another impact of the SEC rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling programs. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill on those reserves within the required five-year timeframe. Substantial downward adjustments to our estimated proved reserves could have a material adverse effect on our financial condition, results of operations, and operating cash flows. 
+Our property acquisitions may not be worth what we paid due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities. 
+Successful property acquisitions require an assessment of a number of factors sometimes beyond our control. These factors include exploration potential, future crude oil, natural gas, and NGL prices, operating costs, and potential environmental and other liabilities. These assessments are not precise and their accuracy is inherently uncertain. 
+In connection with our acquisitions, we typically perform a customary review of the acquired properties that will not necessarily reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and 
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+warranties. 
+In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such acquisitions may be limited. 
+Integrating acquired properties and businesses involves a number of other special risks, including the risk that management may be distracted from normal business concerns by the need to integrate operations and systems as well as retain and assimilate additional employees. Therefore, we may not be able to realize all of the anticipated benefits of our acquisitions. 
+We have limited control over the activities on properties we do not operate. 
+Some of our properties, including a portion of our operations in the Eagle Ford shale in South Texas, are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including the nature and timing of drilling and operational activities, the operator's skill and expertise, compliance with environmental, safety and other regulations, the approval of other participants in such properties, the selection and application of suitable technology, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs and materially and adversely affect our financial condition and results of operations. 
+We rely on third-party service providers to conduct the drilling operations on properties we operate. 
+Where we are the operator of a property, we rely on third-party service providers to perform the necessary drilling operations. The ability of third-party service providers to perform such drilling operations will depend on those service providers' ability to compete for and retain qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the supply and demand for oil, natural gas liquids and natural gas, prevailing economic conditions and financial, business and other factors. The failure of a third-party service provider to adequately perform operations could delay drilling or completion or reduce production from the property and adversely affect our financial condition and results of operations. 
+Title to the properties in which we have an interest may be impaired by title defects. 
+We generally rely on title reports in acquiring oil and gas leasehold interests and obtain title opinions only on significant properties that we drill. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Title insurance is not available for oil and gas properties. As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work of examining records in the appropriate governmental offices and title abstract facilities before attempting to acquire or place under lease a specific mineral interest and/or undertake drilling activities. We, in some cases, perform curative work to correct deficiencies in the marketability of the title to us. Generally, under the terms of the operating agreements affecting our properties, any monetary loss attributable to a loss of title is to be borne by all parties to any such agreement in proportion to their interests in such property. A material title defect can reduce the value or render a property worthless, thus adversely affecting our financial condition, results of operations and operating cash flow if such property is of sufficient value. 
+Exploration and development drilling may not result in commercially producible reserves. 
+Crude oil and natural gas drilling and production activities are subject to numerous risks, including the risk that no commercially producible crude oil, natural gas, or associated liquids will be found. The cost of drilling and 
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+completing wells is often uncertain, and crude oil, natural gas or associated liquids drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors include: 
+• 
+unexpected drilling conditions; 
+• 
+title problems; 
+• 
+disputes with owners or holders of surface interests on or near areas where we operate; 
+• 
+pressure or geologic irregularities in formations; 
+• 
+engineering and construction delays; 
+• 
+equipment failures or accidents; 
+• 
+hurricanes or other adverse weather conditions; 
+• 
+compliance with environmental and other governmental requirements; and 
+• 
+shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies. 
+The prevailing prices for crude oil, natural gas, and NGLs affect the cost of and the demand for drilling rigs, completion and production equipment, and other related services. However, changes in costs may not occur simultaneously with corresponding changes in commodity prices. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region. In addition, the recent economic and financial downturn has adversely affected the financial condition of some drilling contractors, which may constrain the availability of drilling services in some areas. 
+Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a materially adverse effect on our ability to explore on or develop our properties. 
+The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well if crude oil, natural gas, or NGLs are present, or whether they can be produced economically. The cost of drilling, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling and completion costs. 
+Drilling results in our newer shale plays, such as the Eagle Ford and Haynesville shales, may be more uncertain than results in shale plays that are more developed and have longer established production histories. For example, our experience with horizontal drilling in these shales, as well as the industry’s drilling and production history, is more limited than in many shale plays, such as the Barnett or Woodford shales, and we and the industry generally have less information with respect to the ultimate recoverability of reserves and the production decline rates in these shales than other areas with longer histories of drilling and production. Completion techniques that have proven to be successful in other shale formations to maximize recoveries are being used in the early development of these new shales; however, we can provide no assurance of the ultimate success of these drilling 
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+and completion techniques. 
+In addition, a significant part of our strategy involves increasing our inventory of drilling locations. Such multi-year drilling inventories can be more susceptible to long-term uncertainties that could materially alter the occurrence or timing of actual drilling. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled, although we have the present intent to do so, or if we will be able to produce crude oil, natural gas, or NGLs from these or any other potential drilling locations. 
+Our future drilling activities may not be successful. Our overall drilling success rate or our drilling success rate within a particular area may decline. In addition, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we may not be able to economically produce oil or natural gas from all of them. 
+Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory and delineation drilling in these plays are subject to drilling and completion technique risks, and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs, and the value of our undeveloped acreage could decline if drilling results are unsuccessful. 
+Many of our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore, and being able to run tools and recover equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools and other equipment the entire length of the well bore during completion operations, being able to recover such tools and other equipment, and successfully cleaning out the well bore after completion of the final fracture stimulation. 
+Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or prices for crude oil, natural gas, and NGL decline, then the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of our undeveloped acreage could decline in the future. 
+Uncertainties associated with enhanced recovery methods may result in us not realizing an acceptable return on our investments in such projects. 
+We inject water into formations on some of our properties to increase the production of crude oil, natural gas, and associated liquids. We may in the future expand these efforts to more of our properties or employ other enhanced recovery methods in our operations. The additional production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of crude oil, natural gas, and associated liquids in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects. In addition, if proposed legislation and regulatory initiatives relating to hydraulic fracturing become law, the cost of some of these enhanced recovery methods could increase substantially. 
+Our commodity derivative contract activities may result in financial losses or may limit the prices that we receive for crude oil, natural gas, and NGL sales. 
+To mitigate a portion of the exposure to potentially adverse market changes in crude oil, natural gas, and 
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+NGL prices and the associated impact on cash flows, the Company has entered into various derivative contracts. The Company’s derivative contracts in place include swap and collar arrangements for crude oil, natural gas, and NGLs. As of December 31, 2011, we were in a net accrued asset position of $31.2 million with respect to our crude oil, natural gas, and NGL derivative activities. These activities may expose us to the risk of financial loss in certain circumstances, including instances in which: 
+• 
+our production is less than expected; 
+• 
+one or more counterparties to our commodity derivative contracts default on their contractual obligations; or 
+• 
+there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement. 
+The risk of one or more counterparties defaulting on their obligations is heightened by the recent global and domestic economic and financial downturn affecting many banks and other financial institutions, including our counterparties and their affiliates. These circumstances may adversely affect the ability of our counterparties to meet their obligations to us pursuant to derivative transactions, which could reduce our revenues and cash flows from realized derivative cash settlements. As a result, our financial condition, results of operations, and cash flows could be materially affected in an adverse way if our counterparties default on their contractual obligations under our commodity derivative contracts. 
+In addition, commodity derivative contracts may limit the prices that we receive for our crude oil, natural gas and NGL sales if crude oil, natural gas, or NGL prices rise substantially over the price established by the commodity derivative contract. 
+The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results. 
+Substantially all of our accounts receivable result from crude oil, natural gas, and NGL sales or joint interest billings to co-owners of oil and gas properties we operate. This concentration of customers and joint interest owners may impact our overall credit risk because these entities may be similarly affected by various economic and other conditions, including the recent global and domestic economic and financial downturn. 
+In addition, for the year ended December 31, 2011, one customer, Regency, individually accounted for approximately 18 percent of our total production revenue. During 2010 and 2009, we had one customer each year, Regency and Teppco Crude Oil LLC, individually account for approximately 11 percent and 12 percent , respectively, of our total production revenue. The loss of one or more of these customers could reduce competition for our products and negatively impact the prices at which we sell such products. 
+We have entered into firm transportation contracts that require us to pay fixed amounts of money to our counterparties regardless of quantities actually shipped, processed, or gathered. If we are unable to deliver the necessary quantities of natural gas to our counterparties, our results of operations and liquidity could be adversely affected. 
+As of December 31, 2011, we were contractually committed to deliver 1,766 Bcf of natural gas and 9 MMbl of oil pursuant to contracts expiring at various dates through 2023. We may enter into additional firm transportation agreements as our development of our shale plays, including the Eagle Ford and Haynesville shales, expand. At the current time, we do not have enough proved developed reserves to offset these contractual liabilities, but we intend to develop reserves that will exceed the commitments and therefore do not expect any shortfalls. We expect our production volumes, as well as that of our competitors, to increase significantly in the Eagle Ford shale. The use of firm transportation commitments gives us the strategic advantage of priority space in a transportation pipeline. In the event we encounter delays in drilling and completing our wells or otherwise due to construction, interruptions of 
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+operations, or delays in connecting new volumes to gathering systems or pipelines for an extended period of time, the requirements to pay for quantities not delivered could have a material impact on our results of operations and liquidity. 
+Future crude oil, natural gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values. 
+We follow the successful efforts method of accounting for our crude oil and natural gas properties. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If commercial quantities of hydrocarbons are not discovered with an exploratory well, the costs of drilling the well are expensed. 
+The capitalized costs of our crude oil, natural gas, and NGL properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net revenues, we generally must write down the costs of each depletion pool to the estimated discounted future net cash flows of that depletion pool. Unproved properties are evaluated at the lower of cost or fair market value. We incurred an impairment of proved property and impairment of unproved properties totaling $219.0 million and $7.4 million , respectively, during 2011, $6.1 million and $2.0 million , respectively, during 2010, and $174.8 million and $45.4 million , respectively, during 2009. Significant further declines in crude oil, natural gas, or NGL prices in the future or unsuccessful exploration efforts could cause further impairment write-downs of capitalized costs. 
+We review the carrying value of our properties for indicators of impairment on a quarterly basis using the prices in effect as of the end of each quarter. Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date, even if crude oil, natural gas, or NGL prices increase. 
+Lower crude oil, natural gas, or NGL prices could limit our ability to borrow under our credit facility. 
+Our credit facility has a current commitment amount of $1.0 billion , subject to a borrowing base that the lenders periodically redetermine based largely on the bank group’s assessment of the value of our crude oil, natural gas, and NGL properties, which in turn is impacted by crude oil, natural gas, and NGL prices. The current borrowing base under our credit facility is $1.3 billion . Declines in crude oil, natural gas, or NGL prices in the future could limit our borrowing base and reduce our ability to borrow under our credit facility. Additionally, divestitures of properties could result in a reduction of our borrowing base. 
+Our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt. 
+As of December 31, 2011 , we had $285.1 million , net of debt discount, of total long-term senior unsecured debt outstanding under our 3.50% Senior Convertible Notes Due 2027 ("3.50% Senior Convertible Notes"); $350.0 million of long-term senior unsecured debt outstanding relating to our 6.625% Senior Notes that we issued on February 7, 2011; $350.0 million of long-term senior unsecured debt outstanding relating to our 6.50% Senior Notes that we issued on November 8, 2011; and no outstanding borrowings under our secured credit facility (other than two outstanding letters of credit in the aggregate amount of $608,000 , which reduce the amount available for borrowings under the facility on a dollar-for-dollar basis), resulting in $999.4 million of available debt capacity under our credit facility, assuming the borrowing conditions of this facility were met. Our long-term debt represented 40 percent of our total book capitalization as of December 31, 2011. 
+Our indebtedness could have important consequences for our operations, including: 
+• 
+making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements; 
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+Table of Contents 
+• 
+requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to productive investments; 
+• 
+limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends; 
+• 
+placing us at a competitive disadvantage compared to our competitors that have less debt; and 
+• 
+making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business. 
+Our ability to make payments on our debt and to refinance our debt and fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory, and other factors that are beyond our control. If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our credit facility or from other sources, we might not be able to service our debt or fund our other liquidity needs. If we are unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity securities, divest assets, or restructure or refinance our debt. We might not be able to sell our equity securities, sell our assets, or restructure or refinance our debt on a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our existing and future credit agreements, may prohibit us from pursuing any of these alternatives. Further, changes in the credit ratings of our debt may negatively affect the cost, terms, conditions, and availability of future financing. The indenture under our 3.50% Senior Convertible Notes provides that under certain circumstances we have the option to settle our obligations under these senior convertible notes through the issuance of shares of our common stock if we so elect. 
+Our debt agreements, including the agreement governing our credit facility and the indentures governing the 6.625% Senior Notes and 6.50% Senior Notes, permit us to incur additional debt in the future, subject to compliance with restrictive covenants under those agreements. In addition, entities we may acquire in the future could have significant amounts of debt outstanding that we could be required to assume, and in some cases accelerate repayment thereof, in connection with the acquisition, or we may incur our own significant indebtedness to consummate an acquisition. 
+As discussed above, our credit facility is subject to periodic borrowing base redeterminations. We could be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowing base or arrange new financing, we may be forced to sell significant assets. 
+The agreements governing our debt contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt. 
+Our debt agreements contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under our credit facility is subject to compliance with certain financial covenants, including (i) maintenance of a quarterly ratio of total debt to consolidated earnings before interest, taxes, depreciation, amortization, and exploration expense of no greater than 4.0 to 1.0, and (ii) maintenance of a current ratio of no less than 1.0 to 1.0, each as defined in our credit facility. Our credit facility also requires us to comply with certain financial covenants, including requirements that we maintain certain levels of stockholders’ equity and limit our annual cash dividends to no more than $50.0 million . These restrictions on our ability to operate our business could seriously harm our business by, among other things, limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate opportunities. 
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+The respective indentures governing the 6.625% Senior Notes and the 6.50% Senior Notes also contain covenants that, among other things, limit our ability and the ability of our subsidiaries to: 
+• 
+incur additional debt; 
+• 
+make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire capital stock; 
+• 
+sell assets, including capital stock of our subsidiaries; 
+• 
+restrict dividends or other payments of our subsidiaries; 
+• 
+create liens that secure debt; 
+• 
+enter into transactions with affiliates; and 
+• 
+merge or consolidate with another company. 
+Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all or a portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness. 
+We are subject to operating and environmental risks and hazards that could result in substantial losses. 
+Crude oil and natural gas operations are subject to many risks, including human error and accidents that could cause personal injury, death and property damage, well blowouts, craterings, explosions, uncontrollable flows of crude oil, natural gas and associated liquids or well fluids, fires, adverse weather such as hurricanes in the South Texas & Gulf Coast region, freezing conditions in the Williston Basin of our Rocky Mountain region, floods, droughts, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas such as hydrogen sulfide, and other environmental risks and hazards. If any of these types of events occurs, we could sustain substantial losses. 
+There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our current and past generation, handling and disposal of materials, including solid and hazardous wastes and petroleum hydrocarbons. We may incur joint and several, strict liability under applicable United States federal and state environmental laws in connection with releases of petroleum hydrocarbons and other hazardous substances at, on, under or from our leased or owned properties, some of which have been used for natural gas and oil exploration and production activities for a number of years, often by third parties not under our control. For our non-operated properties, we are dependent on the operator for operational and regulatory compliance, and could be subject to liabilities in the event of non-compliance. These properties and the wastes disposed thereon or away from could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including the CERCLA or the Superfund law, the RCRA, the Clean Water Act, the CAA, the OPA, and analogous state laws. Under any implementing regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damage allegedly caused by the release of petroleum hydrocarbons or other wastes into the environment. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur losses. 
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+We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden environmental damage. We do not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damage or insurance coverage for environmental damage that occurs over time is available at a reasonable cost. In addition, pollution and environmental risks generally are not fully insurable. Further, we may elect not to obtain other insurance coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks to which we are subject. Accordingly, we may be subject to liability or may lose substantial assets in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer a material loss. 
+Following the severe Atlantic hurricanes in 2004, 2005, and 2008, the insurance markets suffered significant losses. As a result, insurance coverage for wind storms has become substantially more expensive, and future availability and costs of coverage are uncertain. 
+Our operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs and other risks. 
+Federal, state, tribal, and local authorities extensively regulate the oil and natural gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may become more stringent and, as a result, may affect, among other things, the pricing or marketing of crude oil, natural gas and NGL production. Noncompliance with statutes and regulations and more vigorous enforcement of such statutes and regulations by regulatory agencies may lead to substantial administrative, civil, and criminal penalties, including the assessment of natural resource damages, the imposition of significant investigatory and remedial obligations and may also result in the suspension or termination of our operations. The overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells and related facilities and, in turn, decreases profitability. 
+Governmental authorities regulate various aspects of drilling for and the production of crude oil, natural gas, and NGLs, including the permit and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in crude oil and natural gas properties, rights-of-way and easements, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment, and restoration standards, oil and gas operations, and restoration. Public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain projects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or impose conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or develop certain properties. Federal authorities also may require any of our ongoing or planned operations on federal leases to be delayed, suspended, or terminated. Any such delay, suspension, or termination could have a materially adverse effect on our operations. 
+Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, tribal and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. Under existing or future environmental laws and regulations, we could incur significant liability, including joint and several, strict liability under federal, state, and tribal environmental laws for noise emissions and for discharges of crude oil, natural gas, and associated liquids or other pollutants into the air, soil, surface water, or groundwater. We could be required to spend substantial amounts on investigations, litigation, and remediation for these discharges and other compliance issues. Any unpermitted release of petroleum or other pollutants from our operations could result not only in cleanup costs, but also natural resources, real or personal property and other compensatory damages and civil and criminal liability. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a materially adverse effect on us. 
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+Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. 
+Operations in certain of our regions, such as our Rocky Mountain and Permian regions, are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. Wildlife seasonal restrictions may limit access to federal leases or across federal lands. Possible restrictions may include seasonal restrictions in greater sage-grouse habitat during breeding and nesting seasons, within a certain distance of active raptor nests during fledging, and in big game winter or parturition ranges during winter or calving seasons. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. 
+Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. 
+Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of oil, natural gas and associated liquids from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques to many of our oil and natural gas properties, including our unconventional resource plays in the Granite Wash of Texas and Oklahoma, the Eagle Ford shale of south Texas, and the Bakken/Three Forks formations in North Dakota. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and natural gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving the use of diesel in the fluid system under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. If hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit or disclosure requirements or operational restrictions and also to associated permitting delays, litigation risk, and potential cost increases. 
+Certain states that we operate in, including Pennsylvania, Texas, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas ("RCT") and the public of certain information regarding the components and volume of water used in the hydraulic fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling and/or completion of wells. 
+There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating a review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the United States Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the United States 
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+Department of the Interior is developing disclosure requirements or other mandates for hydraulic fracturing on federal lands. 
+Additionally, certain members of Congress have called upon the United States Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the United States Securities and Exchange Commission to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the United States Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their course and outcomes, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory processes. 
+Further, on July 28, 2011, the EPA issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards ("NSPS") and National Emission Standards for Hazardous Air Pollutants ("NESHAPS") programs. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion ("REC") techniques developed in EPA's Natural Gas STAR program along with the pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology ("MACT") standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. We are currently evaluating the effect these proposed rules could have on our business. Final action on the proposed rules is expected by March or April, 2012. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing such activity to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. Additional legislation or regulation could also lead to operational delays or increased costs in the exploration for and production of oil, natural gas, and associated liquids, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state, or local laws, or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and delays, which could adversely affect our financial position, results of operations, and cash flows. 
+On October 20, 2011, the EPA announced a schedule for development of standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works ("POTWs"). The regulations will be developed under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. The EPA anticipates issuing the proposed rules in 2014. 
+Our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations and/or completions or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules. 
+The hydraulic fracturing process on which we depend to drill for commercial quantities of crude oil, natural gas, and associated liquids requires the use and disposal of significant quantities of water. 
+Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or 
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+disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of natural gas. 
+Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition. 
+Certain United States federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation . 
+On September 12, 2011, President Obama sent to Congress a legislative package that included proposed legislation that, if enacted into law, would eliminate certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, among other proposals: 
+• 
+the repeal of the percentage depletion allowance for oil and natural gas properties; 
+• 
+the elimination of current deductions for intangible drilling and development costs; 
+• 
+the elimination of the deduction for certain domestic production activities; and 
+• 
+an extension of the amortization period for certain geological and geophysical expenditures. 
+These proposals also were included in President Obama's Proposed Fiscal Year 2012 Budget. It is unclear whether these or similar changes will be enacted. The passage of this legislation or any similar changes in federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows. 
+Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for crude oil, natural gas, and NGLs. 
+In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other "greenhouse gases" present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. For example, the EPA has adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other regulates the permitting and emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011. In the courts, several cases are pending that may increase the risk of claims being filed against companies that have significant greenhouse gas emissions. Such cases seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property. Any laws or regulations that restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas that we produce. 
+In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce 
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+emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. 
+The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, gas, and NGLs we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition, and results of operations. Finally, it should be noted that some scientists have predicted that increasing concentrations of greenhouse gases in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If such effects were to occur, our operations could be adversely affected. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from flooding or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. 
+The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), which was signed into law on July 21, 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Commodities Futures Trading Commission (the "CFTC") is required to implement rules relating to these activities by July 16, 2012. On October 18, 2011, the CFTC approved regulations to set position limits for certain futures and option contracts in the major energy markets, which regulations are presently being challenged in federal court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association. The Dodd-Frank Act may also require us to comply with margin requirements and with certain clearing and trade execution requirements in our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. 
+The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows. 
+Our ability to sell crude oil, natural gas and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines and other transportation 
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+Table of Contents 
+systems owned or operated by others or by other interruptions. 
+The marketability of our crude oil, natural gas, and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing facilities, and pipeline and other transportation systems owned or operated by third parties. The lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay or discontinuance of development plans for our properties, or lower price realizations. Although we have some contractual control over the processing and transportation of our production, material changes in these business relationships could materially affect our operations. Federal and state regulation of crude oil, natural gas, and NGLs production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process, and transport crude oil, natural gas, and NGLs. 
+In particular, if drilling in the Eagle Ford shale, Haynesville shale, Bakken/Three Forks resource play, and Granite Wash resource play continues to be successful, the amount of crude oil, natural gas, and NGLs being produced by us and others could exceed the capacity of, and result in strains on, the various gathering and transportation systems, pipelines, processing facilities, and other infrastructure available in these areas. It will be necessary for additional infrastructure, pipelines, gathering and transportation systems and processing facilities to be expanded, built or developed to accommodate anticipated production from these areas. Because of the current economic climate, certain processing, pipeline, and other gathering or transportation projects that might be, or are being, considered for these areas may not be developed timely or at all due to lack of financing or other constraints. In addition, capital and other constraints could limit our ability to build or access intrastate gathering and transportation systems necessary to transport our production to interstate pipelines or other points of sale or delivery. In such event, we might have to delay or discontinue development activities or shut in our wells to wait for sufficient infrastructure development or capacity expansion and/or sell production at significantly lower prices, which would adversely affect our results of operations and cash flows. 
+A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flows and results of operations. 
+New technologies may cause our current exploration and drilling methods to become obsolete. 
+The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected. 
+Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions. 
+As a crude oil, natural gas, and NGL producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance 
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+Table of Contents 
+that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows. 
+Cybersecurity attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. 
+The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for crude oil, natural gas, and NGLs, all of which could adversely affect the markets for our operations. Energy assets might be specific targets of terrorist attacks. These developments have subjected our operations to increased risk and, depending on their occurrence and ultimate magnitude, could have a material adverse effect on our business. 
+Risks Related to Our Common Stock 
+The price of our common stock may fluctuate significantly, which may result in losses for investors. 
+From January 1, 2011, to February 16, 2012 , the closing daily sale price of our common stock as reported by the New York Stock Exchange ranged from a low of $56.04 per share in January 2011 to a high of $86.85 per share in October 2011. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include: 
+• 
+changes in crude oil, natural gas, or NGL prices; 
+• 
+variations in drilling, recompletion, and operating activity; 
+• 
+changes in financial estimates by securities analysts; 
+• 
+changes in market valuations of comparable companies; 
+• 
+additions or departures of key personnel; 
+• 
+future sales of our common stock; and 
+• 
+changes in the national and global economic outlook. 
+We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could decline as a result. 
+Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment. 
+Our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or preventing a change of control. These provisions, among other things, provide for non-cumulative voting in the election of members of the Board of Directors and impose procedural requirements on stockholders who wish to make nominations for the election of directors or propose other actions at stockholder meetings. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock. 
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+Shares eligible for future sale may cause the market price of our common stock to drop significantly, even if our business is doing well. 
+The potential for sales of substantial amounts of our common stock in the public market may have a materially adverse effect on our stock price. As of February 16, 2012 , 64,068,540 shares of our common stock were freely tradable without substantial restriction or the requirement of future registration under the Securities Act of 1933. Also as of that date, options to purchase 458,263 shares of our common stock were outstanding, all of which were exercisable. These options are exercisable at prices ranging from $10.86 to $20.87 per share. In addition, restricted stock units (“RSUs”) providing for the issuance of up to a total of 308,412 shares of our common stock and 1,230,814 performance share units ("PSUs") were outstanding. PSUs are structurally the same as the previously granted Performance Share Awards or ("PSAs") (collectively known as "Performance Share Units" or "PSUs"). The PSUs represent the right to receive, upon settlement of the PSUs after the completion of a three-year performance period, a number of shares of our common stock that may be from zero to two times the number of PSUs granted, depending on the extent to which the underlying performance criteria have been achieved and the extent to which the PSUs have vested. In addition, we may issue additional shares of our common stock in connection with a put or conversion of our 3.50% Senior Convertible Notes. As of February 16, 2012 , there were 64,114,366 shares of our common stock outstanding, which is net of 81,067 treasury shares. 
+We may not always pay dividends on our common stock. 
+Payment of future dividends remains at the discretion of the Board of Directors, and will continue to depend on our earnings, capital requirements, financial condition, and other factors. In addition, the payment of dividends is subject to a covenant in our credit facility limiting our annual cash dividends to no more than $50.0 million , and to covenants in the indentures for our 6.625% Senior Notes and 6.50% Senior Notes that limit our ability to pay dividends beyond a certain amount. Our Board of Directors may determine in the future to reduce the current semi-annual dividend rate of $0.05 per share, or discontinue the payment of dividends altogether. 
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+ITEM 1B. UNRESOLVED STAFF COMMENTS 
+We have no unresolved comments from the SEC staff regarding our periodic or current reports under the Securities Exchange Act of 1934. 
+ITEM 3. LEGAL PROCEEDINGS 
+From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. As of the filing date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows. 
+We note that approximately 22,000 acres of our approximately 196,000 net acres in the Eagle Ford shale play in South Texas are the subject of a lawsuit captioned W.H. Sutton, et al. vs. St. Mary Land & Exploration Co., et al. instituted in the District Court of Webb County in and for the 49 th Judicial District of Texas on May 13, 2010. The plaintiffs claim an aggregate overriding royalty interest of 7.46875% in production attributable to a 1966 oil, gas and mineral lease, and that such overriding royalty interest attaches to subsequent leases currently affecting the acreage that is the subject of the lawsuit, which had been released from the 1966 lease. At the original lease date, the 1966 lease was executed for approximately 40,000 acres. The plaintiffs seek to quiet title to their claimed overriding royalty interest and the recovery of unpaid overriding royalty interest proceeds allegedly due. We believe that the claimed overriding royalty interest has been terminated under the governing agreements and the applicable law, and have contested the plaintiffs’ claims. Both parties filed motions for summary judgment, and on February 8, 2011, the District Court issued an order granting plaintiffs’ motion for summary judgment and denying our motion for summary judgment. The order granting plaintiffs’ motion for summary judgment did not award damages but reserved such determination for final order. We believe that the summary judgment is incorrect under the governing agreements and applicable law, and we have appealed the court's ruling. On September 30, 2011, the District Court entered final judgment for the plaintiffs and awarded damages of approximately $5.1 million, which includes prejudgment interest. The District Court also awarded attorneys fees and costs. We have appealed the District Court's judgment and obtained a stay pending appeal that prevents the plaintiffs from executing on the judgment. 
+We believe this lawsuit is entirely without merit and we will continue to vigorously contest this litigation. However, we cannot predict the ultimate outcome of this lawsuit. If the plaintiffs were to ultimately prevail, the overriding royalty interest would have the effect of reducing our net revenue interest in the affected acreage, which would negatively impact our economics in this portion of our acreage, but we do not believe would have a material adverse effect upon our financial condition, results of operations, or cash flows. For a more detailed discussion of our Eagle Ford shale play, see Core Operational Areas, South Texas & Gulf Coast Region in Part I, Items 1 and 2 of this report. 
+We recently filed, in Webb County, Texas, a declaratory judgment action, captioned SM Energy Company vs. W.H. Sutton, et al. , seeking a judgment declaring that the 1966 lease terminated with respect to the remaining 18,000 acres, based upon a failure of continuous development, and that any overriding royalty interest claimed by the defendants' has been extinguished. 
+ITEM 4. MINE SAFETY DISCLOSURES 
+These disclosures are not applicable to us. 
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+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Market Information. Our common stock is currently traded on the New York Stock Exchange under the ticker symbol “SM”. The following table presents the range of high and low intraday sales prices per share for the indicated quarterly periods in 2011 and 2010, as reported by the New York Stock Exchange: 
+Quarter Ended 
+High 
+Low 
+December 31, 2011 
+$ 
+88.50 
+$ 
+53.45 
+September 30, 2011 
+85.55 
+60.52 
+June 30, 2011 
+78.55 
+61.37 
+March 31, 2011 
+75.00 
+54.59 
+December 31, 2010 
+$ 
+59.82 
+$ 
+37.30 
+September 30, 2010 
+44.93 
+33.80 
+June 30, 2010 
+49.13 
+35.29 
+March 31, 2010 
+38.18 
+30.70 
+PERFORMANCE GRAPH 
+The following performance graph compares the cumulative return on our common stock, for the period beginning December 31, 2006, and ending on December 31, 2011, with the cumulative total returns of the Dow Jones U.S. Exploration and Production Board Index, and the Standard & Poor’s 500 Stock Index. 
+COMPARE 5-YEAR CUMULATIVE TOTAL RETURN 
+The preceding information under the caption Performance Graph shall be deemed to be furnished, but not filed with the Securities and Exchange Commission. 
+Holders. As of February 16, 2012, the number of record holders of SM Energy's common stock was 90. Based upon inquiry, SM Energy had approximately 35,800 beneficial owners of its common stock in 2011. 
+Dividends. We have paid cash dividends to our stockholders every year since 1940. Annual dividends of $0.05 per share were paid in each of the years 1998 through 2004. Annual dividends of $0.10 per share were paid in 2005 through 2011. We expect that our practice of paying dividends on our common stock will continue, 
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+although the payment of future dividends will continue to depend on our earnings, cash flow, capital requirements, financial condition, and other factors, including the discretion of our Board of Directors. In addition, the payment of dividends is subject to covenants in our credit facility that limit our annual dividend payment to no more than $50.0 million per year. We are also subject to certain covenants under our 6.625% Senior Notes and 6.50% Senior Notes that restrict certain payments, including dividends; provided, however, the first $6.5 million of dividends paid each year are not restricted by this covenant. Based on our current performance, we do not anticipate that these covenants will restrict future annual dividend payments of $0.10 per share of common stock. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $6.4 million in 2011 and $6.3 million in 2010. 
+Restricted Shares. We have no restricted shares outstanding as of December 31, 2011, aside from Rule 144 restrictions on shares held by insiders and shares issued to members of the Board of Directors under our Equity Incentive Compensation Plan (“Equity Plan”). 
+Purchases of Equity Securities by the Issuer and Affiliated Purchasers. The following table provides information about purchases by the Company and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the indicated quarters and year ended December 31, 2011, of shares of the Company’s common stock, which is the sole class of equity securities registered by the Company pursuant to Section 12 of the Exchange Act. 
+ISSUER PURCHASES OF EQUITY SECURITIES 
+Total Number of Shares Purchased (1) 
+Average Price Paid per Share 
+Total Number of Shares Purchased as Part of Publicly Announced Program 
+Maximum Number of Shares that May Yet be Purchased Under the Program (2) 
+January 1, 2011 – 
+March 31, 2011 
+8,878 
+$ 
+72.47 
+— 
+3,072,184 
+April 1, 2011 - 
+June 30, 2011 
+— 
+$ 
+— 
+— 
+3,072,184 
+July 1, 2011 - 
+September 30, 2011 
+123,504 
+$ 
+75.49 
+— 
+3,072,184 
+October 1, 2011 - 
+October 31, 2011 
+— 
+$ 
+— 
+— 
+3,072,184 
+November 1, 2011 - 
+November 30, 2011 
+88 
+$ 
+78.92 
+— 
+3,072,184 
+December 1, 2011 - 
+December 31, 2011 
+— 
+$ 
+— 
+— 
+3,072,184 
+Total October 1, 2011 - 
+December 31, 2011 
+88 
+$ 
+78.92 
+— 
+3,072,184 
+Total 
+132,470 
+$ 
+75.29 
+— 
+3,072,184 
+(1) 
+All shares purchased in 2011 were to offset tax withholding obligations that occur upon the delivery of outstanding shares underlying RSUs and PSUs delivered under the terms of grants under the Equity Plan. 
+(2) 
+In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of this filing, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility, the indentures governing our 6.625% Senior Notes and 6.50% Senior Notes and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow, or borrowings under our credit facility. The stock repurchase program may be suspended or discontinued at any time. Please refer to Dividends above for a description of our dividend limitations. 
+50 
+Table of Contents 
+ITEM 6. SELECTED FINANCIAL DATA 
+The following table sets forth selected supplemental financial and operating data for us as of the dates and periods indicated. The financial data for each of the five years presented were derived from our consolidated financial statements. The following data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report, which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our consolidated financial statements included in this report. 
+Years Ended December 31, 
+2011 
+2010 
+2009 
+2008 
+2007 
+(in millions, except per share data) 
+Total operating revenues 
+$ 
+1,603.3 
+$ 
+1,092.8 
+$ 
+832.2 
+$ 
+1,301.3 
+$ 
+990.1 
+Net income (loss) 
+$ 
+215.4 
+$ 
+196.8 
+$ 
+(99.4 
+) 
+$ 
+87.3 
+$ 
+187.1 
+Net income (loss) per share: 
+Basic 
+$ 
+3.38 
+$ 
+3.13 
+$ 
+(1.59 
+) 
+$ 
+1.40 
+$ 
+3.02 
+Diluted 
+$ 
+3.19 
+$ 
+3.04 
+$ 
+(1.59 
+) 
+$ 
+1.38 
+$ 
+2.90 
+Total assets at year-end 
+$ 
+3,799.0 
+$ 
+2,744.3 
+$ 
+2,360.9 
+$ 
+2,697.2 
+$ 
+2,572.9 
+Long-term debt: 
+Line of credit 
+$ 
+— 
+$ 
+48.0 
+$ 
+188.0 
+$ 
+300.0 
+$ 
+285.0 
+3.50% Senior Convertible Notes, net of debt discount 
+$ 
+285.1 
+$ 
+275.7 
+$ 
+266.9 
+$ 
+258.7 
+$ 
+251.1 
+6.625% Senior Notes 
+$ 
+350.0 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+6.50% Senior Notes 
+$ 
+350.0 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Cash dividends declared and paid per common share 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+51 
+Table of Contents 
+Supplemental Selected Financial and Operations Data 
+Years Ended December 31, 
+2011 
+2010 
+2009 
+2008 
+2007 
+Balance Sheet Data (in millions) 
+Total working capital (deficit) 
+$ 
+(42.6 
+) 
+$ 
+(227.4 
+) 
+$ 
+(87.6 
+) 
+$ 
+15.2 
+$ 
+(92.6 
+) 
+Total stockholders’ equity 
+$ 
+1,462.9 
+$ 
+1,218.5 
+$ 
+973.6 
+$ 
+1,162.5 
+$ 
+902.6 
+Weighted-average common shares outstanding (in thousands) 
+Basic 
+63,755 
+62,969 
+62,457 
+62,243 
+61,852 
+Diluted 
+67,564 
+64,689 
+62,457 
+63,133 
+64,850 
+Reserves 
+Oil (MMBbl) 
+71.7 
+57.4 
+53.8 
+51.4 
+78.8 
+Gas (Bcf) 
+664.0 
+640.0 
+449.5 
+557.4 
+613.5 
+NGLs (MMBbl) 
+27.5 
+— 
+— 
+— 
+— 
+BCFE 
+1,259.2 
+984.5 
+772.2 
+865.5 
+1,086.5 
+Production and Operational (in millions) 
+Oil, gas, and NGL production revenues 
+$ 
+1,332.4 
+$ 
+836.3 
+$ 
+616.0 
+$ 
+1,259.4 
+$ 
+912.1 
+Oil, gas, and NGL production expenses 
+$ 
+290.1 
+$ 
+195.1 
+$ 
+206.8 
+$ 
+271.4 
+$ 
+218.2 
+DD&A 
+$ 
+511.1 
+$ 
+336.1 
+$ 
+304.2 
+$ 
+314.3 
+$ 
+227.6 
+General and administrative 
+$ 
+118.5 
+$ 
+106.7 
+$ 
+76.0 
+$ 
+79.5 
+$ 
+60.1 
+Production Volumes 
+Oil (MMBbl) 
+8.1 
+6.4 
+6.3 
+6.6 
+6.9 
+Gas (Bcf) 
+100.3 
+71.9 
+71.1 
+74.9 
+66.1 
+NGLs (MMBbl) 
+3.5 
+— 
+— 
+— 
+— 
+BCFE 
+169.7 
+110.0 
+109.1 
+114.6 
+107.5 
+Realized price 
+Oil (per Bbl) 
+$ 
+88.23 
+$ 
+72.65 
+$ 
+54.40 
+$ 
+92.99 
+$ 
+67.56 
+Gas (per Mcf) 
+$ 
+4.32 
+$ 
+5.21 
+$ 
+3.82 
+$ 
+8.60 
+$ 
+6.74 
+NGL (per Bbl) 
+$ 
+53.32 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Adjusted price (net of derivative cash settlements) 
+Oil (per Bbl) 
+$ 
+78.89 
+$ 
+66.85 
+$ 
+56.74 
+$ 
+75.59 
+$ 
+62.60 
+Gas (per Mcf) 
+$ 
+4.80 
+$ 
+6.05 
+$ 
+5.59 
+$ 
+8.79 
+$ 
+7.63 
+NGL (per Bbl) 
+$ 
+47.90 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Expense per MCFE 
+LOE 
+$ 
+0.88 
+$ 
+1.10 
+$ 
+1.33 
+$ 
+1.46 
+$ 
+1.31 
+Transportation 
+$ 
+0.51 
+$ 
+0.19 
+$ 
+0.19 
+$ 
+0.19 
+$ 
+0.14 
+Production taxes 
+$ 
+0.32 
+$ 
+0.48 
+$ 
+0.37 
+$ 
+0.71 
+$ 
+0.58 
+DD&A 
+$ 
+3.01 
+$ 
+3.06 
+$ 
+2.79 
+$ 
+2.74 
+$ 
+2.12 
+General and administrative 
+$ 
+0.70 
+$ 
+0.97 
+$ 
+0.70 
+$ 
+0.69 
+$ 
+0.56 
+Statement of Cash Flow Data (in millions) 
+Provided by operations 
+$ 
+760.5 
+$ 
+497.1 
+$ 
+436.1 
+$ 
+679.2 
+$ 
+632.1 
+(Used in) investing 
+$ 
+(1,264.9 
+) 
+$ 
+(361.6 
+) 
+$ 
+(304.1 
+) 
+$ 
+(673.8 
+) 
+$ 
+(805.1 
+) 
+Provided by (used in) financing 
+$ 
+618.5 
+$ 
+(141.1 
+) 
+$ 
+(127.5 
+) 
+$ 
+(42.8 
+) 
+$ 
+215.1 
+Note: Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head. Beginning in the first quarter of 2011, we changed our reporting for natural gas volumes to separately show natural gas and NGL production volumes, revenues, and pricing consistent with title transfer for each product. Please refer to additional discussion above under the caption Oil, Gas, and NGL Prices in Part II, Item 7 of this report. 
+52 
+Table of Contents 
+ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+This discussion includes forward-looking statements. Please refer to Cautionary Information about Forward-Looking Statements in Part I, Items 1 and 2 of this report for important information about these types of statements. 
+Overview of the Company 
+General Overview 
+We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America. Our assets include leading positions in the Eagle Ford shale and Bakken/Three Forks resource plays, as well as meaningful positions in the Granite Wash, Haynesville shale, and Woodford shale resource plays. We have built a portfolio of onshore properties in the contiguous United States primarily through early entrance into existing and emerging resource plays. This portfolio is comprised of properties with established production and reserves, prospective drilling opportunities, and unconventional resource prospects. We believe our strategy provides for stable and predictable production and reserve growth. Furthermore, by entering these plays early, we believe that we can capture larger resource potential at a lower cost. 
+In general, we generate almost all of our revenues and cash flows from the sale of produced oil, gas and NGLs. In 2011, we also generated meaningful gains and cash proceeds from the divestiture of oil and gas properties. Please refer to the discussion below under 2011 Highlights . 
+Our business strategy is focused on the early capture of resource plays in order to create and then enhance value for our shareholders, while maintaining a strong balance sheet. We strive to leverage industry leading exploration and leasehold acquisition teams to quickly acquire and test new resource play concepts at a reasonable cost. Once we have captured potential value through these efforts, our goal is to develop such potential through top tier operational and project execution, and as appropriate, mitigate our risk in asset development by divesting of all or a portion of certain assets. We continually examine our portfolio for opportunities to improve the quality of our asset base in order to maximize our returns and preserve our financial strength. 
+In 2011 we had the following financial and operational results: 
+• 
+At year-end 2011, we had estimated proved reserves of 1,259.2 BCFE, of which 53 percent was natural gas and 67 percent was characterized as proved developed. We added 526.1 BCFE from our drilling program, the majority of which related to our activity in the Eagle Ford shale in South Texas, the Bakken/Three Forks plays in North Dakota, and the Haynesville Shale in East Texas. We sold 93.1 BCFE of proved reserves during the year related to assets located primarily in our South Texas & Gulf Coast region. We had negative price revisions that decreased our estimated proved reserves by 25.3 BCFE due to lower commodity prices in our gas-weighted regions. The prices used in the calculation of proved reserve estimates as of December 31, 2011, were $96.19 per Bbl, $4.12 per MMBtu, and $59.37 per Bbl, for oil, natural gas, and NGLs, respectively. These prices were 21 percent higher for oil and six percent lower for natural gas than the prices used at year-end 2010. Performance revisions in 2011 resulted in a net 36.8 BCFE increase in our estimate of proved reserves. This increase includes the impact of our conversion to three stream production, which is partially offset by negative engineering revisions due primarily to the failure of Woodford shale wells in our Mid-Continent region to satisfy our internal economic hurdles due to current commodity prices and well costs. 
+• 
+The PV-10 value of our estimated proved reserves was $3.5 billion as of December 31, 2011, compared with $2.3 billion as of December 31, 2010. The after tax value, represented by the standardized measure calculation, was $2.6 billion as of December 31, 2011, compared with $1.7 billion as of 
+53 
+Table of Contents 
+December 31, 2010. The standardized measure calculation is presented in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown under Reserves in Part I, Items 1 and 2 of this report. 
+• 
+We had record production in 2011. Our average daily production in 2011 was 274.8 MMcf of gas, 22.1 MBbl of oil, and 9.6 MBbl of NGLs, for an average equivalent production rate of 465.0 MMCFE, compared with 301.4 MMCFE in 2010, an increase of 54 percent year over year. 
+• 
+We had record net income of $215.4 million and diluted earnings per share of $3.19 for the year ended December 31, 2011. This compares with net income of $196.8 million , or $3.04 per diluted share, for the year ended December 31, 2010. 
+• 
+We had record cash flow from operating activities of $760.5 million for the year ended December 31, 2011, compared with $497.1 million as of December 31, 2010, which was an increase of 53 percent year over year. 
+• 
+Costs incurred for oil and gas producing activities for the year ended December 31, 2011, were $1.6 billion , compared with $877.4 million for the same period in 2010. 
+Reserve Replacement, Finding and Development Costs, and Growth 
+Like all oil and gas exploration and production companies, we face the challenge of growing proved reserves. An exploration and production company depletes part of its asset base with each unit of oil, gas, or NGL it produces. Our future growth will depend on our ability to organically and economically add reserves in excess of production. 
+The following table provides various reserve replacement and finding and development cost metrics for the year ended December 31, 2011: 
+Reserve Replacement Percentage 
+Finding and Development Cost per MCFE 
+Excluding Divestitures 
+Including Divestitures 
+Excluding Divestitures 
+Including Divestitures 
+Drilling, excluding revisions 
+310 
+% 
+255 
+% 
+$ 
+2.85 
+$ 
+3.46 
+Drilling, including revisions 
+317 
+% 
+262 
+% 
+$ 
+2.79 
+$ 
+3.37 
+Drilling and acquisitions, excluding revisions 
+310 
+% 
+255 
+% 
+$ 
+2.85 
+$ 
+3.46 
+Drilling and acquisitions, including revisions 
+317 
+% 
+262 
+% 
+$ 
+2.79 
+$ 
+3.37 
+Reserve Acquisitions* 
+N/A* 
+N/A* 
+N/A* 
+N/A* 
+All-in 
+317 
+% 
+262 
+% 
+$ 
+2.89 
+$ 
+3.50 
+*There were no proved reserve acquisitions in 2011. 
+54 
+Table of Contents 
+The following table provides average reserve replacement and finding and development cost metrics for the three-year period ended December 31, 2011: 
+Reserve Replacement Percentage 
+Finding and Development Cost per MCFE 
+Excluding Divestitures 
+Including Divestitures 
+Excluding Divestitures 
+Including Divestitures 
+Drilling, excluding revisions 
+262 
+% 
+205 
+% 
+$ 
+2.65 
+$ 
+3.39 
+Drilling, including revisions 
+259 
+% 
+201 
+% 
+$ 
+2.68 
+$ 
+3.45 
+Drilling and acquisitions, excluding revisions 
+262 
+% 
+205 
+% 
+$ 
+2.65 
+$ 
+3.39 
+Drilling and acquisitions, including revisions 
+259 
+% 
+201 
+% 
+$ 
+2.68 
+$ 
+3.45 
+Reserve Acquisitions 
+N/M * 
+N/M * 
+$ 
+3.36 
+N/M * 
+All-in 
+259 
+% 
+201 
+% 
+$ 
+2.83 
+$ 
+3.64 
+* N/M – Percentage or amount, as applicable, is not meaningful. 
+Our challenge is to grow net asset value per share, which we believe drives appreciation in our stock price over the long term. To accomplish this, we believe it is important to organically and economically replace annual production with new reserves. We believe annual reserve replacement percentage and finding and development costs are important analytical measures that are widely used by investors and industry peers in evaluating and comparing the performance of oil and gas companies. While single-year measurements have some meaning in terms of a trend, we believe that aberrations, causing both good and bad results, will occur over short intervals of time. The information used to calculate the above reserve replacement and finding and development cost metrics is included in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. For additional information about these metrics, see the reserve replacement and finding and development cost terms in the Glossary of Oil and Gas Terms at the end of Part I, Items 1 and 2 of this report. 
+Oil, Gas, and NGL Prices 
+Our financial condition and the results of our operations are significantly affected by the prices we receive for oil, gas, and NGL production, which can fluctuate dramatically. Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head. As a result, we reported realized prices for our natural gas production for periods through December 31, 2010, that were higher than industry benchmarks due to the price uplift associated with incremental value contained in the higher BTU content of our produced gas stream. Beginning in the first quarter of 2011, we changed our reporting for natural gas volumes to show natural gas and NGL production volumes consistent with title transfer for each product. Projected rapid production growth from our NGL-rich assets associated with plant product sales contracts necessitated a change in our reporting of production volumes. Prior period production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of the NGL volumes produced in prior periods. We sell the majority of our natural gas under contracts using first-of-the-month index pricing, which means gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day the gas is produced. For assets where high BTU gas is sold at the wellhead, we also receive additional value for the high energy content contained in the gas stream. Our NGL production is generally sold using contracts paying us a monthly average of the posted OPIS Mont Belvieu daily settlement prices, adjusted for processing, transportation, and location differentials. Our crude oil and condensate are sold using contracts paying us either the average of the NYMEX WTI daily settlement price or the average of alternative posted prices for the periods in which the product is produced, adjusted for quality, transportation, and location differentials. 
+55 
+Table of Contents 
+The following table is a summary of commodity price data for the years ended December 31, 2011, 2010, and 2009. 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+Crude Oil (per Bbl): 
+Average NYMEX price 
+$ 
+95.05 
+$ 
+79.51 
+$ 
+61.99 
+Realized price 
+$ 
+88.23 
+$ 
+72.65 
+$ 
+54.40 
+Natural Gas (per Mcf): 
+Average NYMEX price 
+$ 
+4.00 
+$ 
+4.37 
+$ 
+3.94 
+Realized price 
+$ 
+4.32 
+$ 
+5.21 
+$ 
+3.82 
+NGLs (per Bbl): 
+Average OPIS price 
+$ 
+59.47 
+$ 
+34.61 
+$ 
+46.92 
+Realized price 
+$ 
+53.32 
+N/A 
+N/A 
+Note: Prior year NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of NGL volumes in prior periods. Please refer to additional discussion above. Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 6% Isobutane, 11% Normal Butane, 14% Natural Gasoline and 32% Propane for all periods presented. 
+We expect future prices for oil, gas, and NGLs to be volatile. In addition to supply and demand fundamentals, as a global commodity, the price of oil will likely continue to be impacted by real or perceived geopolitical risks in oil producing regions of the world, particularly in the Middle East. Additionally, the relative strength of the U.S. Dollar compared to other currencies could affect the price of oil. The supply of NGLs in the U.S. is expected to grow in the near term as a result of a number of industry participants targeting projects that produce these products, which could negatively impact future pricing. The pricing of several of the specific NGL products have strong correlations to the price of oil and accordingly are likely to directionally follow that market. Natural gas prices are under downward pressure due to current market oversupply because of high levels of drilling activity, a warmer than expected heating season, and slow economic growth. The 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (same product mix as discussed above) as of December 31, 2011, were $98.85 per Bbl of oil, $3.30 per MMBtu of gas, and $55.78 per Bbl of NGLs, respectively. Comparable prices as of February 16, 2012, were $104.02 per Bbl, $3.11 per MMBtu, and $51.24 per Bbl, respectively. 
+While changes in quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products. Our realized prices shown in the table above do not include the impact of cash settlements from derivative contracts, which is consistent with all prior periods reported. 
+Derivative Activity 
+We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives. The level of our production covered by derivatives is driven by the amount of debt on our balance sheet and the level of capital commitments and long-term obligations we have in place. With the derivative contracts we have in place, we believe we have established a base cash flow stream for our future operations and partially reduced our exposure to volatility in commodity prices. Our use of collars for a portion of the derivatives allows us to participate in some of the upward movements in oil, gas, and NGL prices while also setting a price floor for a portion of our production. Please see Note 10 – Derivative Financial Instruments of Part II, Item 8 of this report for additional information regarding our oil, gas, and NGL 
+56 
+Table of Contents 
+derivatives, and see the caption, Summary of Oil, Gas, and NGL Derivative Contracts in Place, later in this section. 
+As of January 1, 2011, we elected to de-designate all commodity derivative contracts previously designated as cash flow hedges on December 31, 2010, and to discontinue hedge accounting prospectively. Accordingly, beginning January 1, 2011, changes in fair value of these contracts result in non-cash gains and losses that are recognized immediately in earnings. Realized cash settlements from our oil, gas, and NGL derivative contracts for the year ended December 31, 2011, resulted in a loss of $75.4 million, a gain of $48.0 million, and a loss $18.9 million, respectively. 
+The following table shows a reconciliation from our realized prices to our adjusted prices for the commodities indicated, including the effects of derivative cash settlements for 2011, 2010 and 2009: 
+For the Year Ended 
+December 31, 
+2011 
+2010 
+2009 
+Crude Oil (per Bbl): 
+Realized price 
+$ 
+88.23 
+$ 
+72.65 
+$ 
+54.40 
+Plus (less) the effects of derivative cash settlements 
+(9.34 
+) 
+(5.80 
+) 
+2.34 
+Adjusted price, including the effects of derivative cash settlements 
+$ 
+78.89 
+$ 
+66.85 
+$ 
+56.74 
+Natural Gas (per Mcf): 
+Realized price 
+$ 
+4.32 
+$ 
+5.21 
+$ 
+3.82 
+Plus the effects of derivative cash settlements 
+0.48 
+0.84 
+1.77 
+Adjusted price, including the effects of derivative cash settlements 
+$ 
+4.80 
+$ 
+6.05 
+$ 
+5.59 
+Natural Gas Liquids (per Bbl): 
+Realized price 
+$ 
+53.32 
+$ 
+— 
+$ 
+— 
+(Less) the effects of derivative cash settlements 
+(5.42 
+) 
+— 
+— 
+Adjusted price, including the effects of derivative cash settlements 
+$ 
+47.90 
+$ 
+— 
+$ 
+— 
+Note: Prior year NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of the volumes in prior periods. Please refer to additional discussion above under the caption Oil, Gas, and NGL Prices above. 
+The Dodd-Frank Act included provisions that require over-the-counter derivative transactions to be executed through an exchange or centrally cleared. The Dodd-Frank Act requires the CFTC, the SEC, and other regulators to establish rules and regulations to implement the new legislation by July 16, 2012. The CFTC has proposed new rules governing margin requirements for uncleared swaps entered into by non-bank swap entities, and U.S. banking regulators have proposed new rules regarding margin requirements for uncleared swaps entered into by bank swap entities. The ultimate effect on our business of the proposed new rules and any additional regulations is currently uncertain. Of particular concern to us is whether the provisions of the final rules and regulations will allow us to qualify as a non-financial, commercial end user exempt from the requirements to post margin in connection with commodity price risk management activities. Final rules and regulations on major provisions of the legislation, such as new margin requirements, are to be established through regulatory rulemaking. Although we cannot predict the ultimate outcome of these rulemakings, new rules and regulations in this area may result in increased costs and cash collateral requirements for the types of derivative instruments we use to manage our financial risks related to volatility in oil, gas, and NGL commodity prices. 
+2011 Highlights 
+Operational Activities. We operated eleven to twelve drilling rigs company-wide for most of 2011. We focused our operated drilling activity in 2011 on oil and NGL-rich gas programs and pursued certain other natural 
+57 
+Table of Contents 
+gas projects of strategic importance to us. We also participated in higher levels of non-operated activity in oil and NGL-rich plays. 
+In our Eagle Ford shale program in South Texas, we operated two rigs at the beginning of the year and increased to five drilling rigs by year-end 2011. We focused our drilling in areas with higher BTU gas content and condensate yields. During 2011, we entered into arrangements to secure the pipeline takeaway capacity, drilling, and completion services required to accelerate and maintain our operated program. We continue to explore other arrangements to facilitate the growth of this program. Please refer to Note 6 – Commitments and Contingencies under Part II, Item 8 of this report and Delivery Commitments and Core Operational Areas under Part I, Items 1 and 2 of this report for additional discussion concerning these agreements. On our non-operated Eagle Ford acreage, the operator increased activity on our shared acreage throughout 2011. At year-end, ten drilling rigs were running in our non-operated Eagle Ford shale program this program. We participated with our partners in the construction of necessary infrastructure to support the growth in production associated with these assets during 2011. 
+We operated an average of three drilling rigs in the Williston Basin throughout 2011, all of which were focused on Bakken/Three Forks drilling. Our drilling results in these prospects met or exceeded our expectations. Elsewhere in the Rocky Mountain region, we tested the Niobrara formation in both southeastern and central Wyoming. 
+In our Mid-Continent region, we operated two drilling rigs in our Granite Wash program in western Oklahoma and the Texas Panhandle to test and delineate our acreage in the play. The majority of our acreage position is held by production, and we believe the potential from this emerging program could be significant. 
+In our ArkLaTex region, we had one operated rig in our Haynesville shale program at year-end, with a focus on holding the highest potential acreage through production. 
+Our Permian region operated one rig throughout 2011, splitting its efforts between the testing of Wolfberry down spacing and drilling Mississippian limestone targets as part of our exploration effort. 
+Production Results. The table below provides a regional breakdown of our 2011 production: 
+ArkLaTex 
+Mid-Continent 
+South Texas & Gulf Coast 
+Permian 
+Rocky 
+Mountain 
+Total (1) 
+Production: 
+Oil (MMBbl) 
+0.1 
+0.4 
+2.6 
+1.3 
+3.7 
+8.1 
+Gas (Bcf) 
+29.3 
+28.6 
+34.7 
+3.5 
+4.2 
+100.3 
+NGLs (MMBbl) 
+0.1 
+0.1 
+3.2 
+— 
+— 
+3.5 
+Equivalent (BCFE) 
+30.1 
+31.6 
+69.7 
+11.5 
+26.7 
+169.7 
+Avg. Daily Equivalents 
+(MMCFE/d) 
+82.5 
+86.7 
+191.1 
+31.5 
+73.3 
+465.0 
+Relative percentage 
+18 
+% 
+19 
+% 
+41 
+% 
+6 
+% 
+16 
+% 
+100 
+% 
+(1) Totals may not sum due to rounding. 
+In 2011, our production growth was led by our Eagle Ford shale program. Both our operated and non-operated programs targeting the Eagle Ford shale contributed more production than originally budgeted. Please refer to Comparison of Financial Results and Trends between 2011 and 2010 below for additional discussion on production. 
+Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows: 
+58 
+Table of Contents 
+For the Year Ended 
+December 31, 2011 
+(in millions) 
+Development costs 
+$ 
+1,208.3 
+Facility costs 
+112.4 
+Exploration costs 
+177.4 
+Acquisitions 
+Leasing activity 
+55.2 
+Total, including asset retirement obligation 
+$ 
+1,553.3 
+Our operations are generally funded first using cash flows from operating activities. We also use borrowings under our credit facility. In 2011, we used proceeds from debt offerings and divestitures to help fund our capital investment activities. These sources allowed us to invest $1.5 billion for development and exploration, including facility costs, and $55.2 million for leasehold acquisitions. Total costs incurred during 2011 increased 77 percent from the prior year, reflecting our increased level of drilling activity, particularly in the Eagle Ford shale. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we fund our capital program. 
+Acquisition and Development Agreement. We entered into an Acquisition and Development Agreement that provided for a transfer of a 12.5 percent working interest to Mitsui in certain non-operated oil and gas assets representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick, and Webb Counties, Texas. As consideration for the interests, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs attributable to our remaining interests in these assets until Mitsui has expended an aggregate $680.0 million on our behalf. Based on our forecast of the operator's current drilling plans, we estimate it will take three to four years to fully utilize the $680.0 million that Mitsui is obligated to carry. The agreement also provided for the conveyance of one-half of our ownership in related gathering assets in exchange for reimbursement by Mitsui of 50 percent of the total costs we paid for those assets through the closing date. The effective date of the transfer was March 1, 2011, and the transaction closed on December 2, 2011. Mitsui has reimbursed us for capital expenditures and other costs, net of revenues, that we paid and were attributable to the transferred interests during the period between the effective date and the closing date. We are applying these reimbursed funds to the 10 percent of our drilling and completion costs for the affected acreage not already covered by Mitsui's 90 percent carry. 
+Divestiture Activity. We had the following divestiture activity during 2011: 
+• 
+Eagle Ford Shale Divestiture. In August 2011 , we completed the divestiture of certain operated Eagle Ford shale assets located in our South Texas & Gulf Coast region, comprised of our entire operated acreage position in LaSalle County, Texas, as well as an immaterial adjacent block of our operated acreage in Dimmit County, Texas. Total divestiture proceeds were $230.8 million . The estimated gain on this divestiture was $194.6 million and post-closing adjustments, if any, are expected to be finalized in the first quarter of 2012. 
+• 
+Mid-Continent Divestiture. In June 2011 , we completed the divestiture of certain non-strategic assets located in our Mid-Continent region. Total divestiture proceeds were $35.8 million . The estimated gain on this divestiture was $28.5 million and post-closing adjustments, if any, are expected to be finalized in the first quarter of 2012. 
+• 
+Rocky Mountain Divestiture. In January 2011 , we completed the divestiture of certain non-strategic assets located in our Rocky Mountain region. Total divestiture proceeds were $45.5 million . The final gain on this divestiture was $27.2 million . 
+• 
+Marcellus Divestiture Update . In July 2011 , we entered into agreements with Endeavour International Corporation ("Endeavour") to divest of our Marcellus shale assets and related pipeline 
+59 
+Table of Contents 
+facilities located in Pennsylvania for $80.0 million net to our interest. Subsequently, Endeavour failed to consummate the transaction after giving notice of its intent to terminate the agreement. We have disputed Endeavour's right to take these actions, and are currently pursuing our legal remedies, including specific performance or damages from Endeavour. Due to the uncertainty surrounding the transaction, it was determined that these assets do not continue to meet the specific criteria required for presentation as assets held for sale. As a result, we have reclassified these assets previously classified as held for sale to assets held and used. We measured the assets at the lower of the assets' carrying amount before the assets were classified as held for sale, adjusted for any depreciation and depletion expense that would have been recognized had the assets been continuously classified as held and used, or the assets' fair value at the subsequent date that the assets no longer met the criteria for assets held for sale. As a result of this measurement, we recognized $14.7 million of DD&A expense and a $27.5 million write-down to proved and unproved oil and gas properties. This write-down is included in gain on divestiture activity in the accompanying consolidated statements of operations. 
+Outlook for 2012 
+We enter 2012 with a capital program expected to be in the range of $1.4 billion to $1.5 billion, of which approximately $1.2 billion to $1.3 billion will be focused on drilling and completion activities. Approximately 90 percent of our drilling budget will be spent on our operated projects, with approximately 70 percent of our 2012 drilling and completion capital being deployed in our operated Eagle Ford shale and Bakken/Three Forks programs. 
+In 2012, we plan to invest between $650 million and $700 million of drilling and completion capital in our operated Eagle Ford shale play. We began 2012 operating five rigs on our Eagle Ford shale acreage with plans to operate five to six drilling rigs in the first half of the year as we transition a larger proportion of our program to pad drilling. Once we have transitioned to pad drilling, we anticipate reducing activity by one rig in the second half to exit the year with five operated rigs, three of which will be focused on pad drilling. During 2011, we entered into an additional services agreement for gas takeaway capacity in 2013 and beyond in our operated Eagle Ford program, thereby increasing our number of providers to three and mitigating some risks of marketing our gas. During 2012, we plan to continue testing down spacing opportunities to determine the ultimate development spacing of our Galvan Ranch, Briscoe Ranch, and Apache Ranch areas. Along with down spacing tests, we will continue to refine our development program and well designs to optimize well performance and capital efficiency. 
+In our non-operated Eagle Ford shale program, the operator is currently operating ten drilling rigs and based on the operator's stated plans, our expectation is that the number of rigs will remain constant throughout the year. Mitsui will carry the majority of our non-operated drilling activity through 2012 and, as such, we expect to deploy minimal capital related to drilling in this program. Costs associated with items such as infrastructure are not carried by Mitsui, and we would be responsible for our proportionate share of the costs. 
+We plan to deploy between $160 million and $185 million of our capital budget in our operated Bakken/Three Forks program in the Williston Basin in 2012. We currently are operating three drilling rigs in this program and plan to add a fourth rig in the first half of 2012. Our plan with these rigs is to hold our Raven and Gooseneck prospects through production, and to begin infill drilling in our Bear Den prospect which is already held by production. 
+We also have activity planned in our Permian region, and Granite Wash, Niobrara, and Haynesville shale programs in 2012. Between $60 million and $70 million of our capital budget in 2012 is dedicated to our operated Granite Wash program, where we anticipate operating a three rig program throughout the year targeting NGL-rich washes. The remainder of our other operated program will be split between assets in the Permian basin and targets in the DJ basin and Powder River Basin. In the Haynesville shale, we have reduced the number of wells we plan to drill in 2012 in light of current natural gas prices. We now expect to invest approximately $35 million to $40 million during the year, after which time we will cease drilling activity in this area. 
+60 
+Table of Contents 
+Please refer to Overview of Liquidity and Capital Resources for additional discussion regarding how we intend to fund our 2012 capital program. 
+Financial Results of Operations and Additional Comparative Data 
+The table below provides information regarding selected production and financial information for the quarter ended December 31, 2011, and the immediately preceding three quarters. Additional details of per MCFE costs are contained later in this section. 
+For the Three Months Ended 
+December 31, 
+September 30, 
+June 30, 
+March 31, 
+2011 
+2011 
+2011 
+2011 
+(in millions, except for production data) 
+Production (BCFE) 
+51.3 
+42.5 
+39.8 
+36.1 
+Oil, gas, and NGL production revenue 
+$ 
+397.0 
+$ 
+325.2 
+$ 
+333.9 
+$ 
+276.3 
+Realized hedge loss 
+$ 
+(6.2 
+) 
+$ 
+(6.8 
+) 
+$ 
+(6.3 
+) 
+$ 
+(1.4 
+) 
+Gain (loss) on divestiture activity 
+$ 
+(25.0 
+) 
+$ 
+190.7 
+$ 
+30.0 
+$ 
+24.9 
+Lease operating expense 
+$ 
+43.5 
+$ 
+40.0 
+$ 
+33.2 
+$ 
+33.1 
+Transportation costs 
+$ 
+30.7 
+$ 
+23.9 
+$ 
+16.9 
+$ 
+15.0 
+Production taxes 
+$ 
+19.0 
+$ 
+13.8 
+$ 
+3.3 
+$ 
+17.8 
+DD&A 
+$ 
+167.3 
+$ 
+123.1 
+$ 
+115.4 
+$ 
+105.4 
+Exploration 
+$ 
+20.0 
+$ 
+11.3 
+$ 
+9.6 
+$ 
+12.7 
+Impairment of proved properties 
+$ 
+170.5 
+$ 
+48.5 
+$ 
+— 
+$ 
+— 
+General and administrative 
+$ 
+35.6 
+$ 
+29.8 
+$ 
+27.3 
+$ 
+25.9 
+Change in Net Profits Plan liability 
+$ 
+(0.8 
+) 
+$ 
+(24.9 
+) 
+$ 
+(14.0 
+) 
+$ 
+14.2 
+Unrealized and realized derivative (gain) loss 
+$ 
+46.8 
+$ 
+(128.4 
+) 
+$ 
+(43.9 
+) 
+$ 
+88.4 
+Net income (loss) 
+$ 
+(120.7 
+) 
+$ 
+230.1 
+$ 
+124.5 
+$ 
+(18.5 
+) 
+_____________________________________ 
+Note: Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head. Beginning in the first quarter of 2011, we changed our reporting for natural gas to show natural gas and NGL production volumes, revenues, and pricing consistent with title transfer for each product. Please refer to additional discussion above under the caption Oil, Gas, and NGL Prices . 
+Selected Performance Metrics: 
+For the Three Months Ended 
+December 31, 
+September 30, 
+June 30, 
+March 31, 
+2011 
+2011 
+2011 
+2011 
+Average net daily production equivalent (MMCFE per day) 
+557.9 
+462.1 
+436.9 
+401.4 
+Lease operating expense (per MCFE) 
+$ 
+(0.85 
+) 
+$ 
+(0.94 
+) 
+$ 
+(0.84 
+) 
+$ 
+(0.92 
+) 
+Transportation costs (per MCFE) 
+$ 
+(0.60 
+) 
+$ 
+(0.56 
+) 
+$ 
+(0.42 
+) 
+$ 
+(0.41 
+) 
+Production taxes as a percent of oil, gas, and NGL production revenue 
+4.8 
+% 
+4.3 
+% 
+1.0 
+% 
+6.4 
+% 
+Depletion, depreciation and amortization and asset retirement obligation liability accretion (per MCFE) 
+$ 
+(3.26 
+) 
+$ 
+(2.89 
+) 
+$ 
+(2.90 
+) 
+$ 
+(2.92 
+) 
+General and administrative (per MCFE) 
+$ 
+(0.69 
+) 
+$ 
+(0.70 
+) 
+$ 
+(0.69 
+) 
+$ 
+(0.72 
+) 
+61 
+Table of Contents 
+A year-to-year overview of selected production and financial information, including trends: 
+As of and for the Years Ended December 31, 
+Amount Change Between 
+Percent Change Between 
+2011 
+2010 
+2009 
+2011/2010 
+2010/2009 
+2011/2010 
+2010/2009 
+Net production volumes 
+Oil (MMBbl) 
+8.1 
+6.4 
+6.3 
+1.7 
+0.1 
+27 
+% 
+— 
+% 
+Natural gas (Bcf) 
+100.3 
+71.9 
+71.1 
+28.5 
+0.8 
+40 
+% 
+1 
+% 
+NGLs (MMBbl) 
+3.5 
+— 
+— 
+3.5 
+— 
+N/A 
+N/A 
+BCFE 
+169.7 
+110.0 
+109.1 
+59.7 
+0.9 
+54 
+% 
+1 
+% 
+Average net daily production 
+Oil (MBbl per day) 
+22.1 
+17.4 
+17.3 
+4.7 
+0.1 
+27 
+% 
+— 
+% 
+Natural gas (MMcf per day) 
+274.8 
+196.9 
+194.8 
+78.0 
+2.1 
+40 
+% 
+1 
+% 
+NGLs (MBbl per day) 
+9.6 
+— 
+— 
+9.6 
+0.0 
+N/A 
+N/A 
+Equivalent (MMCFE per day) 
+465.0 
+301.4 
+298.8 
+163.6 
+2.6 
+54 
+% 
+1 
+% 
+Oil, gas, & NGL production revenues (in millions) 
+Oil production revenue 
+$ 
+712.8 
+$ 
+461.9 
+$ 
+344.3 
+$ 
+250.9 
+$ 
+117.6 
+54 
+% 
+34 
+% 
+Gas production revenue 
+433.4 
+374.4 
+271.7 
+59.0 
+102.7 
+16 
+% 
+38 
+% 
+NGL production revenue 
+186.2 
+— 
+— 
+186.2 
+— 
+N/A 
+N/A 
+Total 
+$ 
+1,332.4 
+$ 
+836.3 
+$ 
+616.0 
+$ 
+496.1 
+$ 
+220.3 
+59 
+% 
+36 
+% 
+Oil, gas, & NGL production expense (in millions) 
+Lease operating expenses 
+$ 
+149.8 
+$ 
+121.5 
+$ 
+145.5 
+$ 
+28.3 
+$ 
+(24.0 
+) 
+23 
+% 
+(16 
+)% 
+Transportation costs 
+86.4 
+21.2 
+20.6 
+65.2 
+0.6 
+308 
+% 
+3 
+% 
+Production taxes 
+53.9 
+52.4 
+40.7 
+1.5 
+11.7 
+3 
+% 
+29 
+% 
+Total 
+$ 
+290.1 
+$ 
+195.1 
+$ 
+206.8 
+$ 
+95.0 
+$ 
+(11.7 
+) 
+49 
+% 
+(6 
+)% 
+Realized price 
+Oil (per Bbl) 
+$ 
+88.23 
+$ 
+72.65 
+$ 
+54.40 
+$ 
+15.58 
+$ 
+18.25 
+21 
+% 
+34 
+% 
+Natural gas (per Mcf) 
+$ 
+4.32 
+$ 
+5.21 
+$ 
+3.82 
+$ 
+(0.89 
+) 
+$ 
+1.39 
+(17 
+)% 
+36 
+% 
+NGLs (per Bbl) 
+$ 
+53.32 
+$ 
+— 
+$ 
+— 
+$ 
+53.32 
+$ 
+— 
+N/A 
+N/A 
+Per MCFE data 
+Realized price 
+$ 
+7.85 
+$ 
+7.60 
+$ 
+5.65 
+$ 
+0.25 
+$ 
+1.95 
+3 
+% 
+35 
+% 
+Lease operating expense 
+(0.88 
+) 
+(1.10 
+) 
+(1.33 
+) 
+0.22 
+0.23 
+(20 
+)% 
+(17 
+)% 
+Transportation costs 
+(0.51 
+) 
+(0.19 
+) 
+(0.19 
+) 
+(0.32 
+) 
+— 
+168 
+% 
+— 
+% 
+Production taxes 
+(0.32 
+) 
+(0.48 
+) 
+(0.37 
+) 
+0.16 
+(0.11 
+) 
+(33 
+)% 
+30 
+% 
+General and administrative 
+(0.70 
+) 
+(0.97 
+) 
+(0.70 
+) 
+0.27 
+(0.27 
+) 
+(28 
+)% 
+39 
+% 
+Operating profit, before the effects of derivative cash settlements 
+$ 
+5.44 
+$ 
+4.86 
+$ 
+3.06 
+$ 
+0.58 
+$ 
+1.80 
+12 
+% 
+59 
+% 
+Derivative cash settlements 
+(0.27 
+) 
+0.22 
+1.29 
+(0.49 
+) 
+(1.07 
+) 
+(223 
+)% 
+(83 
+)% 
+Operating profit, including the effects of derivative cash settlements 
+$ 
+5.17 
+$ 
+5.08 
+$ 
+4.35 
+$ 
+0.09 
+$ 
+0.73 
+2 
+% 
+17 
+% 
+Depletion, depreciation and amortization and asset retirement obligation liability accretion 
+$ 
+(3.01 
+) 
+$ 
+(3.06 
+) 
+$ 
+(2.79 
+) 
+$ 
+0.05 
+$ 
+(0.27 
+) 
+(2 
+)% 
+10 
+% 
+Note: Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head. Beginning in the first quarter of 2011, we changed our reporting for natural gas volumes to separately show natural gas and NGL production volumes, revenues, and pricing consistent with title transfer for each product. Please refer to additional 
+62 
+Table of Contents 
+discussion above under the caption Oil, Gas, and NGL Prices . 
+We present per MCFE information because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe require analysis. Average daily production for the year ended December 31, 2011, increased 54 percent compared to the same period in 2010, driven mainly by the development of our Eagle Ford shale program. 
+Changes in production volumes, revenues, and costs reflect the cyclical and highly volatile nature of our industry. Our realized price for the year ended December 31, 2011, increased three percent from the same period in 2010 due to a higher realized price received for oil. Please refer to our discussion above under Oil, Gas, and NGL prices for information regarding how we have changed our reporting for natural gas volumes to show post processing production volumes of natural gas and NGLs for assets where our sales contracts permit us to do so. 
+Our LOE on a per MCFE basis for the year ended December 31, 2011, decreased 20 percent compared to the same period in 2010. The divestiture of non-strategic properties with meaningfully higher per unit operating costs within our Rocky Mountain and Mid-Continent regions in 2011 and Permian region in late 2010 is the driver of the decline in LOE from 2010. In addition, our LOE declined on a per MCFE basis due to higher production volumes. We believe the current high level of industry activity, particularly in plays with oil and rich-gas, has the potential to increase lease operating costs in 2012. 
+Production taxes on a per MCFE basis for the year ended December 31, 2011, decreased 33 percent compared to the same period in 2010. We generally expect production taxes to trend with oil, gas, and NGL revenues. We received notification in the second quarter of 2011 that wells within our Eagle Ford and Haynesville shale plays qualified for a severance tax incentive program in Texas. As a result, a sizable incentive tax rebate was recorded and our severance tax accruals were adjusted downward. We expect that substantially all future operated wells to be drilled in these areas will qualify for enacted reduced tax rates. 
+Transportation costs on a per MCFE basis for the year ended December 31, 2011, increased 168 percent compared to the same period in 2010. This is a result of increased production in our Eagle Ford shale program, where transportation arrangements have resulted in higher per unit transportation costs due to the lack of existing infrastructure in this emerging play. We anticipate transportation costs will continue to increase on a per MCFE basis as the Eagle Ford shale becomes a larger portion of our production. 
+Our general and administrative expense on a per MCFE basis for the year ended December 31, 2011, decreased 28 percent compared to the same period in 2010, because production increased at a faster rate than our general and administrative expense. A portion of our general and administrative expense is linked to our profitability and cash flow, which are driven in large part by the realized commodity prices we receive for our production. The Net Profits Plan and a portion of our short-term incentive compensation are tied to net revenues and therefore are subject to variability. 
+Our operating profit, including the effects of derivative cash settlements, for the year ended December 31, 2011, increased two percent , on a per MCFE basis, compared to the same period in 2010. 
+Our depletion, depreciation, and amortization, including asset retirement obligation accretion expense, for the year ended December 31, 2011, decreased two percent , on a per MCFE basis, compared to the same period in 2010. Overall the property balances between 2011 and 2010 remained relatively constant while the reserve base and production increased, causing the per unit depletion, depreciation and amortization rate ("DD&A rate") to decrease. Our DD&A rate can also fluctuate as a result of impairments, divestitures, and changes in the mix of our production and the underlying proved reserve volumes. Additionally, the accounting treatment for assets that are classified as assets held for sale can impact the DD&A rate since properties held for sale are not depleted. 
+Please refer to Comparison of Financial Results and Trends between 2011 and 2010 for additional discussion on oil, gas, and NGL production expense, DD&A, and general and administrative expense. 
+63 
+Table of Contents 
+Financial information (in millions, except shares and per share amounts): 
+As of and for the Years Ended December 31, 
+Amount Change Between 
+Percent Change Between 
+2011 
+2010 
+2009 
+2011/ 2010 
+2010/ 2009 
+2011/ 2010 
+2010/ 2009 
+Working deficit 
+$ 
+(42.6 
+) 
+$ 
+(227.4 
+) 
+$ 
+(87.6 
+) 
+$ 
+184.8 
+$ 
+(139.8 
+) 
+(81 
+)% 
+160 
+% 
+Long-term debt 
+$ 
+985.1 
+$ 
+323.7 
+$ 
+454.9 
+$ 
+661.4 
+$ 
+(131.2 
+) 
+204 
+% 
+(29 
+)% 
+Stockholders’ equity 
+$ 
+1,462.9 
+$ 
+1,218.5 
+$ 
+973.6 
+$ 
+244.4 
+$ 
+244.9 
+20 
+% 
+25 
+% 
+Net income (loss) 
+$ 
+215.4 
+$ 
+196.8 
+$ 
+(99.4 
+) 
+$ 
+18.6 
+$ 
+296.2 
+9 
+% 
+(298 
+)% 
+Basic net income (loss) per common share 
+$ 
+3.38 
+$ 
+3.13 
+$ 
+(1.59 
+) 
+$ 
+0.25 
+$ 
+4.72 
+8 
+% 
+(297 
+)% 
+Diluted net income (loss) per common share 
+$ 
+3.19 
+$ 
+3.04 
+$ 
+(1.59 
+) 
+$ 
+0.15 
+$ 
+4.63 
+5 
+% 
+(291 
+)% 
+Basic weighted-average common shares outstanding (in thousands) 
+63,755 
+62,969 
+62,457 
+786 
+512 
+1 
+% 
+1 
+% 
+Diluted weighted-average common shares outstanding (in thousands) 
+67,564 
+64,689 
+62,457 
+2,875 
+2,232 
+4 
+% 
+4 
+% 
+Basic weighted-average common shares outstanding used in our December 31, 2011, 2010, and 2009, basic net income (loss) per common share calculations reflect increases in outstanding shares related to stock option exercises and vesting of RSUs. Our December 31, 2011, basic net income (loss) per common share calculation also includes common stock issued upon the settlement of PSUs. Diluted weighted-average common shares outstanding used in our December 31, 2011, and 2010, diluted net income per common share calculations include nonvested RSUs, contingent PSUs, and in-the-money stock options. Our December 31, 2011, diluted net income per common share calculation also includes the impact of our 3.50% Senior Convertible Notes. There were no dilutive shares included in our year-end 2009 diluted net income (loss) per common share calculation, as we recognized a net loss for the period. 
+In 2011, our average stock price exceeded the conversion price of $54.42 of our 3.50% Senior Convertible Notes, thus making them potentially dilutive for the first time. As of the filing date our stock price is trading above the $54.42 conversion price, therefore we expect our 3.50% Senior Convertible Notes to have a dilutive impact on our first quarter 2012 diluted net income per common share calculation. Please refer to Note 1 - Summary of Significant Accounting Policies and Note 7 - Compensation Plans in Part II, Item 8 of this report for detailed components of our net income (loss) per common share calculation. 
+Comparison of Financial Results and Trends between 2011 and 2010 
+Oil, gas, and NGL production revenue. Average daily production for the year ended December 31, 2011, increased 54 percent to 465.0 MMCFE, compared with 301.4 MMCFE for the same period in 2010. Please refer to the discussion above under Oil, Gas, and NGL Prices regarding how we have changed our reporting for natural gas and NGL volumes. The following table presents the regional changes in our production and oil, gas, and NGL revenues and costs between the two years: 
+64 
+Table of Contents 
+Average Net Daily Production Added (Lost) 
+Oil, Gas & NGL Revenue Added (Lost) 
+Production Costs Increase (Decrease) 
+(MMCFE/d) 
+(in millions) 
+(in millions) 
+ArkLaTex 
+43.2 
+$ 
+57.6 
+$ 
+5.2 
+Mid-Continent 
+(4.8 
+) 
+5.7 
+(1.1 
+) 
+South Texas & Gulf Coast 
+129.0 
+348.9 
+79.0 
+Permian 
+(8.7 
+) 
+(12.2 
+) 
+(0.3 
+) 
+Rocky Mountain 
+4.9 
+96.1 
+12.2 
+Total 
+163.6 
+$ 
+496.1 
+$ 
+95.0 
+The largest regional production increase occurred in the South Texas & Gulf Coast region as a result of production from drilling activity in our Eagle Ford shale program. Activity in our Eagle Ford shale program continues to increase, and we expect production from this region to increase for the next several years. We also saw an increase in production in our ArkLaTex region, as a result of strong production performance from wells drilled in our Haynesville shale program in late 2010 and early 2011. 
+The following table summarizes the realized prices we received in 2011 and 2010, before the effects of derivative cash settlements: 
+For the Years Ended 
+December 31, 
+2011 
+2010 
+Realized oil price ($/Bbl) 
+$ 
+88.23 
+$ 
+72.65 
+Realized gas price ($/Mcf) 
+$ 
+4.32 
+$ 
+5.21 
+Realized NGL price ($/Bbl) 
+$ 
+53.32 
+$ 
+— 
+Realized equivalent price ($/MCFE) 
+$ 
+7.85 
+$ 
+7.60 
+Note: Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head. Beginning in the first quarter of 2011, we changed our reporting for natural gas volumes to separately show natural gas and NGL production volumes, revenues, and pricing consistent with title transfer for each product. Please refer to additional discussion above under the caption Oil, Gas, and NGL Prices . 
+The three percent increase in realized equivalent price per MCFE coupled with a 54 percent increase in production volumes between periods resulted in a meaningful increase in revenue. We expect our realized price to trend with commodity prices. At current levels of anticipated activity, we expect production volumes to increase annually for the next several years. 
+Realized hedge (loss) gain. We recorded a net realized hedge loss of $20.7 million for the year ended December 31, 2011, compared with a net realized hedge gain of $23.5 million for the same period in 2010. The realized net loss in 2011 is comprised of realized cash settlements on commodity derivative contracts that were previously recorded in AOCL, whereas the realized net gain in 2010 is comprised of realized cash settlements on all commodity derivative contracts. Our realized oil, gas, and NGL hedge gains and losses are a function of commodity prices at the time of settlement and the price at the time the derivative transaction was entered into. 
+Gain on divestiture activity. We recorded a gain on divestiture activity of $220.7 million , which is net of the $27.5 million write-down related to our Marcellus assets, for the year ended December 31, 2011, compared with $155.3 million for the comparable period of 2010. The 2011 gain relates to the divestitures of oil and gas properties located in our South Texas & Gulf Coast, Rocky Mountain, and Mid-Continent regions. The 2010 gain was mainly related to the divestitures of non-strategic oil and gas properties located in our Rocky Mountain and Permian regions. We will continue to evaluate our portfolio to determine whether there are non-strategic properties we could divest. Please refer to Divestiture Activity under 2011 Highlights for additional discussion. 
+65 
+Table of Contents 
+Marketed gas system revenue and expense. Marketed gas system revenue was $69.9 million for the year ended December 31, 2011, compared with $70.1 million for the year ended December 31, 2010. Concurrent with the decrease in marketed gas system revenue, marketed gas system expense decreased to $64.2 million for the year ended December 31, 2011, from $66.7 million for the comparable period of 2010. We expect that marketed gas system revenue and expense will continue to trend with increases and decreases in production and our net realized price for natural gas. 
+Oil, gas, and NGL production expense. Total production costs increased $95.0 million or 49 percent, to $290.1 million for the year ended December 31, 2011, compared with $195.1 million in 2010. Total oil, gas, and NGL production costs per MCFE decreased $0.06 to $1.71 for the year ended December 31, 2011, compared with $1.77 in 2010. This decrease is comprised of the following: 
+• 
+A $0.23 decrease in recurring LOE on a per MCFE basis reflects the sale of non-strategic properties in the Rocky Mountain and Mid-Continent regions in 2011 and the Permian region in late 2010 with higher per unit LOE costs that resulted in lower LOE on a per unit basis year over year. We expect that the various resources required to service our industry, particularly those located in basins with liquids-rich projects, will become more sought after and harder to secure as a result of an increase in activity targeting oil and NGL plays. Accordingly, we expect to see upward pressure on recurring LOE in 2012. 
+• 
+A $0.16 decrease in production taxes on a per MCFE basis is due to severance tax incentives in Texas that benefit our assets in the South Texas & Gulf Coast and Mid-Continent regions. Please refer to our production tax discussion under the caption A year-to-year overview of selected production and financial information, including trends for additional information. 
+• 
+A $0.01 increase in workover LOE on a per MCFE basis related primarily to increased workover activity in our South Texas & Gulf Coast region. 
+• 
+A $0.32 increase in transportation costs on a per MCFE basis is primarily the result of increased production in our Eagle Ford shale program, which has higher per unit transportation costs than our Company average. Please refer to our caption A year-to-year overview of selected production and financial information, including trends for additional information. 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A increased 52 percent to $511.1 million in 2011 compared with $336.1 million in 2010. DD&A expense per MCFE decreased two percent to $3.01 in 2011 compared to $3.06 in 2010. Please refer to the discussion under the caption A year-to -year overview of selected production and financial information, including trends for additional information. 
+Exploration. The components of exploration expense are summarized as follows: 
+Years Ended December 31, 
+2011 
+2010 
+Summary of Exploration Expense 
+(in millions) 
+Geological and geophysical expenses 
+$ 
+7.3 
+$ 
+21.5 
+Exploratory dry hole 
+0.3 
+0.3 
+Overhead and other expenses 
+45.9 
+42.1 
+Total 
+$ 
+53.5 
+$ 
+63.9 
+Exploration expense decreased 16 percent to $53.5 million in 2011 compared with $63.9 million for the same period in 2010. The majority of the change in exploration expense between 2011 and 2010 is due to a decreased amount spent on seismic as our current plays become more established. We continue to test our current resource plays and expect to maintain a modest exploratory program in future periods. Any exploratory well incapable of producing oil, gas, or NGLs in commercial quantities is deemed an exploratory dry hole, and impacts the amount of exploration expense we record. The amount of dry hole expense included in exploration expense 
+66 
+Table of Contents 
+during 2011 and 2010 was minimal. The decreased geological and geophysical costs were partially offset by an increase in exploration costs related to equity incentive compensation expense as discussed under General and administrative below. 
+Impairment of proved properties. We recorded a $219.0 million impairment of proved oil and gas properties in 2011 compared to $6.1 million in 2010. The impairment in 2011 was related to assets located in our ArkLaTex region, which were impacted by significantly lower natural gas prices in the second half of 2011. Proved property impairments are more likely to occur in periods of low commodity prices. 
+Abandonment and impairment of unproved properties. We recorded abandonment and impairment of unproved properties expense of $7.4 million for the year ended December 31, 2011, primarily associated with lease expirations in our ArkLaTex region. We recorded $2.0 million of abandonment and impairment of unproved properties expense for the comparable period in 2010, primarily associated with lease expirations in our Rocky Mountain and ArkLaTex regions. We expect abandonments and impairments of unproved properties to be more likely to occur in periods of low commodity prices, because low prices negatively impact operating cash flows available for exploration and development and also negatively impact anticipated economic performance. 
+General and administrative. General and administrative expense increased 11 percent, to $118.5 million for the year ended December 31, 2011, compared with $106.7 million for the same period in 2010. G&A decreased $0.27 to $0.70 per MCFE for the year ended December 31, 2011, compared to $0.97 per MCFE for the same period in 2010. 
+The total increase in general and administrative expense for the year ended December 31, 2011, includes $8.9 million relating to increases in base and equity incentive compensation and accruals for cash bonuses, as well as a $4.7 million increase in corporate office expenses. The increase in overall compensation and corporate office expenses is largely the result of an increase in employee headcount between the two periods. G&A expense decreased as a result of a $1.3 million increase in COPAS overhead reimbursements, caused by an increase in our operated well count resulting from our drilling efforts, and a $500,000 decrease in cash payments accrued under the Net Profits Plan. We expect payments made under the Net Profits Plan to trend with commodity prices. 
+Change in Net Profits Plan liability. Generally, this non-cash item is related to the change in the estimated value of the associated liability between the reporting periods. Please refer to Note 11 - Fair Value Measurements in Part II, Item 8 of this report for the impact the direct payment made to cash out several pools had on our change in Net Profits Plan liability. For 2011, the change in Net Profits plan liability, a non-cash item, was a $25.5 million benefit compared to a $34.4 million benefit in 2010. This non-cash charge or benefit is directly related to the change in the estimated value of the associated liability between the reporting periods. We broadly expect the change in our liability to continue to trend with changes in strip prices. The change in our liability is subject to estimation and may change dramatically from period to period based on assumptions used for production rates, reserve quantities, commodity pricing, discount rates, tax rates, and production costs. Payments made to participants as a result of divestitures will also impact our liability. 
+Unrealized and realized derivative (gain) loss. We recognized an unrealized and realized derivative gain of $37.1 million in 2011 compared to a loss of $8.9 million for the same period in 2010. The 2011 amount includes gains resulting from unrealized changes in fair value on commodity derivative contracts of $62.8 million and realized cash settlement losses on derivatives for which unrealized changes in fair value were not previously recorded in other comprehensive loss of $25.7 million . The 2010 balance is comprised solely of the ineffective portion of derivatives designated as cash flow hedges. Please refer to Note 10 - Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion. 
+Other operating expense. Other expense was $17.6 million in 2011 compared with $3.0 million in 2010. The increase is a result of commission and legal costs associated with our Acquisition and Development Agreement with Mitsui, as well as legal costs related to the arbitration proceedings against Anadarko E&P Company, LP during the second half of 2011. Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement, in Part II, Item 8 of this report for additional discussion on our Acquisition and Development 
+67 
+Table of Contents 
+Agreement. 
+Income tax (expense) benefit . Income tax expense totaled $123.6 million for 2011 compared with $118.1 million for 2010, resulting in effective tax rates of 36.5 percent and 37.5 percent , respectively. The effective rate change from 2010 primarily reflects changes in the mix of the highest marginal state tax rates, a multi-year research and experimentation credit claim, an adjustment for anticipated utilization of charitable contributions carryovers, and differing effects of other permanent differences including percentage depletion. Our current income tax benefit in 2011 is $204,000 compared with current income tax expense of $3.5 million in 2010. These amounts were three percent of the total income tax expense or benefit for 2010 and were not material for 2011. 
+At the end of 2010, federal legislation was passed making qualified property placed in service after September 8, 2010, and before January 1, 2012, eligible for 100 percent bonus depreciation. This same law made qualified property placed in service between January 1, 2010, and December 31, 2012, eligible for the 50 percent bonus depreciation election. We continue to be in an accelerated development mode on several unconventional projects. As a result, our election to utilize bonus depreciation for 2009, 2010, and 2011 is having the anticipated impact of reducing alternative minimum tax thereby, resulting in lower amounts of current income tax benefit/expense reported above. In 2011 we believe we will generate a net operating loss for income tax purposes and will carry a portion of that loss back to 2010 to recover most of the tax paid in that year. The remaining net operating loss is expected to be utilized in future years. We expect that the creation and utilization of net operating losses will limit our future ability to deduct charitable contribution carryovers from prior years so we recorded a valuation allowance related to that item. 
+During 2011, we completed a multi-year research and experimentation credit study. The study enabled us to establish credit claims for prior years and the current year. Tax law allowing the calculation of these credits has not been extended past December 31, 2011 as of the filing of this report. We expect to benefit from utilization of the remaining credits in future years. Please refer to Risk Factors - Risks Related to Our Business for additional discussion. 
+Comparison of Financial Results between 2010 and 2009 
+Oil and gas production revenue. Average daily production for the year ended December 31, 2010, increased one percent to 301.4 MMCFE, compared with 298.8 MMCFE for the same period in 2009. The following table presents the regional changes in our production and oil and gas revenues and costs between the two years. 
+Average Net Daily Production Added (Lost) 
+Oil and Gas Revenue Added 
+Production Costs Increase (Decrease) 
+(MMCFE/d) 
+(in millions) 
+(in millions) 
+ArkLaTex 
+(1.5 
+) 
+$ 
+7.4 
+$ 
+(5.8 
+) 
+Mid-Continent 
+(7.2 
+) 
+23.9 
+4.0 
+South Texas & Gulf Coast 
+35.4 
+131.4 
+20.6 
+Permian 
+(1.3 
+) 
+37.8 
+2.2 
+Rocky Mountain 
+(22.8 
+) 
+19.8 
+(32.7 
+) 
+Total 
+2.6 
+$ 
+220.3 
+$ 
+(11.7 
+) 
+The largest regional production decrease occurred in the Rocky Mountain region as a result of our divestitures of non-strategic oil and gas assets that occurred in the fourth quarter of 2009 and first quarter of 2010. The largest production growth occurred in our South Texas & Gulf Coast region as a result of production from drilling activity in our Eagle Ford shale program. 
+The following table summarizes the average realized prices we received in 2010 and 2009, before the effects of hedging: 
+68 
+Table of Contents 
+For the Years Ended 
+December 31, 
+2010 
+2009 
+Realized oil price ($/Bbl) 
+$ 
+72.65 
+$ 
+54.40 
+Realized gas price ($/Mcf) 
+$ 
+5.21 
+$ 
+3.82 
+Realized equivalent price ($/MCFE) 
+$ 
+7.60 
+$ 
+5.65 
+The 35 percent increase in average realized prices per MCFE coupled with a one percent increase in production volumes between periods resulted in higher oil and gas revenue. 
+Realized hedge (loss) gain. We recorded a net realized hedge gain of $23.5 million for the year ended December 31, 2010, compared with a net realized hedge gain of $140.6 million for the same period in 2009. These gains were mainly related to favorable settlements on natural gas hedges. The realized net gains in 2010 and 2009 are comprised of realized cash settlements on all commodity derivative contracts. 
+Marketed gas system revenue and expense. Marketed gas system revenue increased $11.6 million to $70.1 million for the year ended December 31, 2010, compared with $58.5 million for the year ended December 31, 2009. Concurrent with the increase in marketed gas system revenue, marketed gas system expense increased $9.1 million to $66.7 million for the year ended December 31, 2010, compared with $57.6 million for the comparable period of 2009. 
+Gain on divestiture activity. We recorded a gain on divestiture activity of $155.3 million for the year ended December 31, 2010, compared with $11.4 million for the comparable period of 2009. The 2010 gain relates to the divestitures of non-strategic oil and gas properties located in our Rocky Mountain and Permian regions. The 2009 gain was mainly related to the Hanging Woman Basin property divestiture that closed in late 2009. 
+Oil and gas production expense. Total production costs decreased $11.7 million or six percent to $195.1 million for the year ended December 31, 2010, compared with $206.8 million in 2009. Total oil and gas production costs per MCFE decreased $0.12 to $1.77 for the year ended December 31, 2010, compared with $1.89 in 2009. This decrease is comprised of the following: 
+• 
+A $0.23 decrease in recurring LOE on a per MCFE basis reflects the sale of non-strategic properties in late 2009 and early 2010 with higher per unit LOE costs, which resulted in lower LOE on a per unit basis year over year. 
+• 
+A $0.11 increase in production taxes on a per MCFE basis is due to the increase in realized prices between periods. 
+• 
+Workover LOE and transportation costs on a per MCFE basis remained flat year over year. 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A increased $31.9 million, or ten percent, to $336.1 million in 2010 compared with $304.2 million in 2009. DD&A expense per MCFE increased ten percent to $3.06 in 2010 compared to $2.79 in 2009. The increase was impacted by our divestiture of lower cost basis properties in 2010, and higher DD&A rates in our Eagle Ford and Haynesville programs. 
+Exploration. The components of exploration expense are summarized as follows: 
+69 
+Table of Contents 
+Years Ended December 31, 
+2010 
+2009 
+Summary of Exploration Expense 
+(in millions) 
+Geological and geophysical expenses 
+$ 
+21.5 
+$ 
+20.2 
+Exploratory dry hole 
+0.3 
+7.8 
+Overhead and other expenses 
+42.1 
+34.2 
+Total 
+$ 
+63.9 
+$ 
+62.2 
+Exploration expense increased $1.7 million, or three percent, to $63.9 million in 2010 compared with $62.2 million for the same period in 2009. The overall increase in expense primarily relates to an increase in exploration overhead, which is partially offset by a decrease in exploratory dry hole expense. In 2009, we had $7.8 million of exploratory dry hole expense related to properties in our ArkLaTex region compared with minimal exploratory dry hole expense in 2010. Other increases in exploration costs related to an increase in equity incentive compensation expense are discussed under General and administrative below. 
+Impairment of proved properties. We recorded a $6.1 million impairment of proved oil and gas properties in 2010 compared to $174.8 million in 2009. A significant decrease in commodity prices, including differentials, during the first quarter of 2009 caused the majority of the non-cash impairment in that year. The largest portion of the impairment in 2009 was $97.3 million related to assets located in the Mid-Continent region which were impacted at the end of the first quarter by low natural gas prices and wider than normal differentials. 
+Abandonment and impairment of unproved properties. During 2010, we abandoned or impaired $2.0 million of unproved properties compared with $45.4 million for 2009. The largest specific components of the 2009 impairment and abandonment related to our Floyd shale acreage located in Mississippi and certain acreage in Oklahoma. Additionally in 2009, we incurred write-offs related to acreage that we did not maintain or related to acreage that we did not believe will be prospective. 
+Impairment of materials inventory. There were no impairments of materials inventory recorded in 2010. We recorded a $14.2 million impairment of materials inventory for the year ended December 31, 2009. The 2009 inventory impairment was caused by a decrease in the value of tubular goods and other raw materials. 
+General and administrative. General and administrative expense increased $30.7 million, or 40 percent, to $106.7 million for the year ended December 31, 2010, compared with $76.0 million for the same period in 2009. G&A increased $0.27 to $0.97 per MCFE for the year ended December 31, 2010, compared to $0.70 per MCFE for the same period in 2009. 
+General and administrative expense increased due to a $21.9 million increase in base compensation, cash bonus, and long-term incentive compensation expense for the year ended December 31, 2010, compared with the same period in 2009. The increase in cash bonus and long-term incentive compensation expense reflects compensation expense associated with the PSAs granted in the third quarter of 2010, as well as the improvement in our performance and the anticipated achievement of various performance criteria, established by the Compensation Committee of our Board of Directors. 
+Additionally, G&A expense increased as a result of a $5.1 million decrease in COPAS overhead reimbursements, caused by a decrease in our operated well count resulting from our recent divestiture efforts, and a $1.4 million increase in cash payments accrued under the Net Profits Plan. 
+Bad debt recovery. We did not record any bad debt expense or recovery of bad debt expense in 2010. In 2008, SemGroup, L.P. and certain of its North American subsidiaries filed for bankruptcy protection. At that time, certain SemGroup L.P. entities were purchasing a portion of our oil production. As a result of the bankruptcy filing, we recorded bad debt expense of $16.6 million as of December 31, 2008. In 2009, we sold a portion of our SemGroup L.P. administrative claim, at which time we recorded a recovery of bad debt expense of $5.2 million. 
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+Table of Contents 
+Change in Net Profits Plan liability. For 2010, this non-cash item was a $34.4 million benefit compared to a $7.1 million benefit for 2009. Payments made or accrued in 2010 as part of allocating the proceeds received from divestitures decreased the estimated liability for the future amounts to be paid to plan participants. 
+Unrealized and realized derivative (gain) loss. We recognized a loss of $8.9 million in 2010 compared to a loss of $20.5 million for 2009. This non-cash item is driven by the change in the value of our derivative position, as well as the portion of that position that is considered ineffective for accounting purposes. 
+Other operating expense. Other expense decreased $10.5 million to $3.0 million in 2010 compared with $13.5 million in 2009. During 2009, we incurred $1.5 million of expense related to the assignment of a drilling rig contract in our Rocky Mountain region and incurred a loss related to hurricanes of $8.3 million. 
+Income tax (expense) benefit. Income tax expense totaled $118.1 million for 2010 compared to a tax benefit of $60.1 million for 2009, resulting in effective tax rates of 37.5 percent and 37.7 percent, respectively. The effective rate change from 2009 primarily reflects changes in the mix of the highest marginal state tax rates, anticipated utilization of state tax net operating losses, and differing effects of other permanent differences, including percentage depletion. Our current income tax expense in 2010 was $3.5 million compared to current income tax benefit of $20.4 million in 2009. These amounts are three percent and 34 percent, respectively, of the total income tax expense or benefit for each period. 
+Qualified property placed in service in 2009 and 2010, up to September 8, 2010, was eligible for 50 percent bonus depreciation as a result of tax laws passed in 2008 and 2010. Qualified property placed in service after September 8, 2010, was eligible for 100 percent bonus depreciation. Because we are currently in an accelerated development mode on several of our unconventional projects we will not receive much of a current benefit resulting solely from this deduction. However, making the respective elections for 2010 accelerates deductions impacting our alternative minimum tax calculations in future years providing us with an anticipated opportunity, given current development expectations, to limit the impact of alternative minimum tax on the calculation of current income tax expense in those years. The amounts of current income tax expense reported above reflect our election to utilize bonus depreciation for both years. The benefit of bonus depreciation in 2010 was limited by alternative minimum tax calculations related to intangible drilling costs. Our 2009 current income tax benefit reflects creation of a net operating loss due in part to bonus depreciation which we carried back to 2005 to obtain a refund. 
+Overview of Liquidity and Capital Resources 
+We believe we have sufficient liquidity and capital resources to execute our business plans for the foreseeable future. 
+Sources of cash 
+Our primary sources of liquidity are the cash flows provided by our operating activities, use of our credit facility, divestitures of properties, and other financing alternatives, including accessing capital markets. From time to time, we may be able to enter into carrying cost funding and sharing arrangements with third parties for particular exploration and/or development programs. All of our sources of liquidity can be impacted by the general condition of the broad economy and by fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and our industry. We have no control over the market prices for oil, gas, or NGLs, although we are able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. The borrowing base on our credit facility could be reduced as a result of lower commodity prices or divestitures of producing properties. Historically, decreases in commodity prices have limited our industry’s access to the capital markets. 
+We also consummated our Acquisition and Development Agreement with Mitsui that funds, or carries, 90 percent of certain for the drilling and completion of Eagle Ford shale wells in our non-operated Eagle Ford shale position until $680.0 million has been expended on our behalf. This carry is expected to be realized over the next three to four years. 
+71 
+Table of Contents 
+In 2012, we expect cash flow from operations and divestiture proceeds will fund the majority of our capital program. Our credit facility, which was undrawn as of year-end, will be used to fund the remaining balance of our capital program. Although we expect our cash flow, expected divestiture proceeds, and available borrowing capacity under our credit facility will be sufficient to fund our current capital program, accessing the capital markets or the use of other financing alternatives are available options. We will continue to evaluate our property base to identify and divest properties we consider non-core to our strategic goals. 
+Current proposals to fund the federal government budget include eliminating or reducing current tax deductions for intangible drilling costs, the domestic production activities deduction, and percentage depletion. Legislation modifying or eliminating these deductions would have the immediate effect of reducing operating cash flows thereby reducing funding available for our exploration and development capital programs and those of our peers in the industry. These funding reductions could have a significant adverse effect on drilling in the United States for a number of years. 
+Credit facility 
+In May 2011, we entered into our Fourth Amended and Restated Credit Agreement for a $2.5 billion senior secured revolving credit facility having a scheduled maturity date of May 27, 2016. This credit facility replaced our prior $1.0 billion senior secured revolving credit facility. The initial borrowing base for the new credit facility was $1.3 billion, which was subsequently increased as part of our normal redetermination process to $1.4 billion in the third quarter of 2011, and reduced by approximately 25 percent of the aggregate principal amount of our 6.50% Senior Notes, to $1.3 billion in the fourth quarter of 2011. Our lenders have agreed to an aggregate commitment amount of $1.0 billion as of December 31, 2012. The borrowing base is redetermined semi-annually by our lenders. We believe that the commitment amount is sufficient to meet our anticipated liquidity and operating needs. Through the filing date of this report, we have experienced no issues drawing upon our credit facility. No individual bank participating in the credit facility represents more than ten percent of the lending commitments under the credit facility. 
+We had no borrowings outstanding under this facility as of December 31, 2011 , and February 16, 2012 . We had two letters of credit outstanding under our credit facility, totaling $608,000 , as of December 31, 2011 , and February 16, 2012 . Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis . As a result, we had $999.4 million of available borrowing capacity under this facility as of December 31, 2011, and February 16, 2012. Our daily weighted-average credit facility debt balances for the years ended December 31, 2011 , and 2010, were $10.7 million and $54.6 million, respectively. Borrowings under our credit facility are secured by mortgages on substantially all of our oil and gas properties. As of December 31, 2011, and the filing date of this report, we were in compliance with all financial and non-financial covenants under our credit facility. Please refer to Note 5 – Long-term Debt in Part II, Item 8 of this report for our borrowing base utilization grid. 
+Senior Notes 
+In the first quarter of 2011, we issued $350.0 million in aggregate principal amount of 6.625% Senior Notes at par. During the fourth quarter of 2011, we issued $350.0 million in aggregate principal amount of 6.50% Senior Notes at par. Please refer to Note 5 – Long-term Debt in Part II, Item 8 of this report for additional discussion. 
+Weighted-average interest rates 
+O ur weighted-average interest rates in the current and prior year include cash interest payments, cash fees paid on the unused portion of the credit facility’s aggregate commitment amount, letter of credit fees, amortization of the convertible notes debt discount, and amortization of deferred financing costs. Our weighted-average interest rates for the years ended December 31, 2011 , 2010, and 2009, were 8.5 percent, 8.3 percent and 5.4 percent, respectively. The increase in our weighted-average interest rate from 2010 is the result of adding higher interest rate debt in 2011, with higher fixed charges, and increased deferred financing costs. Our weighted-average 
+72 
+Table of Contents 
+borrowing rates for the years ended December 31, 2011 , 2010, and 2009, were 5.2 percent, 2.8 percent, and 2.9 percent, respectively. Our weighted-average borrowing rates include cash interest payments, and excludes, cash fees paid on the unused portion of the credit facility’s aggregate commitment amount, letter of credit fees, amortization of the convertible notes debt discount, and amortization of deferred financing costs. 
+We are subject to customary covenants under our credit facility, including limitations on dividend payments and requirements to maintain certain financial ratios, which include debt to consolidated earnings before interest, taxes, depreciation, depletion, amortization, and exploration expense of less than 4.0 to 1.0 and an adjusted current ratio, as defined by our credit agreement, of no less than 1.0. As of December 31, 2011, our debt to EBITDAX ratio and adjusted current ratio as defined by our credit agreement, were 1.11 and 3.04, respectively. As of the filing date of this report, we are in compliance with all financial and non-financial covenants under our credit facility. 
+Uses of cash 
+We use cash for the acquisition, exploration, and development of oil and gas properties, and for the payment of debt obligations, trade payables, overhead, income taxes, and stockholder dividends. Expenditures for the exploration and development of oil and gas properties are the primary use of our capital resources. During 2011, we spent $1.6 billion for exploration, development capital expenditures, and leasehold acquisition. These amounts differ from the cost incurred amounts based on the timing of cash payments associated with these activities as compared to the accrual-based activity upon which the costs incurred amounts are presented. 
+The amount and allocation of future capital expenditures will depend upon a number of factors including the number and size of available economic acquisitions and drilling opportunities, our cash flows from operating, investing and financing activities, and our ability to assimilate acquisitions and execute our drilling program. In addition, the impact of oil, natural gas, and NGL prices on investment opportunities, the availability of capital and borrowing facilities, and the success of our development and exploratory activities may lead to changes in funding requirements for future development. We regularly review our capital expenditure budget to assess changes in current and projected cash flows, acquisition opportunities, debt requirements and other factors. 
+We may from time to time repurchase certain amounts of our outstanding debt securities for cash and/or through exchanges for other securities. Such repurchases or exchanges may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or exchanges will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. 
+In 2011, we paid $6.4 million in dividends to our stockholders, which constitutes an annual dividend of $0.10 per share. Our intention is to continue to make dividend payments for the foreseeable future, subject to our future earnings, our financial condition, credit facility and other covenants, and other factors which could arise. Payment of future dividends remains at the discretion of the Board of Directors. 
+As of the filing date of this report, our Board has authorized us to repurchase up to 3,072,184 shares of our common stock under our stock repurchase program. Shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility and the indentures governing our 6.625% Senior Notes and 6.50% Senior Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. There were no share repurchases in 2011, and we currently do not plan to repurchase shares in 2012. 
+On April 1, 2012, all or a portion of our outstanding 3.50% Senior Convertible Notes can be put to us at the option of the respective noteholders. If the notes are put to us on that date, we have the option of paying the purchase price in cash, shares of our common stock, or any combination thereof. On or after April 6, 2012, we will have the option of redeeming all or a portion of the outstanding notes for cash. The notes are convertible into shares of our common stock under certain circumstances, including if they are called for redemption, and we may elect to settle conversion obligations in cash, shares of our common stock, or a combination thereof. Depending on the then current trading level of our common stock and our liquidity position, we may elect to redeem the 3.50% 
+73 
+Table of Contents 
+Convertible Notes in 2012. The closing price of our common stock exceeded the conversion trigger price of $70.75 per share for at least 20 trading days in the 30 consecutive trading days ending on the last trading day for the quarters ended March 31, 2011, and December 31, 2011. However, none of the holders opted to convert their 3.50% Senior Convertible Notes during the second quarter of 2011. The notes will be convertible during the first quarter of 2012. 
+The following table presents amounts and percentage changes between years in net cash flows from our operating, investing, and financing activities. The analysis following the table should be read in conjunction with our consolidated statements of cash flows in Part II, Item 8 of this report. 
+As of and for the Years Ended December 31, 
+Amount of Changes Between 
+Percent of Change Between 
+2011 
+2010 
+2009 
+2011/2010 
+2010/2009 
+2011/2010 
+2010/2009 
+(in millions) 
+Net cash provided by operating activities 
+$ 
+760.5 
+$ 
+497.1 
+$ 
+436.1 
+$ 
+263.4 
+$ 
+61.0 
+53 
+% 
+14 
+% 
+Net cash (used in) investing activities 
+$ 
+(1,264.9 
+) 
+$ 
+(361.6 
+) 
+$ 
+(304.1 
+) 
+$ 
+(903.3 
+) 
+$ 
+(57.5 
+) 
+250 
+% 
+19 
+% 
+Net cash provided by (used in) financing activities 
+$ 
+618.5 
+$ 
+(141.1 
+) 
+$ 
+(127.5 
+) 
+$ 
+759.6 
+$ 
+(13.6 
+) 
+(538 
+)% 
+11 
+% 
+Analysis of cash flow changes between 2011 and 2010 
+Operating activities. Cash received from oil, gas, and NGL production revenues, net of derivative cash settlements of $46.4 million , increased $409.4 million to $1.2 billion for the year ended December 31, 2011. The increase was the result of a 50 percent increase in production revenue including derivative cash settlements. Additionally, cash paid for lease operating expenses in 2011 increased $26.5 million compared with 2010. We received $4.0 million in income tax refunds in 2011 compared to $25.6 million received during 2010. 
+Investing activities. Cash used for investing activities was $1.3 billion for the year ended December 31, 2011, compared with $361.6 million for the same period in 2010. Cash spent on 2011 capital expenditures increased $964.8 million , or 144 percent , to $1.6 billion . This increase in capital and exploration activities was financed mainly by higher cash flows available from operating activities, divestiture proceeds, and proceeds from the issuance of our 6.625% Senior Notes and 6.50% Senior Notes. Proceeds received from divestitures increased $53.0 million to $364.5 million for the year ended December 31, 2011, due to an increase in the size of the divestiture packages. 
+Financing activities. Net repayments to our credit facility decreased $92.0 million for the year ended December 31, 2011, compared to 2010 as our strong cash position throughout 2011 resulted in decreased borrowings. After deducting aggregate fees of $15.8 million, we received aggregate net proceeds of $684.2 million due to the issuance of our 6.625% Senior Notes and 6.50% Senior Notes during 2011. We spent $8.7 million on debt issuance costs for our amended credit facility during the year ended December 31, 2011. 
+Analysis of cash flow changes between 2010 and 2009 
+Operating activities. Cash received from oil and gas production revenues, net of the realized effects of derivative cash settlements, increased $84.6 million to $836.4 million for the year ended December 31, 2010. The increase was the result of a one percent increase in production and a 13 percent increase in our net realized price after derivative cash settlements, resulting in a 14 percent increase in production revenue. Included in the 2010 oil and gas production revenue amounts was $23.5 million of net realized hedging gains. Additionally, cash paid for lease operating expenses in 2010 decreased $29.2 million compared with 2009. We received $25.6 million in income tax refunds in 2010 compared to $9.9 million received during 2009. 
+74 
+Table of Contents 
+Investing activities. Cash used for investing activities was $361.6 million for the year ended December 31, 2010, compared with $304.1 million for the same period in 2009. We received proceeds of $311.5 million primarily from the sale of non-strategic properties located in our Rocky Mountain and Permian regions. The $39.9 million of proceeds from the sale of oil and gas properties received in 2009 related primarily to the sale of non-strategic properties located in our Rocky Mountain region that were divested of in the fourth quarter of 2009. Cash outflows for 2010 capital expenditures increased $289.0 million, or 76 percent, to $668.3 million. This was due to increased drilling activity as a result of more favorable commodity prices, an improved overall macro-economic environment, and our drilling activities in our Eagle Ford shale play. We received $16.8 million in proceeds from an insurance settlement relating to Hurricane Ike for the year ended December 31, 2009, but no material insurance proceeds were received in 2010. 
+Financing activities. Net repayments to our credit facility increased $28.0 million for the year ended December 31, 2010, compared to 2009. We spent $11.1 million on debt issuance costs for our amended credit facility during the year ended December 31, 2009. We did not incur any debt issuance costs in 2010. We received $3.3 million more in proceeds from the sale of common stock in 2010, than in 2009. 
+Commodity Price Risk and Interest Rate Risk 
+We are exposed to market risk, including the effects of changes in oil, gas, and NGL commodity prices and changes in interest rates. Changes in interest rates can affect the amount of interest we earn on our cash, cash equivalents, and short-term investments, and the amount of interest we pay on borrowings under our revolving credit facility. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate 3.50% Senior Convertible Notes, 6.625% Senior Notes, or 6.50% Senior Notes, but do affect their fair market value. 
+For fixed-rate debt, interest rate changes affect the fair market value but do not impact results of operations or cash flows. Conversely, interest rate changes for floating-rate debt generally do not affect the fair market value but do impact future results of operations and cash flows, assuming other factors are held constant. The carrying amount of our floating-rate debt typically approximates its fair value. We had no floating-rate debt outstanding as of December 31, 2011. Our fixed-rate debt outstanding, net of debt discount, at this same date was $985.1 million . As of December 31, 2011, we do not have any interest rate hedges in place to mitigate potential interest rate risks. 
+Because we produce and sell oil, gas, and NGLs, our financial results are affected when prices for these commodities fluctuate. The following table reflects our estimate of the effect on net cash flows from operations of a ten percent change in our adjusted price for oil, gas, or NGLs, and in combination for the years presented, inclusive of the impact of derivative cash settlements. These amounts have been reduced by the effective income tax rate applicable to each period since a reduction in revenue would reduce income taxes. General and administrative expenses have not been adjusted. To fund the capital expenditures we incurred in those years we would have been required to utilize amounts under our credit facility as a source of funds. In each of these years we would have had sufficient unused borrowing capacity available under our credit facility to meet this contingency without reducing or eliminating expenditures or altering our growth strategy. 
+The table below shows the effect of a ten percent decrease in adjusted price on net cash flow from operations: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+(in millions) 
+Oil 
+$ 
+(73.7 
+) 
+$ 
+(48.7 
+) 
+$ 
+(29.5 
+) 
+Natural Gas 
+(37.9 
+) 
+(30.5 
+) 
+(11.9 
+) 
+NGLs 
+(18.4 
+) 
+— 
+— 
+Total 
+$ 
+(130.0 
+) 
+$ 
+(79.2 
+) 
+$ 
+(41.4 
+) 
+We enter into commodity derivative contracts in order to reduce the impact of fluctuations in commodity 
+75 
+Table of Contents 
+prices. Please refer to Note 10 – Derivative Financial Instruments of Part II, Item 8 of this report for additional information about our oil, gas, and NGL derivative contracts, and additional information is below under the caption Summary of Oil, Gas, and NGL Derivative Contracts in Place. We do not anticipate significant changes in existing derivative contract transactions. 
+Summary of Oil, Gas, and NGL Derivative Contracts in Place 
+Our oil, gas, and NGLs derivative contracts include costless swaps and costless collar arrangements. All contracts are entered into for other-than-trading purposes. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional information regarding accounting for our derivative transactions. Commodity derivatives are an important part of our financial risk management program. The amount of commodity derivative contracts we enter into is driven by the amount of debt on our accompanying consolidated balance sheets and the level of capital and long-term commitments we have made, as well as considerations of other factors. 
+As of December 31, 2011, our commodity derivative contracts through the second quarter of 2014 totaled 7.5 million Bbls of oil, 56.7 million MMBtu of gas, and 1.3 million Bbls of NGLs. As of February 16, 2012 , the Company had commodity derivative contracts in place through the fourth quarter of 2014 for a total of 11.0 million Bbls of oil, 77.9 million MMBtu of gas, and 1.5 million Bbls of NGLs. 
+In a typical commodity swap agreement, if the agreed-upon published third-party index price is lower than the swap fixed price, we receive the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, we pay the difference. For collar agreements, we receive the difference between an agreed upon index and the floor price if the index price is below the floor price. We pay the difference between the agreed upon contracted ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the contracted floor and ceiling prices. 
+The following tables describe the approximate volumes, average contract prices, and fair value of contracts we have in place as of December 31, 2011. 
+Oil contracts 
+Oil Swaps: 
+Contract Period 
+NYMEX WTI Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair Value at 
+December 31, 2011 
+(Liability) 
+(Bbls) 
+(per Bbl) 
+(in millions) 
+First quarter 2012 
+569,000 
+$ 
+84.15 
+$ 
+(8.5 
+) 
+Second quarter 2012 
+524,000 
+$ 
+84.19 
+(7.9 
+) 
+Third quarter 2012 
+489,000 
+$ 
+83.87 
+(7.2 
+) 
+Fourth quarter 2012 
+463,000 
+$ 
+87.08 
+(5.0 
+) 
+2013 
+616,000 
+$ 
+88.22 
+(4.8 
+) 
+2014 
+661,000 
+$ 
+91.72 
+(0.9 
+) 
+All oil swaps 
+3,322,000 
+$ 
+(34.3 
+) 
+76 
+Table of Contents 
+Oil Collars: 
+Contract Period 
+NYMEX WTI 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+Fair Value at 
+December 31, 2011 
+Assets (Liability) 
+(Bbls) 
+(per Bbl) 
+(per Bbl) 
+(in millions) 
+First quarter 2012 
+391,000 
+$ 
+76.58 
+$ 
+109.96 
+$ 
+(0.5 
+) 
+Second quarter 2012 
+372,000 
+$ 
+76.55 
+$ 
+109.88 
+(0.9 
+) 
+Third quarter 2012 
+347,000 
+$ 
+76.45 
+$ 
+109.70 
+(0.9 
+) 
+Fourth quarter 2012 
+325,000 
+$ 
+76.34 
+$ 
+109.60 
+(0.8 
+) 
+2013 
+2,147,000 
+$ 
+75.84 
+$ 
+109.81 
+(4.2 
+) 
+2014 
+560,000 
+$ 
+80.00 
+$ 
+116.05 
+1.2 
+All oil collars 
+4,142,000 
+$ 
+(6.1 
+) 
+77 
+Table of Contents 
+Natural Gas Contracts 
+Natural Gas Swaps: 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair Value at 
+December 31, 2011 
+Asset 
+(MMBtu) 
+(per MMBtu) 
+(in millions) 
+First quarter 2012 
+7,930,000 
+$ 
+5.15 
+$ 
+17.4 
+Second quarter 2012 
+7,140,000 
+$ 
+4.77 
+12.6 
+Third quarter 2012 
+6,510,000 
+$ 
+4.95 
+11.7 
+Fourth quarter 2012 
+6,020,000 
+$ 
+5.20 
+10.7 
+2013 
+13,810,000 
+$ 
+5.05 
+17.0 
+2014 
+2,910,000 
+$ 
+5.42 
+3.3 
+All natural gas swaps* 
+44,320,000 
+$ 
+72.7 
+*Natural gas swaps are comprised of IF ANR OK (1%), IF CIG (2%), IF El Paso Permian (2%), IF HSC (8%), IF NGPL MidCont. (1%), IF NGPL TXOK (6%), IF NNG Ventura (1%), IF PEPL (19%), IF Reliant N/S (34%), and IF TETCO STX (26%). 
+Natural Gas Collars: 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+Fair Value at 
+December 31, 2011 
+Asset 
+(MMBtu) 
+(per MMBtu) 
+(per MMBtu) 
+(in millions) 
+2013 
+6,650,000 
+4.39 
+5.34 
+$ 
+4.8 
+2014 
+5,734,000 
+4.38 
+5.36 
+2.7 
+All natural gas collars* 
+12,384,000 
+$ 
+7.5 
+*Natural gas collars are comprised of IF HSC (18%), IF NGPL TXCO (18%), IF Reliant N/S (29%), and IF TETCO STX (35%). 
+Natural Gas Liquid Contracts 
+NGL Swaps: 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair Value at 
+December 31, 2011 
+(Liability) 
+(Bbls) 
+(per Bbl) 
+(in millions) 
+First quarter 2012 
+349,000 
+$ 
+46.04 
+$ 
+(3.4 
+) 
+Second quarter 2012 
+314,000 
+$ 
+45.64 
+(2.2 
+) 
+Third quarter 2012 
+287,000 
+$ 
+47.85 
+(1.1 
+) 
+Fourth quarter 2012 
+266,000 
+$ 
+47.72 
+(1.0 
+) 
+2013 
+84,000 
+$ 
+44.95 
+(0.9 
+) 
+All NGL swaps* 
+1,300,000 
+$ 
+(8.6 
+) 
+*NGL swaps are comprised of OPIS Mont. Belvieu LDH Propane (32%), OPIS Mont. Belvieu Purity Ethane (41%), OPIS Mont. Belvieu NON-LDH Isobutane (5%), OPIS Mont. Belvieu NON-LDH Natural Gasoline (11%), and OPIS Mont. Belvieu NON-LDH Normal Butane (11%). 
+78 
+Table of Contents 
+Commodity Derivative Contracts Entered into After December 31, 2011 
+The following tables include all commodity derivative contracts entered into subsequent to December 31, 2011, through February 16, 2012: 
+Oil Collars: 
+Contract Period 
+NYMEX WTI 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+(Bbls) 
+(per Bbl) 
+(per Bbl) 
+First quarter 2012 
+323,000 
+$ 
+85.00 
+$ 
+115.90 
+Second quarter 2012 
+371,000 
+$ 
+85.00 
+$ 
+115.90 
+Third quarter 2012 
+291,000 
+$ 
+85.00 
+$ 
+115.90 
+Fourth quarter 2012 
+241,000 
+$ 
+85.00 
+$ 
+115.90 
+2013 
+720,000 
+$ 
+85.00 
+$ 
+111.00 
+2014 
+1,614,000 
+$ 
+85.00 
+$ 
+105.12 
+All oil collars 
+3,560,000 
+Natural Gas Swaps: 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+(MMBtu) 
+(per MMBtu) 
+Fourth quarter 2012 
+2,404,000 
+$ 
+2.98 
+2013 
+6,699,000 
+$ 
+3.43 
+2014 
+12,044,000 
+$ 
+3.95 
+All natural gas swap contracts 
+21,147,000 
+*Natural gas swaps are comprised of IF HSC (76%), IF NGPL TXOK (5%), IF PEPL (10%), IF Reliant N/S (9%). 
+NGL Swaps: 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+(Bbls) 
+(per Bbl) 
+First quarter 2012 
+61,000 
+$ 
+83.11 
+Second quarter 2012 
+73,000 
+$ 
+83.07 
+Third quarter 2012 
+59,000 
+$ 
+83.09 
+Fourth quarter 2012 
+50,000 
+$ 
+83.06 
+All NGL swap contracts 
+243,000 
+*NGL swaps are comprised of OPIS Mont. Belvieu NON-LDH Isobutane (36%), OPIS Mont. Belvieu NON-LDH Natural Gasoline (36%), and OPIS Mont. Belvieu NON-LDH Normal Butane (28%). 
+79 
+Table of Contents 
+Schedule of Contractual Obligations 
+The following table summarizes our future estimated principal payments and minimum lease payments for the periods specified (in millions): 
+Contractual Obligations 
+Total 
+Less than 1 year 
+1-3 years 
+3-5 years 
+More than 5 years 
+Long-term debt 
+$ 
+1,391.0 
+$ 
+347.1 
+$ 
+91.9 
+$ 
+91.9 
+$ 
+860.1 
+Derivative liability 
+55.9 
+42.9 
+13.0 
+— 
+— 
+Net Profits Plan 
+105.8 
+20.8 
+37.6 
+32.0 
+15.4 
+Delivery commitments 
+893.6 
+24.1 
+134.3 
+190.3 
+544.9 
+Operating leases and contracts 
+205.4 
+106.9 
+74.0 
+7.7 
+16.8 
+Other 
+18.6 
+6.5 
+11.4 
+0.3 
+0.4 
+Total 
+$ 
+2,670.3 
+$ 
+548.3 
+$ 
+362.2 
+$ 
+322.2 
+$ 
+1,437.6 
+The long-term debt line in this table includes $287.5 million for the 3.50% Senior Convertible Notes, $350.0 million for the 6.625% Senior Notes, and $350.0 million for the 6.50% Senior Notes. The long-term debt balance also includes accrued interest of $173.0 million and $228.0 million for the 6.625% Senior Notes and the 6.50% Senior Notes, respectively. Additionally, we have assumed that we will redeem the 3.50% Senior Convertible Notes during 2012. Accordingly, $2.5 million of interest payments related to the 3.50% Senior Convertible Notes are included in long-term debt in the table above. The actual payments under our revolving credit facility will vary significantly. We had no outstanding borrowings under our credit facility as of December 31, 2011. 
+The above table includes estimated oil, gas, and NGL derivative payments of $55.9 million based on future market prices as of December 31, 2011. This amount represents only the liability portion of the marked-to-market value of our commodity derivatives at December 31, 2011; it does not include estimated oil, gas, and NGL derivative receipts based on December 31, 2011, market prices. This amount varies from the fair value of our derivative assets and liabilities presented on the accompanying consolidated balance sheets, as the fair value of such derivative contracts considers time value, volatility, and the risk of non-performance for us and for our counterparties. Both the marked-to-market value and fair value will change as oil, gas, and NGL commodity prices change. The overall fair value of our commodity derivative portfolio as of December 31, 2011, was a net asset of $31.2 million . 
+The table also includes $105.8 million in other long-term liabilities that represents six years of undiscounted forecasted payments for the Net Profits Plan. Payments are expected to gradually decrease for the years beyond what is shown in this table. The amounts recorded on the accompanying consolidated balance sheets reflect all future Net Profits Plan payments and the impact of discounting, and therefore differ from the amounts disclosed in this table. The variability in the amount of payments will be a direct reflection of commodity prices, production rates, capital expenditures, and operating costs in future periods. Predicting the timing and amounts of payments associated with this liability is contingent upon estimates of appropriate discount factors, adjusting for risk and time value, and upon a number of factors we cannot control. 
+The other line in the table includes the remaining funded portion of our estimated pension liability of $15.5 million , even though we recognize that we cannot accurately determine the timing of future payments. We are expected to make contributions to the Pension Plan in 2012 of $4.9 million . We made contributions of $5.3 million and in 2011. 
+In addition to the amounts included in the table above, we entered into a capital project in 2011 for the development of infrastructure in our non-operated Eagle Ford shale play, which will extend through 2013. Pursuant to the terms of our agreement for the construction, ownership, and operation of these assets, we are required to pay our portion of the expenses. Based on current estimates, we do not expect our commitment costs to exceed $75.0 million over the duration of the agreement. 
+80 
+Table of Contents 
+We have excluded asset retirement obligations because we are not able to accurately predict the precise timing of these amounts. 
+Please refer to Note 8 – Pension Benefits , Note 9 – Asset Retirement Obligations , and Note 7 – Compensation Plans , Note 10 – Derivative Financial Instruments , and Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional discussion regarding our pension liability, asset retirement obligations, Net Profits Plan liability, derivative contracts, operating leases, and gathering, processing, and transportation through-put commitments. 
+Off-balance Sheet Arrangements 
+As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of December 31, 2011, we have not been involved in any unconsolidated SPE transactions. 
+We evaluate our transactions to determine if any variable interest entities exist. If it is determined that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. 
+Critical Accounting Policies and Estimates 
+Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our estimates on historical experience and various other sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we calculate due to changes in circumstances, global economics and politics, and general business conditions. A summary of our significant accounting policies is detailed in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report. We have outlined below those policies identified as being critical to the understanding of our business and results of operations and which require the application of significant management judgment. 
+Oil and gas reserve quantities. Our estimated reserve quantities and future net cash flows are critical to the understanding of the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our financial statements including the calculations of depletion and impairment of proved oil and gas properties and the estimate of our Net Profits Plan liability. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure calculations require a ten percent discount rate to be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves, including using independent reserve engineering consultants. We expect that periodic reserve estimates will change in the future as additional information becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves at December 31 and June 30 of each year. For purposes of depletion and impairment, reserve quantities are adjusted at all interim periods for the estimated impact of additions and dispositions. Changes in depletion or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period the reserve estimates change. Please refer to Supplemental Oil and Gas Information in Part II, Item 8 of this report. 
+The following table presents information about reserve changes from period to period that due to items we 
+81 
+Table of Contents 
+do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves. 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+BCFE 
+BCFE 
+BCFE 
+Change 
+Change 
+Change 
+Revisions resulting from price changes 
+(25.3 
+) 
+42.6 
+12.0 
+Revisions resulting from performance 
+36.8 
+(17.9 
+) 
+(61.6 
+) 
+Total 
+11.5 
+24.7 
+(49.6 
+) 
+As previously noted, commodity prices are volatile, and estimates of reserves are inherently imprecise. Consequently, we expect to continue experiencing these types of changes. Please refer to additional reserves discussion under Overview of the Company. 
+The following table reflects the estimated BCFE change and percentage change to our total reported reserve volumes from the described hypothetical changes: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+BCFE 
+Percentage 
+BCFE 
+Percentage 
+BCFE 
+Percentage 
+Change 
+Change 
+Change 
+Change 
+Change 
+Change 
+A 10% decrease in SEC pricing 
+(22.2 
+) 
+(2 
+)% 
+(13.9 
+) 
+(1 
+)% 
+(25.1 
+) 
+(3 
+)% 
+A 10% decrease in proved undeveloped reserves 
+(41.5 
+) 
+(3 
+)% 
+(29.7 
+) 
+(3 
+)% 
+(14.2 
+) 
+(2 
+)% 
+The table above solely reflects the impact of a ten percent change in SEC pricing or decrease in proved undeveloped reserves and does not include additional impacts to our proved reserves that may result from our internal intent to drill hurdles. Additional reserve information can be found in the reserve table and discussion included in Items 1 and 2 of Part I of this report, and in Supplemental Oil and Gas Disclosures of Part II, Item 8 of this report. 
+Successful efforts method of accounting. Accounting principles generally accepted in the United States provide for two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method. Both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more detailed description is included in Note 1 - Summary of Significant Accounting Policies of Part II, Item 8 of this report. 
+Revenue recognition. Our revenue recognition policy is significant because revenue is a key component of our results of operations and our forward-looking statements contained in our analysis of liquidity and capital resources. We derive our revenue primarily from the sale of produced oil, gas, and NGLs. We report revenue as the gross amounts we receive before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded in the month our production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a purchaser. At the end of each month we make estimates of the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our properties, their historical performance, NYMEX and local spot market prices, and other factors as the basis for 
+82 
+Table of Contents 
+these estimates. Variances between our estimates and the actual amounts received are recorded in the month payment is received. A ten percent change in our year-end revenue accrual would have impacted net income before tax by $14.9 million in 2011. 
+Change in Net Profits Plan Liability. We record the estimated liability of future payments for our Net Profits Plan. The estimated liability is calculated based on a number of assumptions, including estimates of proved reserves, estimated future capital, present value discount factors, pricing assumptions, and overall market conditions. Please refer to Note 11 - Fair Value Measurements in Part II, Item 8 of this report for additional discussion . 
+Asset retirement obligations. We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells projected into the future based on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates, and determine what credit-adjusted risk-free discount rate to use. The impact to the accompanying consolidated statements of operations from these estimates is reflected in our depreciation, depletion, and amortization calculations and occurs over the remaining life of our respective oil and gas properties. Please refer to Note 9 – Asset Retirement Obligations in Part II, Item 8 of this report. 
+Impairment of oil and gas properties. Our proved oil and gas properties are recorded at cost. We evaluate our proved properties for impairment at least annually and when events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted cash flows to the the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates. 
+Unproved oil and gas properties are assessed periodically for impairment on a lease-by-lease basis based on the remaining lease terms, drilling results, commodity price outlook, and future capital allocations. An impairment allowance is provided on unproven property when we determine that the property will not be developed or the carrying value will not be realized. Please refer to section Impairment of Proved and Unproved Properties in Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of this report for impairment results. 
+Derivatives and Hedging. We periodically enter into commodity derivative contracts to manage our exposure to oil and gas price volatility. The accounting treatment for the change in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is designated as a hedge. Effective January 1, 2011, we elected to de-designate all of our commodity derivatives that had previously been designated as cash flow hedges as of December 31, 2010, and have elected to discontinue hedge accounting prospectively. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in accumulated other comprehensive loss until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the statement of income because changes in fair value of the derivative offsets changes in the fair value of the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative's fair value and any ineffective portion of the derivative instrument's change in fair value is recognized immediately in earnings. The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, whether or not the forecasted hedged transaction will occur, option pricing models, futures prices, volatility, and time to maturity and credit risk. The values we report in our financial statements changes as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. 
+Income taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or 
+83 
+Table of Contents 
+liability and its carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not. Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations. A one percent increase and decrease in our effective tax rate would have changed our calculated income tax expense by $3.5 million and $3.2 million, respectively, for the year ended December 31, 2011. 
+Accounting Matters 
+Please refer to the section entitled Recently Issued Accounting Standards under Note 1 – Summary of Significant Accounting Policies for additional information on the recent adoption of new authoritative accounting guidance in Part II, Item 8 of this report. 
+Environmental 
+We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes and we are unable to predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital expenditures, liquidity, and results of operations. 
+Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. For additional information about hydraulic fracturing and related environmental matters, see Risk Factors – Risks Related to Our Business – Proposed federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. 
+Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other ‘‘greenhouse gases’’ present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011. 
+In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. 
+The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require 
+84 
+Table of Contents 
+us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. 
+In terms of opportunities, the regulation of greenhouse gas emissions and the introduction of alternative incentives, such as enhanced oil recovery, carbon sequestration and low carbon fuel standards, could benefit us in a variety of ways. For example, although climate change legislation could reduce the overall demand for the oil and natural gas that we produce, the relative demand for natural gas may increase since the burning of natural gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources, such as wind or solar power become more prevalent, natural gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel standards, natural gas may become a more attractive transportation fuel. Approximately 59 and 65 percent of our production on an MCFE basis in 2011 and 2010, respectively, was natural gas. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and natural gas reservoirs, could also benefit us through the potential to obtain greenhouse gas emission allowances or offsets from or government incentives for the sequestration of carbon dioxide. 
+ITEM 7A. 
+QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+The information required by this item is provided under the captions Commodity Price Risk and Interest Rate Risk and Summary of Oil, Gas, and NGL Derivative Contracts in Place in Item 7 above and is incorporated herein by reference. 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+85 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Board of Directors and Stockholders of 
+SM Energy Company and Subsidiaries 
+Denver, Colorado 
+We have audited the accompanying consolidated balance sheets of SM Energy Company and subsidiaries (the “Company”) as of December 31, 2011 and 2010 , and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2011 . These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits. 
+We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. 
+In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of SM Energy Company and subsidiaries as of December 31, 2011 and 2010 , and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 , in conformity with accounting principles generally accepted in the United States of America. 
+As discussed in Note 1 to the consolidated financial statements, the Company changed its method of oil and gas reserve estimation and related required disclosures in 2009 with the implementation of new accounting guidance. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011 , based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 23, 2012 , expressed an unqualified opinion on the Company’s internal control over financial reporting. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 23, 2012 
+86 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED BALANCE SHEETS 
+(in thousands, except share amounts) 
+December 31, 
+2011 
+2010 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+119,194 
+$ 
+5,077 
+Accounts receivable (note 2) 
+210,368 
+163,190 
+Refundable income taxes 
+5,581 
+8,482 
+Prepaid expenses and other 
+68,026 
+45,522 
+Derivative asset 
+55,813 
+43,491 
+Deferred income taxes 
+4,222 
+8,883 
+Total current assets 
+463,204 
+274,645 
+Property and equipment (successful efforts method), at cost: 
+Land 
+1,548 
+1,491 
+Proved oil and gas properties 
+4,378,987 
+3,389,158 
+Less - accumulated depletion, depreciation, and amortization 
+(1,766,445 
+) 
+(1,326,932 
+) 
+Unproved oil and gas properties 
+120,966 
+94,290 
+Wells in progress 
+273,428 
+145,327 
+Materials inventory, at lower of cost or market 
+16,537 
+22,542 
+Oil and gas properties held for sale 
+246 
+86,811 
+Other property and equipment, net of accumulated depreciation of $23,985 in 2011 and $15,480 in 2010 
+71,369 
+21,365 
+Total property and equipment, net 
+3,096,636 
+2,434,052 
+Other noncurrent assets: 
+Derivative asset 
+31,062 
+18,841 
+Restricted cash (note 1) 
+124,703 
+— 
+Other noncurrent assets 
+83,375 
+16,783 
+Total other noncurrent assets 
+239,140 
+35,624 
+Total Assets 
+$ 
+3,798,980 
+$ 
+2,744,321 
+LIABILITIES AND STOCKHOLDERS' EQUITY 
+Current liabilities: 
+Accounts payable and accrued expenses (note 2) 
+$ 
+456,999 
+$ 
+417,654 
+Derivative liability 
+42,806 
+82,044 
+Other current liabilities 
+6,000 
+2,355 
+Total current liabilities 
+505,805 
+502,053 
+Noncurrent liabilities: 
+Long-term credit facility 
+— 
+48,000 
+3.50% Senior Convertible Notes, net of unamortized discount of $2,431 in 2011 and $11,827 in 2010 
+285,069 
+275,673 
+6.625% Senior Notes 
+350,000 
+— 
+6.50% Senior Notes 
+350,000 
+— 
+Asset retirement obligation 
+87,167 
+69,052 
+Asset retirement obligation associated with oil and gas properties held for sale 
+1,277 
+2,119 
+Net Profits Plan liability (note 11) 
+107,731 
+135,850 
+Deferred income taxes 
+568,263 
+443,135 
+Derivative liability 
+12,875 
+32,557 
+Other noncurrent liabilities 
+67,853 
+17,356 
+Total noncurrent liabilities 
+1,830,235 
+1,023,742 
+Commitments and contingencies (note 6) 
+Stockholders' equity: 
+Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 64,145,482 shares in 2011 and 63,412,800 shares in 2010; outstanding, net of treasury shares: 64,064,415 shares in 2011 and 63,310,165 shares in 2010 
+641 
+634 
+Additional paid-in capital 
+216,966 
+191,674 
+Treasury stock, at cost: 81,067 shares in 2011 and 102,635 shares in 2010 
+(1,544 
+) 
+(423 
+) 
+Retained earnings 
+1,251,157 
+1,042,123 
+Accumulated other comprehensive loss 
+(4,280 
+) 
+(15,482 
+) 
+Total stockholders' equity 
+1,462,940 
+1,218,526 
+Total Liabilities and Stockholders' Equity 
+$ 
+3,798,980 
+$ 
+2,744,321 
+The accompanying notes are an integral part of these consolidated financial statements. 
+87 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+(in thousands, except per share amounts) 
+For the Years 
+Ended December 31, 
+2011 
+2010 
+2009 
+Operating revenues and other income: 
+Oil, gas, and NGL production revenue 
+$ 
+1,332,392 
+$ 
+836,288 
+$ 
+615,953 
+Realized hedge (loss) gain (note 10) 
+(20,707 
+) 
+23,465 
+140,648 
+Gain on divestiture activity (note 3) 
+220,676 
+155,277 
+11,444 
+Marketed gas system revenue 
+69,898 
+70,110 
+58,459 
+Other operating revenue 
+1,059 
+7,694 
+5,697 
+Total operating revenues and other income 
+1,603,318 
+1,092,834 
+832,201 
+Operating expenses: 
+Oil, gas, and NGL production expense 
+290,111 
+195,075 
+206,800 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion 
+511,103 
+336,141 
+304,201 
+Exploration 
+53,537 
+63,860 
+62,235 
+Impairment of proved properties 
+219,037 
+6,127 
+174,813 
+Abandonment and impairment of unproved properties 
+7,367 
+1,986 
+45,447 
+Impairment of materials inventory 
+— 
+— 
+14,223 
+General and administrative 
+118,526 
+106,663 
+76,036 
+Bad debt recovery 
+— 
+— 
+(5,189 
+) 
+Change in Net Profits Plan liability 
+(25,477 
+) 
+(34,441 
+) 
+(7,075 
+) 
+Unrealized and realized derivative (gain) loss (note 10) 
+(37,086 
+) 
+8,899 
+20,469 
+Marketed gas system expense 
+64,249 
+66,726 
+57,587 
+Other operating expense 
+17,567 
+3,027 
+13,489 
+Total operating expenses 
+1,218,934 
+754,063 
+963,036 
+Income (loss) from operations 
+384,384 
+338,771 
+(130,835 
+) 
+Nonoperating income (expense): 
+Interest income 
+466 
+321 
+227 
+Interest expense 
+(45,849 
+) 
+(24,196 
+) 
+(28,856 
+) 
+Income (loss) before income taxes 
+339,001 
+314,896 
+(159,464 
+) 
+Income tax (expense) benefit 
+(123,585 
+) 
+(118,059 
+) 
+60,094 
+Net income (loss) 
+$ 
+215,416 
+$ 
+196,837 
+$ 
+(99,370 
+) 
+Basic weighted-average common shares outstanding 
+63,755 
+62,969 
+62,457 
+Diluted weighted-average common shares outstanding 
+67,564 
+64,689 
+62,457 
+Basic net income (loss) per common share (note 1) 
+$ 
+3.38 
+$ 
+3.13 
+$ 
+(1.59 
+) 
+Diluted net income (loss) per common share (note 1) 
+$ 
+3.19 
+$ 
+3.04 
+$ 
+(1.59 
+) 
+The accompanying notes are an integral part of these consolidated financial statements. 
+88 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) 
+(in thousands, except share amounts) 
+Additional Paid-in Capital 
+Accumulated Other Comprehensive Income (Loss) 
+Total Stockholders' Equity 
+Common Stock 
+Treasury Stock 
+Retained Earnings 
+Shares 
+Amount 
+Shares 
+Amount 
+Balances, January 1, 2009 
+62,465,572 
+$ 
+625 
+$ 
+141,283 
+(176,987 
+) 
+$ 
+(1,892 
+) 
+$ 
+957,200 
+$ 
+65,293 
+$ 
+1,162,509 
+Comprehensive loss, net of tax: 
+Net loss 
+— 
+— 
+— 
+— 
+— 
+(99,370 
+) 
+— 
+(99,370 
+) 
+Change in derivative instrument fair value 
+— 
+— 
+— 
+— 
+— 
+— 
+(35,977 
+) 
+(35,977 
+) 
+Reclassification to earnings 
+— 
+— 
+— 
+— 
+— 
+— 
+(67,344 
+) 
+(67,344 
+) 
+Pension liability adjustment 
+— 
+— 
+— 
+— 
+— 
+— 
+74 
+74 
+Total comprehensive loss 
+(202,617 
+) 
+Cash dividends, $ 0.10 per share 
+— 
+— 
+— 
+— 
+— 
+(6,247 
+) 
+— 
+(6,247 
+) 
+Issuance of common stock under Employee Stock Purchase Plan 
+86,308 
+1 
+1,515 
+— 
+— 
+— 
+— 
+1,516 
+Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings, including income tax cost of RSUs 
+156,252 
+1 
+(1,951 
+) 
+— 
+— 
+— 
+— 
+(1,950 
+) 
+Sale of common stock, including income tax benefit of stock option exercises 
+189,740 
+2 
+1,592 
+— 
+— 
+— 
+— 
+1,594 
+Stock-based compensation expense 
+1,250 
+— 
+18,077 
+50,094 
+688 
+— 
+— 
+18,765 
+Balances, December 31, 2009 
+62,899,122 
+$ 
+629 
+$ 
+160,516 
+(126,893 
+) 
+$ 
+(1,204 
+) 
+$ 
+851,583 
+$ 
+(37,954 
+) 
+$ 
+973,570 
+Comprehensive income, net of tax: 
+Net income 
+— 
+— 
+— 
+— 
+— 
+196,837 
+— 
+196,837 
+Change in derivative instrument fair value 
+— 
+— 
+— 
+— 
+— 
+— 
+16,811 
+16,811 
+Reclassification to earnings 
+— 
+— 
+— 
+— 
+— 
+— 
+6,641 
+6,641 
+Pension liability adjustment 
+— 
+— 
+— 
+— 
+— 
+— 
+(980 
+) 
+(980 
+) 
+Total comprehensive income 
+219,309 
+Cash dividends, $ 0.10 per share 
+— 
+— 
+— 
+— 
+— 
+(6,297 
+) 
+— 
+(6,297 
+) 
+Issuance of common stock under Employee Stock Purchase Plan 
+52,948 
+1 
+1,669 
+— 
+— 
+— 
+— 
+1,670 
+Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings, including income tax cost of RSUs 
+113,103 
+1 
+(2,094 
+) 
+— 
+— 
+— 
+— 
+(2,093 
+) 
+Sale of common stock, including income tax benefit of stock option exercises 
+346,377 
+3 
+5,621 
+— 
+— 
+— 
+— 
+5,624 
+Stock-based compensation expense 
+1,250 
+— 
+25,962 
+24,258 
+781 
+— 
+— 
+26,743 
+Balances, December 31, 2010 
+63,412,800 
+$ 
+634 
+$ 
+191,674 
+(102,635 
+) 
+$ 
+(423 
+) 
+$ 
+1,042,123 
+$ 
+(15,482 
+) 
+$ 
+1,218,526 
+Comprehensive income, net of tax: 
+Net income 
+— 
+— 
+— 
+— 
+— 
+215,416 
+— 
+215,416 
+Reclassification to earnings 
+— 
+— 
+— 
+— 
+— 
+— 
+12,997 
+12,997 
+Pension liability adjustment 
+— 
+— 
+— 
+— 
+— 
+— 
+(1,795 
+) 
+(1,795 
+) 
+Total comprehensive income 
+226,618 
+Cash dividends, $ 0.10 per share 
+— 
+— 
+— 
+— 
+— 
+(6,382 
+) 
+— 
+(6,382 
+) 
+Issuance of common stock under Employee Stock Purchase Plan 
+41,358 
+— 
+2,300 
+— 
+— 
+— 
+— 
+2,300 
+Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings 
+278,773 
+3 
+(9,976 
+) 
+— 
+— 
+— 
+— 
+(9,973 
+) 
+Sale of common stock, including income tax benefit of stock option exercises 
+412,551 
+4 
+5,023 
+— 
+— 
+— 
+— 
+5,027 
+Stock-based compensation expense 
+— 
+— 
+27,945 
+21,568 
+(1,121 
+) 
+— 
+— 
+26,824 
+Balances, December 31, 2011 
+64,145,482 
+$ 
+641 
+$ 
+216,966 
+(81,067 
+) 
+$ 
+(1,544 
+) 
+$ 
+1,251,157 
+$ 
+(4,280 
+) 
+$ 
+1,462,940 
+The accompanying notes are an integral part of these consolidated financial statements. 
+89 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+(in thousands) 
+For the Years Ended 
+December 31, 
+2011 
+2010 
+2009 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+215,416 
+$ 
+196,837 
+$ 
+(99,370 
+) 
+Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
+Gain on divestiture activity 
+(220,676 
+) 
+(155,277 
+) 
+(11,444 
+) 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion 
+511,103 
+336,141 
+304,201 
+Exploratory dry hole expense 
+277 
+289 
+7,810 
+Impairment of proved properties 
+219,037 
+6,127 
+174,813 
+Abandonment and impairment of unproved properties 
+7,367 
+1,986 
+45,447 
+Impairment of materials inventory 
+— 
+— 
+14,223 
+Stock-based compensation expense 
+26,824 
+26,743 
+18,765 
+Bad debt recovery 
+— 
+— 
+(5,189 
+) 
+Change in Net Profits Plan liability 
+(25,477 
+) 
+(34,441 
+) 
+(7,075 
+) 
+Unrealized derivative (gain) loss 
+(62,757 
+) 
+8,899 
+20,469 
+Loss related to hurricanes 
+— 
+— 
+8,301 
+Amortization of debt discount and deferred financing costs 
+18,299 
+13,464 
+12,213 
+Deferred income taxes 
+123,789 
+114,517 
+(39,735 
+) 
+Plugging and abandonment 
+(5,849 
+) 
+(8,314 
+) 
+(26,396 
+) 
+Other 
+(6,027 
+) 
+(3,993 
+) 
+3,382 
+Changes in current assets and liabilities: 
+Accounts receivable 
+(41,998 
+) 
+(47,153 
+) 
+46,743 
+Refundable income taxes 
+2,901 
+24,291 
+(19,612 
+) 
+Prepaid expenses and other 
+16,376 
+(35,363 
+) 
+(6,626 
+) 
+Accounts payable and accrued expenses 
+(18,073 
+) 
+53,198 
+(4,814 
+) 
+Excess income tax benefit from the exercise of stock awards 
+— 
+(854 
+) 
+— 
+Net cash provided by operating activities 
+760,532 
+497,097 
+436,106 
+Cash flows from investing activities: 
+Net proceeds from sale of oil and gas properties 
+364,522 
+311,504 
+39,898 
+Proceeds from insurance settlement 
+— 
+— 
+16,789 
+Capital expenditures 
+(1,633,093 
+) 
+(668,288 
+) 
+(379,253 
+) 
+Acquisition of oil and gas properties 
+— 
+(664 
+) 
+(76 
+) 
+Receipts from restricted cash related to 1031 exchange 
+— 
+— 
+14,398 
+Other 
+3,661 
+(4,125 
+) 
+4,152 
+Net cash used in investing activities 
+(1,264,910 
+) 
+(361,573 
+) 
+(304,092 
+) 
+Cash flows from financing activities: 
+Proceeds from credit facility 
+322,000 
+571,559 
+2,072,500 
+Repayment of credit facility 
+(370,000 
+) 
+(711,559 
+) 
+(2,184,500 
+) 
+Debt issuance costs related to credit facility 
+(8,719 
+) 
+— 
+(11,074 
+) 
+Net proceeds from 6.625% Senior Notes 
+341,122 
+— 
+— 
+Net proceeds from 6.50% Senior Notes 
+343,120 
+— 
+— 
+Proceeds from sale of common stock 
+7,327 
+6,440 
+3,110 
+Dividends paid 
+(6,382 
+) 
+(6,297 
+) 
+(6,247 
+) 
+Excess income tax benefit from the exercise of stock awards 
+— 
+854 
+— 
+Other 
+(9,973 
+) 
+(2,093 
+) 
+(1,285 
+) 
+Net cash provided by (used in) financing activities 
+618,495 
+(141,096 
+) 
+(127,496 
+) 
+Net change in cash and cash equivalents 
+114,117 
+(5,572 
+) 
+4,518 
+Cash and cash equivalents at beginning of period 
+5,077 
+10,649 
+6,131 
+Cash and cash equivalents at end of period 
+$ 
+119,194 
+$ 
+5,077 
+$ 
+10,649 
+The accompanying notes are an integral part of these consolidated financial statements. 
+90 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) 
+Supplemental schedule of additional cash flow information and non-cash investing and financing activities: 
+For the Years Ended 
+December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+Cash paid for interest, net of capitalized interest 
+$ 
+(22,133 
+) 
+$ 
+(13,340 
+) 
+$ 
+(17,884 
+) 
+Net cash refunded for income taxes 
+$ 
+4,046 
+$ 
+25,578 
+$ 
+9,857 
+For the years ended December 31, 2011, 2010, and 2009, $214.8 million , $238.5 million , and $109.0 million , respectively, are included as additions to oil and gas properties and accounts payable and accrued expenses. These oil and gas property additions are reflected in cash used in investing activities in the periods that the payables are settled. 
+91 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+Note 1 – Summary of Significant Accounting Policies 
+Description of Operations 
+SM Energy is an independent energy company engaged in the acquisition, exploration, exploitation, development and production of oil, gas, and NGLs in onshore North America, with a focus on oil and liquids-rich resource plays. 
+Basis of Presentation 
+The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") and the instructions to Form 10-K and regulation S-X. Subsidiaries that the Company does not control are accounted for using the equity or cost methods as appropriate. Equity method investments are included in other noncurrent assets in the accompanying consolidated balance sheets ("accompanying balance sheets"). Intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2011 , through the filing date of this report. 
+Use of Estimates in the Preparation of Financial Statements 
+The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization (“DD&A”), impairment of proved properties, asset retirement obligations, and the Net Profits Plan liability, each of which represents a significant component of the accompanying consolidated financial statements. 
+Cash and Cash Equivalents 
+The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. 
+Restricted Cash 
+The Company's restricted cash balance represents cash payments received from Mitsui that are contractually restricted to be used solely for development operations pursuant to the Company's Acquisition and Development Agreement with Mitsui and accordingly are classified as non-current assets. Please refer to Note 12- Acquisition and Development Agreement and Carry and Earning Agreement for additional information. 
+Accounts Receivable and Concentration of Credit Risk 
+The Company’s accounts receivables consist mainly of receivables from oil and gas purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. 
+Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. As of December 31, 2011 , and 2010 , the Company had no allowance for doubtful accounts recorded. 
+92 
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+The Company has accounts in the following locations with two national banks: Denver, Colorado; Shreveport, Louisiana; Houston, Texas; Midland, Texas; and Billings, Montana. The Company has accounts with local banks in Tulsa, Oklahoma and Billings, Montana. The Company’s policy is to invest in highly-rated instruments and to limit the amount of credit exposure at each individual institution. 
+The Company currently uses ten separate counterparties for its oil, gas, and NGL commodity derivatives. The counterparties to the Company’s derivative instruments are highly-rated entities with corporate credit ratings at or exceeding A- and Baa1 classifications by Standard & Poor’s and Moody’s, respectively. 
+Oil and Gas Producing Activities 
+In January 2010, the Financial Accounting Standards Board ("FASB") issued oil and gas reserve estimation and disclosure authoritative accounting guidance effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC final rule, " Modernization of Oil and Gas Reporting ", which was also effective for annual reports for fiscal years ending on or after December 31, 2009. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which was developed by several petroleum industry organizations and is a widely accepted standard for the management of petroleum resources. Key revisions include a requirement to use 12-month average pricing determined by averaging the first of the month prices for the preceding 12 months rather than year-end pricing for estimating proved reserves, the ability to include nontraditional resources in reserves, the ability to use new technology for determining proved reserves, and permitting disclosure of probable and possible reserves. The Company adopted these new rules and interpretations as of December 31, 2009. 
+The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management's judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in cash flows from investing activities as part of capital expenditures within the accompanying consolidated statements of cash flows. The costs of development wells are capitalized whether those wells are successful or unsuccessful. 
+DD&A of capitalized costs related to proved oil and gas properties is calculated on a pool-by-pool basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. As of December 31, 2011 , and 2010 , the Company’s estimated salvage value was $64.1 million and $67.9 million , respectively. 
+Impairment of Proved and Unproved Properties 
+Proved oil and gas property costs are evaluated for impairment and reduced to fair value, which is expected future discounted cash flows, when there is an indication that the carrying costs may not be recoverable. Expected future cash flows are calculated on all developed proved reserves and risk adjusted proved undeveloped, probable, and possible reserves using a discount rate and price forecasts selected by the Company’s management. The discount rate is a rate that management believes is representative of current market conditions. The price forecast is based on NYMEX strip pricing for the first five years, adjusted for basis differentials. At the end of the first five years, a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. An impairment is recorded on unproved property when the Company determines that either the property will not be developed or the carrying value is not realizable. 
+The Company recorded $219.0 million , $6.1 million , and $174.8 million , of proved property impairments 
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+for the years ended December 31, 2011 , 2010 , and 2009 , respectively. The Company impaired its James Lime, Cotton Valley, and Haynesville assets due to significantly lower natural gas prices in the second half of 2011. The largest portion of the impairment in 2009 related to assets located in the Company's Mid-Continent region that were impacted by lower natural gas prices and wider than normal differentials. 
+For the years ended December 31, 2011 , 2010 , and 2009 , the Company recorded expense related to the abandonment and impairment of unproved properties of $7.4 million , $2.0 million , and $45.4 million , respectively. The largest components of the 2009 impairment related to acreage located in Mississippi and Oklahoma. 
+Sales of Proved and Unproved Properties 
+The partial sale of proved properties within an existing field is accounted for as normal retirement and no gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A gain or loss on divestiture activity is recognized for all other sales of proved properties and is included in the accompanying consolidated statements of operations ("accompanying statements of operations"). 
+The partial sale of unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to the ultimate recovery of the cost applicable to the interest retained. A gain on divestiture activity is recognized to the extent that the sales price exceeds the carrying amount of the unproved property. A gain or loss on divestiture activity is recognized for all other sales of unproved property and is included in the accompanying statements of operations. For additional discussion, please refer to Note 3 – Divestitures and Assets Held for Sale . 
+Materials Inventory 
+The Company’s materials inventory is primarily comprised of tubular goods to be used in future drilling operations. Materials inventory is valued at the lower of cost or market and totaled $16.5 million and $22.5 million at December 31, 2011 , and 2010 , respectively. There were no materials inventory write downs for the years ended December 31, 2011 , and 2010 . The Company incurred $14.2 million of net materials inventory write-downs for year the ended December 31, 2009 , as a result of a decrease in the market value of tubular goods. 
+Assets Held for Sale 
+Any properties held for sale as of the date of presentation of the balance sheet have been classified as assets held for sale and are separately presented on the accompanying balance sheets at the lower of net book value or fair value less the cost to sell. The asset retirement obligation liabilities related to such properties have been reclassified to asset retirement obligations associated with oil and gas properties held for sale in the accompanying balance sheets. For additional discussion on assets held for sale, please refer to Note 3 – Divestitures and Assets Held for Sale . 
+Other Property and Equipment 
+Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets which range from three to thirty years. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts. 
+Intangible Assets 
+As of December 31, 2011 , and 2010 , the Company has $7.1 million and $4.4 million , respectively, of intangible assets, which is included as other noncurrent assets in the accompanying balance sheets. These assets arose from acquired indefinite life water rights. All indefinite life intangible assets are evaluated for impairment at 
+94 
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+least annually and if such indicators arise. 
+Cash Settlement Balancing 
+The Company uses the sales method of accounting for gas revenue whereby sales revenue is recognized on all gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. An asset or liability is recognized to the extent that there is an imbalance in excess of the remaining gas reserves on the underlying properties. As of December 31, 2011 , and 2010 , the Company’s has recorded a receivable of $1.9 million and $1.5 million , respectively, and a liability of $1.1 million and $934,000 , respectively, which is included as other noncurrent assets and other noncurrent liabilities in the accompanying balance sheets. 
+Derivative Financial Instruments 
+The Company seeks to manage or reduce commodity price risk on production by entering into derivative contracts. The Company seeks to minimize its basis risk and indexes its oil derivative contracts to NYMEX prices, its NGL derivative contracts to OPIS prices, and the majority of its gas derivative contracts to various regional index prices associated with pipelines in proximity to the Company’s areas of gas production. For additional discussion on derivatives, please see Note 10 – Derivative Financial Instruments . 
+Net Profits Plan 
+The Company records the estimated fair value of expected future payments made under the Net Profits Plan as a noncurrent liability in the accompanying balance sheets. The underlying assumptions used in the calculation of the estimated liability include estimates of production, proved reserves, recurring and workover lease operating expense, transportation, production and ad valorem tax rates, present value discount factors, pricing assumptions, and overall market conditions. The estimates used in calculating the long-term liability are adjusted from period-to-period based on the most current information attributable to the underlying assumptions. Changes in the estimated liability of future payments associated with the Net Profits Plan are recorded as increases or decreases to expense in the current period as a separate line item in the accompanying statements of operations, as these changes are considered changes in estimates. 
+The distribution amounts due to participants and payable in each period under the Net Profits Plan as cash compensation related to periodic operations are recognized as compensation expense and are included within general and administrative expense and exploration expense in the accompanying statements of operations. The corresponding current liability is included in accounts payable and accrued expenses in the accompanying balance sheets. This treatment provides for a consistent matching of cash expense with net cash flows from the oil and gas properties in each respective pool of the Net Profits Plan. For additional discussion, please refer to the heading Net Profits Plan in Note 7 – Compensation Plans and Note 11 – Fair Value Measurements . 
+Asset Retirement Obligations 
+The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. For additional discussion, please refer to Note 9 – Asset Retirement Obligations . 
+Revenue Recognition 
+The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported separately as expenses and are included in oil and gas production expense in the accompanying 
+95 
+Table of Contents 
+statements of operations. Revenue is recorded in the month the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses its knowledge of its properties, their historical performance, NYMEX, OPIS, and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates. 
+Major Customers 
+During 2011 and 2010, sales to Regency Gas Services LLC individually accounted for approximately 18 percent and 11 percent , respectively, of the Company's total oil, gas, and NGL production revenue. During 2009, sales to Teppco Crude Oil LLC individually accounted for 12 percent of the Company's total oil and gas production revenue. 
+Stock Based Compensation 
+At December 31, 2011 , the Company had stock-based employee compensation plans that included Restricted Stock Units ("RSUs"), Performance Share Awards ("PSAs"), Performance Share Units ("PSUs"), stock awards, and stock options issued to employees and non-employee directors, as more fully described in Note 7 - Compensation Plans . PSUs are structurally the same as the previously granted PSAs (collectively known as "Performance Share Units" or "PSUs"). The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance. The Company records compensation expense associated with the issuance of RSUs and PSUs based on the estimated fair value of these awards determined at the time of grant. 
+Income Taxes 
+The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amount on the financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. 
+Earnings per Share 
+Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company. 
+Diluted net income or loss per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of in-the-money outstanding stock options, unvested RSUs, contingent PSUs, and shares into which the 3.50% Senior Convertible Notes are convertible. 
+PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period. For additional discussion on PSUs, please refer to Note 7 – Compensation Plans under the heading Performance Share Units Under the Equity Incentive Compensation Plan . 
+The Company’s 3.50% Senior Convertible Notes have a net-share settlement right giving the Company the 
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+option to irrevocably elect, by notice to the trustee under the indenture for the notes, to settle the Company’s obligation, in the event that holders of the notes elect to convert all or a portion of their notes, by delivering cash in an amount equal to each $1,000 principal amount of notes surrendered for conversion and, if applicable, at the Company’s option, shares of common stock or cash, or any combination of common stock and cash, for the amount of conversion value in excess of the principal amount. For accounting purposes, the treasury stock method is used to measure the potential dilutive impact of shares associated with this conversion feature. Shares of the Company’s common stock traded at an average closing price exceeding the $54.42 conversion price for the twelve-month period ended December 31, 2011 , making them dilutive for that period. The 3.50% Senior Convertible Notes were not dilutive for any reporting period prior to 2011 and therefore do not impact the diluted earnings per share calculation for the years ended December 31, 2010 , and 2009 . 
+The treasury stock method is used to measure the dilutive impact of in-the-money stock options, unvested RSUs, contingent PSUs, and 3.50% Senior Convertible Notes as calculated in the basic and dilutive earnings per share table below. When there is a loss from continuing operations, as was the case for the year ended December 31, 2009 , all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of earnings per share. 
+The following table details the weighted-average dilutive and anti-dilutive securities related to stock options, RSUs, PSUs, and the 3.50% Senior Convertible Notes for the years presented: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+Dilutive 
+3,808,589 
+1,720,149 
+— 
+Anti-dilutive 
+— 
+— 
+1,152,127 
+The following table sets forth the calculations of basic and diluted earnings per share: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+(in thousands, except per share amounts) 
+Net income (loss) 
+$ 
+215,416 
+$ 
+196,837 
+$ 
+(99,370 
+) 
+Basic weighted-average common shares outstanding 
+63,755 
+62,969 
+62,457 
+Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs 
+2,592 
+1,720 
+— 
+Add: dilutive effect of 3.50% Senior Convertible Notes 
+1,217 
+— 
+— 
+Diluted weighted-average common shares outstanding 
+67,564 
+64,689 
+62,457 
+Basic net income (loss) per common share 
+$ 
+3.38 
+$ 
+3.13 
+$ 
+(1.59 
+) 
+Diluted net income (loss) per common share 
+$ 
+3.19 
+$ 
+3.04 
+$ 
+(1.59 
+) 
+Comprehensive Income (Loss) 
+Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders' equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of stockholders’ equity and comprehensive income (loss). 
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+The changes in the balances of components comprising other comprehensive income (loss) are presented in the following table: 
+Change in Derivative Instrument Fair Value 
+Derivative Reclassification to Earnings 
+Pension Liability Adjustments 
+(in thousands) 
+For the year ended December 31, 2009 
+Before tax income (loss) 
+$ 
+(57,613 
+) 
+$ 
+(108,071 
+) 
+$ 
+119 
+Tax benefit (expense) 
+21,636 
+40,727 
+(45 
+) 
+Income (loss), net of tax 
+$ 
+(35,977 
+) 
+$ 
+(67,344 
+) 
+$ 
+74 
+For the year ended December 31, 2010 
+Before tax income (loss) 
+$ 
+26,904 
+$ 
+10,608 
+$ 
+(1,570 
+) 
+Tax benefit (expense) 
+(10,093 
+) 
+(3,967 
+) 
+590 
+Income (loss), net of tax 
+$ 
+16,811 
+$ 
+6,641 
+$ 
+(980 
+) 
+For the year ended December 31, 2011 
+Before tax income (loss) 
+$ 
+— 
+$ 
+20,707 
+$ 
+(2,779 
+) 
+Tax benefit (expense) 
+— 
+(7,710 
+) 
+984 
+Income (loss), net of tax 
+$ 
+— 
+$ 
+12,997 
+$ 
+(1,795 
+) 
+Fair Value of Financial Instruments 
+The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had no outstanding loans under its credit facility as of December 31, 2011 . The Company had $48.0 million in borrowings outstanding under its credit facility as of December 31, 2010 . The Company’s 3.50% Senior Convertible Notes, 6.625% Senior Notes, and 6.50% Senior Notes are recorded at cost, and the fair values are disclosed in Note 11 - Fair Value Instruments. The Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. 
+Industry Segment and Geographic Information 
+The Company operates exclusively in the exploration and production segment, and all of the Company’s operations are conducted entirely in the United States in North America. The Company reports as a single industry segment. The Company’s gas marketing function provides mostly internal services and acts as the first purchaser of natural gas and natural gas liquids produced by the Company in certain cases. The Company considers its marketing function as ancillary to its oil and gas producing activities. The amount of income these operations generate from marketing gas produced by third parties is not material to the Company’s financial position, and segmentation of such activity would not provide a better understanding of the Company’s performance. However, gross revenue and expense related to marketing activities for gas produced by third parties are presented in the marketed gas system revenue and marketed gas system expense line items in the accompanying statements of operations. 
+Off-Balance Sheet Arrangements 
+The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other 
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+contractually narrow or limited purposes. The Company has not been involved in any unconsolidated SPE transactions. 
+The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that SM Energy is the primary beneficiary of a variable interest entity, that entity is consolidated into SM Energy. 
+Recently Issued Accounting Standards 
+In May 2011, the FASB issued new fair value measurement authoritative accounting guidance clarifying the application of fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the provisions of this authoritative accounting guidance and assessing the impact, if any, it may have on the Company’s fair value disclosures beginning in the first quarter of 2012. 
+In June 2011, the FASB issued new authoritative accounting guidance that states an entity that reports items of other comprehensive income has the option to present the components of net income and comprehensive income in either one continuous financial statement, or two consecutive financial statements, including reclassification adjustments. In December 2011, the FASB issued new authoritative accounting guidance which effectively deferred the requirement to present the reclassification adjustments on the face of the financial statements. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2011. The Company will apply this new athoritative accounting guidance in the Company's Quarterly Report on Form 10-Q for the period ended March 31, 2012. 
+In December 2011, the FASB issued new authoritative accounting guidance related to balance sheet offsetting of certain assets and liabilities and assets and liabilities subject to master netting arrangements. The Company currently is not affected by this new authoritative accounting guidance; however, it will continue to evaluate the provisions of this authoritative accounting guidance and assess the impact, if any, it may have on the Company’s financial statements. 
+Note 2 – Accounts Receivable and Accounts Payable and Accrued Expenses 
+Accounts receivable are comprised of the following: 
+As of December 31, 
+2011 
+2010 
+(in thousands) 
+Accrued oil, gas, and NGL sales 
+$ 
+149,384 
+$ 
+108,393 
+Due from joint interest owners 
+30,784 
+50,018 
+State severance tax refunds 
+14,979 
+2,114 
+Other 
+15,221 
+2,665 
+Total accounts receivable 
+$ 
+210,368 
+$ 
+163,190 
+99 
+Table of Contents 
+Accounts payable and accrued expenses are comprised of the following: 
+As of December 31, 
+2011 
+2010 
+(in thousands) 
+Accrued drilling costs 
+$ 
+189,749 
+$ 
+241,298 
+Revenue and severance tax payable 
+61,613 
+37,066 
+Accrued lease operating expense 
+25,197 
+17,643 
+Joint owner advances 
+79,138 
+24,698 
+Accrued compensation 
+43,056 
+45,235 
+ARO liability 
+7,462 
+11,679 
+Accrued interest payable 
+14,646 
+2,582 
+Other 
+36,138 
+37,453 
+Total accounts payable and accrued expenses 
+$ 
+456,999 
+$ 
+417,654 
+Note 3 – Divestitures and Assets Held for Sale 
+Eagle Ford Shale Divestiture 
+In August 2011 , the Company divested of certain operated Eagle Ford shale assets located in its South Texas & Gulf Coast region. This divestiture was comprised of the Company's entire operated acreage in LaSalle County, Texas, as well as an immaterial adjacent block of its operated acreage in Dimmit County, Texas. Total divestiture proceeds were $230.8 million . The estimated gain on this divestiture was $194.6 million . The final divestiture proceeds are subject to normal post-closing adjustments and are expected to be finalized during the first quarter of 2012. 
+Mid-Continent Divestiture 
+In June 2011 , the Company divested of certain non-strategic assets located in its Mid-Continent region. Total divestiture proceeds were $35.8 million . The estimated gain on this divestiture was $28.5 million . The final divestiture proceeds are subject to normal post-closing adjustments and are expected to be finalized during the first quarter of 2012. 
+Rocky Mountain Divestiture 
+In January 2011 , the Company divested of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were $45.5 million . The final gain on this divestiture was $27.2 million . 
+Permian Divestiture 
+In December 2010 , the Company completed the divestiture of certain non-strategic assets located in its Permian region. Total divestiture proceeds were $54.7 million . The final gain on this divestiture was $18.4 million . 
+Legacy Divestiture 
+In February 2010 , the Company completed the divestiture of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were $125.3 million . The final gain on this divestiture was $66.7 million . A portion of the transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”). 
+Sequel Divestiture 
+100 
+Table of Contents 
+In March 2010 , the Company completed the divestiture of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were $129.1 million . The final gain on this divestiture was $53.1 million . A portion of the transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code. 
+Assets Held for Sale 
+Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less costs to sell. Subsequent changes to estimated fair value less the cost to sell will impact the measurement of assets held for sale for which fair value is determined to be less than the carrying value of the assets. 
+In July 2011 , the Company entered into agreements with Endeavour to divest of our Marcellus shale assets and related pipeline facilities located in Pennsylvania for $80.0 million net to the Company's interest. Subsequently, Endeavour failed to consummate the transaction after giving notice of its intent to terminate the agreement. The Company has disputed Endeavour's right to take these actions and is currently pursuing legal remedies including specific performance or damages from Endeavour. Due to the uncertainty surrounding the transaction, it was determined that these assets do not continue to meet the specific criteria required for presentation as assets held for sale. As a result the Company has reclassified these assets previously classified as held for sale to assets held and used. The Company measured the assets at the lower of the assets carrying amount before the assets were classified as held for sale, adjusted for any depreciation and depletion expense that would have been recognized had the assets been continuously classified as held and used, or the assets fair value at the subsequent date that the assets no longer met the criteria for assets held for sale. As a result of this measurement, the Company recognized $14.7 million of DD&A expense and a $27.5 million write-down to proved and unproved oil and gas properties. This write-down is included in gain on divestiture activity in the accompanying statements of operations. 
+The Company determined that none of the divestitures addressed above qualified for discontinued operations accounting under financial statement presentation authoritative accounting guidance. 
+Note 4 – Income Taxes 
+The provision for income taxes consists of the following: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+Current portion of income tax (expense) benefit 
+Federal 
+$ 
+1,757 
+$ 
+(2,903 
+) 
+$ 
+21,926 
+State 
+(1,553 
+) 
+(639 
+) 
+(1,567 
+) 
+Deferred portion of income tax (expense) benefit 
+(123,789 
+) 
+(114,517 
+) 
+39,735 
+Total income tax (expense) benefit 
+$ 
+(123,585 
+) 
+$ 
+(118,059 
+) 
+$ 
+60,094 
+Effective tax rate 
+36.5 
+% 
+37.5 
+% 
+37.7 
+% 
+As a result of the exercise of stock options, the Company reduced its income tax payable in 2010 . The excess income tax benefit to the Company associated with stock awards was $854,000 in 2010 . There was no excess income tax benefit associated with stock awards in 2011 or 2009 . 
+The components of the net deferred income tax liabilities are as follows: 
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+As of December 31, 
+2011 
+2010 
+(in thousands) 
+Deferred tax liabilities: 
+Oil and gas properties 
+$ 
+639,485 
+$ 
+528,652 
+Unrealized derivative asset 
+13,274 
+— 
+Interest on 3.50% Senior Convertible Notes 
+2,256 
+2,219 
+Other 
+1,873 
+2,723 
+Total deferred tax liabilities 
+656,888 
+533,594 
+Deferred tax assets: 
+Net Profits Plan liability 
+40,148 
+50,922 
+Stock compensation 
+17,728 
+13,143 
+Federal and state tax net operating loss carryovers 
+23,651 
+10,772 
+Federal and state tax credit carryovers 
+4,301 
+— 
+Unrealized derivative liability 
+— 
+6,929 
+Other long-term liabilities 
+10,810 
+19,740 
+Total deferred tax assets 
+96,638 
+101,506 
+Valuation allowance 
+(3,791 
+) 
+(2,164 
+) 
+Net deferred tax assets 
+92,847 
+99,342 
+Total net deferred tax liabilities 
+564,041 
+434,252 
+Less: current deferred income tax liabilities 
+(3,307 
+) 
+(2,710 
+) 
+Add: current deferred income tax assets 
+7,529 
+11,593 
+Non-current net deferred tax liabilities 
+$ 
+568,263 
+$ 
+443,135 
+Current federal income tax refundable 
+$ 
+5,581 
+$ 
+8,482 
+Current state income tax payable 
+$ 
+774 
+$ 
+294 
+At December 31, 2011 , the Company had estimated a federal net operating loss carryforward of $77.2 million , which includes $42.9 million unrecognized excess income tax benefit associated with stock awards. The federal net operating loss carryforward expires in 2031 . The Company had estimated state net operating loss carryforwards of $287.8 million expiring between 2012 and 2031 . The Company has federal research and development credit carryforwards of $4.0 million expiring in 2031 and other state tax credits of $352,000 which expire between 2012 and 2021 . The Company’s valuation allowance relates to charitable contribution carryfowards, state net operating loss carryforwards, state tax credits, and state and federal income tax benefit amounts, which the Company anticipates will expire before they can be utilized. Permanent items included in the calculation of income tax for certain states are anticipated to impact the Company’s ability to deduct operating losses and realize federal income tax deduction benefits in those states, and the Company adjusts its valuation allowances accordingly. The change in the valuation allowance from 2010 to 2011, indicated below, primarily reflects a change in the Company’s position regarding anticipated utilization of charitable contribution carryforward amounts. 
+Federal income tax expense differs from the amount that would be provided by applying the statutory U.S. federal income tax rate to income before income taxes primarily due to the effect of state income taxes, research and development credits, percentage depletion, the estimated effect of the domestic production activities deduction, changes in valuation allowances, and other permanent differences, as follows: 
+102 
+Table of Contents 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+Federal statutory tax (expense) benefit 
+$ 
+(118,652 
+) 
+$ 
+(110,214 
+) 
+$ 
+55,812 
+(Increase) decrease in tax resulting from: 
+State tax (expense) benefit (net of federal benefit) 
+(6,458 
+) 
+(7,750 
+) 
+5,141 
+Research and development credit 
+4,516 
+— 
+— 
+Change in valuation allowance 
+(1,627 
+) 
+1,039 
+(56 
+) 
+Statutory depletion 
+341 
+266 
+189 
+Other 
+(1,705 
+) 
+(1,400 
+) 
+(992 
+) 
+Income tax (expense) benefit 
+$ 
+(123,585 
+) 
+$ 
+(118,059 
+) 
+$ 
+60,094 
+Acquisitions, divestitures, drilling activity, and basis differentials impacting the prices received for oil, gas, and NGLs affect apportionment of taxable income to the states where the Company owns oil and gas properties. As its apportionment factors change, the Company’s blended state income tax rate changes. This change, when applied to the Company’s total temporary differences, impacts the total income tax reported in the current year and is reflected in state taxes in the table above. Items affecting state apportionment factors are evaluated at the beginning of each year after completion of the prior year income tax return and when significant acquisition, divestiture or change in drilling activity occurs during the year. 
+The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various states. With few exceptions, the Company is no longer subject to U.S. federal or state income tax examinations by these tax authorities for years before 2007 . In the third quarter of 2011 , the Company completed a research and development credit study and filed an amended 2007 federal return to claim a credit for that year. In the first quarter of 2011 , the Company received a $5.5 million refund from its 2006 tax year as a result of a net operating loss carryback claim from the 2008 tax year. In the fourth quarter of 2010 , the Internal Revenue Service initiated an audit of the Company for the 2009 tax year. The audit was concluded in the second quarter of 2011 with a nominal decrease to the Company's total 2005 refund claim, which was $25.0 million . A quick refund claim of $22.9 million from 2005 was received in the third quarter of 2010 . The balance was received in the fourth quarter of 2011. 
+The Company complies with uncertainty provisions of the income tax authoritative accounting guidance. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. Interest expense in the accompanying statements of operations includes a negligible amount associated with income tax. In 2011, the Company also recorded a negligible amount of penalty expense associated with income taxes as a general and administrative expense. There were no penalties for 2010 and 2009 . 
+The total amount recorded for unrecognized tax benefits is presented below: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+Beginning balance 
+$ 
+807 
+$ 
+884 
+$ 
+994 
+Additions based on tax positions related to current year 
+1,172 
+— 
+— 
+Additions for tax positions of prior years 
+183 
+244 
+231 
+Reductions for lapse of statute of limitations 
+(201 
+) 
+(321 
+) 
+(341 
+) 
+Ending balance 
+$ 
+1,961 
+$ 
+807 
+$ 
+884 
+Note 5 – Long-term Debt 
+Revolving Credit Facility 
+103 
+Table of Contents 
+The Company executed a Fourth Amended and Restated Credit Agreement on May 27, 2011 . This amended revolving credit facility replaced the Company’s previous facility. The Company incurred $8.7 million of deferred financing costs in association with the amended credit facility. Borrowings under the facility are secured by substantially all of the Company’s proved oil and gas properties. The credit facility has a maximum loan amount of $2.5 billion , with current aggregate lender commitments of $1.0 billion , and a maturity date of May 27, 2016 . On November 8, 2011 , the Company's borrowing base under the credit facility was automatically reduced by approximately 25% of the aggregate principal amount of the newly-issued 6.50% Senior Notes, to $1.3 billion , down from $1.4 billion . The borrowing base is subject to regular semi-annual redeterminations by the Company's lenders. The borrowing base redetermination process considers the value of the Company’s oil and gas properties. 
+The Company must comply with certain financial and non-financial covenants under the terms of its credit facility agreement, including the limitation of the Company’s dividends to no more than $50.0 million per year. The Company was in compliance with all financial covenants under the credit facility as of December 31, 2011 . 
+Interest and commitment fees are accrued based on the borrowing base utilization grid below. Eurodollar loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table below, and Alternate Base Rate (“ABR”) and swingline loans accrue interest at Prime plus the applicable margin from the utilization table below. Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the accompanying statements of operations. 
+Borrowing Base Utilization Grid 
+Borrowing Base Utilization Percentage 
+<25% 
+≥25% <50% 
+≥50% <75% 
+≥75% <90% 
+≥90% 
+Eurodollar Loans 
+1.500 
+% 
+1.750 
+% 
+2.000 
+% 
+2.250 
+% 
+2.500 
+% 
+ABR Loans or Swingline Loans 
+0.500 
+% 
+0.750 
+% 
+1.000 
+% 
+1.250 
+% 
+1.500 
+% 
+Commitment Fee Rate 
+0.375 
+% 
+0.375 
+% 
+0.500 
+% 
+0.500 
+% 
+0.500 
+% 
+The Company had no outstanding borrowings under its credit facility as of December 31, 2011 . The Company had $48.0 million in outstanding loans under its revolving credit agreement at December 31, 2010 . The Company had $999.4 million of available borrowing capacity under its current credit facility as of February 16, 2012 , and December 31, 2011 , and $629.5 million of available borrowing capacity under its previous credit facility as of December 31, 2010 . The Company had two letters of credit outstanding totaling $608,000 at February 16, 2012 , and December 31, 2011 , and one letter of credit outstanding in the amount of $483,000 as of December 31, 2010 . Outstanding letters of credit reduce the amount available under the commitment amount on a dollar-for-dollar basis. 
+6.50% Senior Notes Due 2021 
+On November 8, 2011 , the Company issued $350.0 million in aggregate principal amount of 6.50% Senior Notes. The 6.50% Senior Notes were issued at par and mature on November 15, 2021 . The Company received net proceeds of $343.1 million after deducting fees of $6.9 million , which will be amortized as deferred financing costs over the life of the 6.50% Senior Notes. The net proceeds have been and will be used for general corporate purposes, which may include funding the put, redemption or conversion of all or a portion of the 3.50% Senior Convertible Notes. 
+Prior to November 15, 2014 , the Company may redeem up to 35 percent of the aggregate principal amount of the 6.50% Senior Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.5% of the principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 6.50% Senior Notes, in whole or in part, at any time prior to November 15, 2016 , at a redemption price equal to 100% of the principal amount, plus a specified make whole premium and accrued and unpaid interest. 
+The Company may also redeem all or, from time to time, a portion of the 6.50% Senior Notes on or after 
+104 
+Table of Contents 
+November 15, 2016 , at the prices set forth below, during the twelve-month period beginning on November 15 of the applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest: 
+2016 
+103.250 
+% 
+2017 
+102.167 
+% 
+2018 
+101.083 
+% 
+2019 and thereafter 
+100.000 
+% 
+The 6.50% Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the 6.50% Senior Notes. The Company is subject to certain covenants under the indenture governing the 6.50% Senior Notes that limit incurring additional indebtedness, issuing preferred stock, and making restricted payments, including dividends; provided, however, the first $6.5 million of dividends paid each year are not restricted by this covenant. The Company was in compliance with all covenants under its 6.50% Senior Notes as of December 31, 2011 . 
+Additionally, on November 8, 2011 , the Company entered into a registration rights agreement that provides holders of the 6.50% Senior Notes certain registration rights for the 6.50% Senior Notes under the Securities Act of 1933, as amended (the “Securities Act”). On January 19, 2012, the Company filed a registration statement relating to an offer to exchange the outstanding 6.50% Senior Notes for substantially identical notes registered under the Securities Act. The registration statement related to the exchange offer was declared effective by the Securities and Exchange Commission on January 31, 2012. The offer to exchange $350.0 million of its 6.50% Senior Notes, which have been registered under the Securities Act, for $350.0 million of its outstanding 6.50% Senior Notes has not yet closed. Under certain circumstances, in lieu of a registered exchange offer, the Company has agreed to file a shelf registration statement with respect to the 6.50% Senior Notes. If the exchange offer is not completed on or before November 8, 2012, or the shelf registration statement, if required, is not declared effective within the time periods specified in the registration rights agreement, then the Company has agreed to pay additional interest with respect to the 6.50% Senior Notes in an amount not to exceed one percent of the principal amount of the 6.50% Senior Notes until the exchange offer is completed or the shelf registration statement is declared effective. 
+6.625% Senior Notes Due 2019 
+On February 7, 2011 , the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes. The 6.625% Senior Notes were issued at par and mature on February 15, 2019 . The Company received net proceeds of $341.1 million after deducting fees of $8.9 million , which will be amortized as deferred financing costs over the life of the 6.625% Senior Notes. The net proceeds were used to repay all borrowings under the Company’s previous credit facility, fund the Company’s ongoing capital expenditure program, and general corporate purposes. 
+Prior to February 15, 2014 , the Company may redeem up to 35 percent of the aggregate principal amount of the 6.625% Senior Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.625% of the principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 6.625% Senior Notes, in whole or in part, at any time prior to February 15, 2015 , at a redemption price equal to 100% of the principal amount, plus a specified make whole premium and accrued and unpaid interest. 
+The Company may also redeem all or, from time to time, a portion of the 6.625% Senior Notes on or after February 15, 2015 , at the prices set forth below, during the twelve-month period beginning on February 15 of the applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest: 
+2015 
+103.313 
+% 
+2016 
+101.656 
+% 
+2017 and thereafter 
+100.000 
+% 
+105 
+Table of Contents 
+The 6.625% Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the 6.625% Senior Notes. The Company is subject to certain covenants under the indenture governing the 6.625% Senior Notes that limit incurring additional indebtedness, issuing preferred stock, and making restricted payments, including dividends; provided, however, the first $6.5 million of dividends paid each year are not restricted by this covenant. The Company was in compliance with all financial covenants under its 6.625% Senior Notes as of December 31, 2011 . 
+Additionally, on February 7, 2011 , the Company entered into a registration rights agreement that provides holders of the 6.625% Senior Notes certain registration rights for the 6.625% Senior Notes under the Securities Act. On January 11, 2012, the offer to exchange $350.0 million of its 6.625% Senior Notes, which have been registered under the Securities Act, for $350.0 million of its outstanding 6.625% Senior Notes was completed. 
+3.50% Senior Convertible Notes Due 2027 
+On April 4, 2007 , the Company issued $287.5 million in aggregate principal amount of 3.50% Senior Convertible Notes. The 3.50% Senior Convertible Notes mature on April 1, 2027 , unless converted prior to maturity, redeemed, or purchased by the Company. The 3.50% Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. 
+Holders may convert their notes based on a conversion rate of 18.3757 shares of the Company’s common stock per $1,000 principal amount of the 3.50% Senior Convertible Notes (which is equal to an initial conversion price of $54.42 per share), subject to adjustment and contingent upon and only under the following circumstances: (1) if the closing price of the Company’s common stock reaches specified thresholds or the trading price of the notes falls below specified thresholds, (2) if the notes are called for redemption, (3) if specified distributions to holders of the Company’s common stock are made or specified corporate transactions occur, (4) if a fundamental change occurs, or (5) during the ten trading days prior to but excluding the maturity date. 
+Upon conversion of the 3.50% Senior Convertible Notes, holders will receive cash or common stock or any combination thereof as elected by the Company. At any time prior to the maturity date of the notes, the Company has the option to unilaterally and irrevocably elect to net share settle its obligations upon conversion of the notes in cash and, if applicable, shares of common stock. If the Company makes this election, then the Company will pay the following to holders for each $1,000 principal amount of notes converted in lieu of shares of common stock: (1) an amount in cash equal to the lesser of (i) $1,000 or (ii) the conversion value determined in the manner set forth in the indenture for the 3.50% Senior Convertible Notes, and (2) if the conversion value exceeds $1,000 , the Company will also deliver, at its election, cash or common stock or a combination of cash and common stock with respect to the remaining value deliverable upon conversion. 
+If a holder of 3.50% Senior Convertible Notes elects to convert its notes in connection with certain events that constitute a change of control before April 1, 2012 , the Company will pay, to the extent described in the related indenture, a make-whole premium by increasing the conversion rate applicable to the 3.50% Senior Convertible Notes. In addition, the Company will pay contingent interest in cash, commencing with any six-month period beginning on or after April 1, 2012 . Contingent interest will be payable if the average trading price of a note for the five trading days ending on the third trading day immediately preceding the first day of the relevant six-month period equals 120 percent or more of the principal amount of the 3.50% Senior Convertible Notes. 
+Holders of the 3.50% Senior Convertible Notes may elect to surrender all or a portion of their 3.50% Senior Convertible Notes for conversion under certain circumstances, including during a calendar quarter if the closing price of the Company’s common stock was more than 130 percent of the conversion price of $54.42 per share for at least 20 trading days in the 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter. If holders elect to convert all or a portion of the 3.50% Senior Convertible Notes during a calendar quarter in which they are eligible to do so, they will receive cash, shares of the Company’s common stock, 
+106 
+Table of Contents 
+or any combination thereof as may be elected by the Company under the indenture for the 3.50% Senior Convertible Notes. The Company's common stock exceeded the conversion trigger price of $70.75 at various times during 2011. However, none of the holders opted to convert their 3.50% Senior Convertible Notes during the year. The Company's common stock exceeded the conversion trigger price for the quarter ended December 31, 2011 . Therefore, the holders of the 3.50% Senior Convertible Notes have the right to convert all or a portion of their notes during the first quarter of 2012. 
+On or after April 6, 2012, the Company may redeem for cash all or a portion of the 3.50% Senior Convertible Notes at a redemption price equal to 100 percent of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any, up to but excluding the applicable redemption date. Holders of the 3.50% Senior Convertible Notes may require the Company to purchase all or a portion of their notes on each of April 1, 2012, April 1, 2017, and April 1, 2022, at a purchase price equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. On April 1, 2012, the Company may pay the purchase price in cash, in shares of common stock, or in any combination of cash and common stock. On April 1, 2017, and April 1, 2022, the Company must pay the purchase price in cash. 
+Capitalized Interest 
+Capitalized interest costs for the Company for the years ended December 31, 2011 , 2010 , and 2009 , were $10.8 million , $4.3 million , and $1.9 million , respectively. 
+Note 6 – Commitments and Contingencies 
+Commitments 
+The Company has entered into various agreements, which include drilling rig leasing contracts of $143.0 million , gathering, transportation, and processing through-put commitments of $893.6 million , office space leases, including maintenance, of $37.4 million , hydraulic fracturing contracts of $19.2 million , and other miscellaneous contracts and leases of $5.7 million . The annual minimum payments for the next five years and total minimum lease payments thereafter are presented below: 
+Years Ending December 31, 
+(in thousands) 
+2012 
+$ 
+131,021 
+2013 
+99,633 
+2014 
+108,629 
+2015 
+97,401 
+2016 
+100,635 
+Thereafter 
+561,642 
+Total 
+$ 
+1,098,961 
+The Company has gathering, processing, and transportation through-put commitments with various parties that require delivery of a fixed determinable quantity of product. The aggregate minimum commitment to deliver is 1,766 Bcf of natural gas and 9 MMBbls of oil. These contracts expire at various dates through 2023 and the total amount of the commitment is $893.6 million . The Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. The Company expects to fulfill the delivery commitments. 
+The Company leases office space under various operating leases with terms extending as far as September 30, 2022 . Rent expense for 2011 , 2010 , and 2009 was $3.7 million , $2.7 million , and $2.3 million , respectively. Rent expense for 2009 is net of sub lease rent of $185,000 ; there is no sublease rent for 2010 or 2011. The Company also leases office equipment under various operating leases. 
+107 
+Table of Contents 
+In addition to the amounts in the above table, the Company entered into a three-year capital project commencing 2011 for the development of infrastructure in the Company's non-operated Eagle Ford shale play. Pursuant to the terms of the agreement for the construction, ownership and operation of the assets, the Company is required to pay its portion of the costs. Based on current estimates, the Company does not expect its costs to exceed $75 million over the duration of the agreement. 
+Contingencies 
+The Company is subject to litigation and claims that have arisen in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such pending litigation and claims will not have a material effect on the results of operations, the financial position, or cash flows of the Company. 
+The Company is currently a defendant in litigation where the plaintiffs claim an aggregate overriding royalty interest of 7.46875 percent in production from approximately 22,000 of the Company’s net acres in the Eagle Ford shale play in South Texas. The plaintiffs seek to quiet title to their claimed overriding royalty interest and seek the recovery of unpaid overriding royalty interest proceeds allegedly due. The Texas District Court issued an order granting plaintiffs’ motion for summary judgment, but the Company believes that the summary judgment order is incorrect under the governing agreements and applicable law, and the Company has filed its appeal and will continue to contest the claim. The court entered judgment against all defendants awarding the plaintiffs damages of $5.1 million . If the plaintiffs were to ultimately prevail, the overriding royalty interest would reduce the Company’s net revenue interest in the affected acreage. The Company does not currently believe that an unfavorable ultimate outcome is probable, nor that if the plaintiffs prevail there would be a material effect on the financial position of the Company. Based on the Company’s current view of the facts and circumstances of the case, no accrual has been made for any loss. 
+Note 7 – Compensation Plans 
+Cash Bonus Plan 
+The Company has a cash bonus plan based on a performance measurement framework whereby selected eligible employee participants may be awarded an annual cash bonus. The plan document provides that no participant may receive an annual bonus under the plan of more than 200 percent of his or her base salary. As the plan is currently administered, any awards under the plan are based on Company and regional performance, and are then further refined by individual performance. The Company accrues cash bonus expense based upon the Company’s current year’s performance. Included in general and administrative and exploration expense in the accompanying statements of operations are $23.9 million , $21.6 million , and $7.8 million of cash bonus expense related to the specific performance year for the years ended December 31, 2011 , 2010 , and 2009 , respectively. 
+Equity Incentive Compensation Plan 
+There are several components to the equity compensation plan, referred to as the Equity Plan throughout this report, that are described in this section. Various types of equity awards have been granted by the Company in different periods. 
+As of December 31, 2011 , 2.7 million shares of common stock remained available for grant under the Equity Plan. The issuance of a direct share benefit such as a share of common stock, a restricted share, a RSU, or a PSU counts as 1.43 shares against the number of shares available to be granted under the Equity Plan. Each PSU has the potential to count as 2.86 shares against the number of shares available to be granted under the Equity Plan based on the final multiplier. Stock option grants count as one share for each instrument granted against the number of shares available to be granted under the Equity Plan. Stock options were issued out of the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan. 
+108 
+Table of Contents 
+Performance Share Units Under the Equity Incentive Compensation Plan 
+PSUs are the primary form of long-term equity incentive compensation for the Company. The PSU factor is based on the Company’s performance after completion of a three-year performance period. The performance criteria for the PSUs are based on a combination of the Company’s annualized Total Shareholder Return ("TSR") for the performance period and the relative measure of the Company’s TSR compared with the annualized TSR of an index comprised of certain peer companies for the performance period. PSUs are recognized as general and administrative and exploration expense over the vesting period of the award. 
+The fair value of PSUs was measured at the grant date using a stochastic process method using the Geometric Brownian Motion Model (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three-year performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences to the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company's expected volatility, dividend yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a three year vesting period, as well as the volatilities and dividend yields for each of the Company's peers. 
+Total expense recorded for PSUs was $19.7 million , $17.7 million , and $9.3 million for the years ended December 31, 2011 , 2010 , and 2009 , respectively. As of December 31, 2011 , there was $26.4 million of total unrecognized expense related to PSUs, which is being amortized through 2014 . 
+A summary of the status and activity of PSUs for the years ended December 31, 2011 , 2010 , and 2009 is presented in the following table: 
+2011 
+2010 
+2009 
+PSUs 
+Weighted-Average Grant-Date Fair Value 
+PSUs 
+Weighted-Average Grant-Date Fair Value 
+PSUs 
+Weighted-Average Grant-Date Fair Value 
+Non-vested at beginning of year (1) 
+1,110,666 
+$ 
+39.48 
+1,069,090 
+$ 
+32.52 
+464,333 
+$ 
+26.48 
+Granted (1) 
+266,282 
+$ 
+91.45 
+387,651 
+$ 
+52.35 
+725,092 
+$ 
+35.59 
+Vested (1) 
+(364,172 
+) 
+$ 
+35.74 
+(210,801 
+) 
+$ 
+31.18 
+(76,781 
+) 
+$ 
+27.20 
+Forfeited (1) 
+(126,882 
+) 
+$ 
+33.32 
+(135,274 
+) 
+$ 
+34.28 
+(43,554 
+) 
+$ 
+28.62 
+Non-vested at end of year (1) 
+885,894 
+$ 
+57.52 
+1,110,666 
+$ 
+39.48 
+1,069,090 
+$ 
+32.52 
+(1) 
+The number of awards assumes a one multiplier. The final number of shares of common stock issued may vary depending on the ending three -year performance multiplier, which ranges from zero to two . 
+The total fair value of PSUs that vested during the years ended December 31, 2011 , 2010 , and 2009 was $13.0 million , $6.6 million , and $1.8 million , respectively. 
+The Company granted PSUs in 2011 , 2010 , and 2009 as part of its regular annual long-term equity compensation process. The fair value of these grants was $24.3 million , $20.3 million , and $25.8 million for the 2011 , 2010 , and 2009 grants, respectively. The PSUs vest 1/7 th , 2/7 ths , and 4/7 ths on the first three anniversary dates of their issuances. 
+109 
+Table of Contents 
+During 2011, the Company settled 305,423 PSUs that relate to awards granted in 2008 through the issuance of shares of the Company's common stock in accordance with the terms of the PSU awards. As a result, the Company issued a net of 206,468 shares of common stock associated with these grants. The remaining 98,955 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs. 
+Restricted Stock Units Under the Equity Incentive Compensation Plan 
+The Company grants RSUs as a part of its equity incentive compensation program to eligible employees, consultants, and members of the Board of Directors. Restrictions and vesting periods for the awards are determined by the Board of Directors and are set forth in the award agreements. Each RSU represents a right for one share of the Company’s common stock to be delivered upon settlement of the award at the end of a specified period. RSUs are recognized as general and administrative and exploration expense over the vesting period of the award. 
+The total expense associated with RSUs for the years ended December 31, 2011 , 2010 , and 2009 , was $5.3 million , $7.7 million , and $7.9 million , respectively. As of December 31, 2011 , there was $7.5 million of total unrecognized expense related to unvested RSU awards, which is being amortized through 2014 . The Company records compensation expense associated with the issuance of RSUs based on the estimated fair value of the awards. The fair value of an RSU is equal to the closing price of the Company's common stock on the day of grant. 
+A summary of the status and activity of non-vested RSUs for the years ended December 31, 2011 , 2010 , and 2009 , is presented below: 
+2011 
+2010 
+2009 
+RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+Non-vested at beginning of year 
+333,359 
+$ 
+31.16 
+407,123 
+$ 
+34.67 
+402,297 
+$ 
+48.24 
+Granted 
+98,952 
+$ 
+72.69 
+128,865 
+$ 
+40.31 
+241,745 
+$ 
+23.87 
+Vested 
+(105,820 
+) 
+$ 
+30.61 
+(160,398 
+) 
+$ 
+46.30 
+(211,092 
+) 
+$ 
+46.26 
+Forfeited 
+(17,614 
+) 
+$ 
+36.80 
+(42,231 
+) 
+$ 
+35.43 
+(25,827 
+) 
+$ 
+50.35 
+Non-vested at end of year 
+308,877 
+$ 
+44.33 
+333,359 
+$ 
+31.16 
+407,123 
+$ 
+34.67 
+The total fair value of RSUs that vested during the years ended December 31, 2011 , 2010 , and 2009 , was $3.2 million , $7.4 million , and $9.8 million , respectively. 
+The Company issued 98,952 RSUs in 2011 , 128,865 RSUs in 2010 , and 241,745 RSUs in 2009 as part of its long-term equity compensation process. The fair value associated with these issuances was $7.2 million , $5.2 million , and $5.8 million , respectively. These RSUs vest 1/7 th , 2/7 ths , and 4/7 ths on the first three anniversary dates of their issuances. 
+During the years ended December 31, 2011 , 2010 , and 2009 , the Company settled 105,820 , 160,381 , and 215,700 RSUs, respectively. The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, the Company issued net shares of common stock of 72,305 , 113,103 , and 156,252 for 2011 , 2010 , and 2009 , respectively. The remaining 33,515 , 47,278 , and 59,448 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon the delivery of the shares underlying those RSUs for 2011 , 2010 , and 2009 , respectively. 
+110 
+Table of Contents 
+Stock Option Grants Under the Equity Incentive Compensation Plan 
+The Company has previously granted stock options under the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan. The last issuance of stock options occurred on December 31, 2004. Stock options to purchase shares of the Company’s common stock had been granted to eligible employees and members of the Board of Directors. All options granted under the option plans have been granted at exercise prices equal to the respective closing market price of the Company’s underlying common stock on the grant dates. All stock options granted under the option plans are exercisable for a period of up to ten years from the date of grant. As of December 31, 2011, 2010, and 2009, there was no unrecognized compensation expense related to stock option awards. 
+A summary of activity associated with the Company’s Stock Option Plans during the last three years is presented in the following table: 
+Weighted - 
+Average 
+Aggregate 
+Exercise 
+Intrinsic 
+Shares 
+Price 
+Value 
+For the year ended December 31, 2009 
+Outstanding, start of year 
+1,509,710 
+$ 
+12.69 
+Exercised 
+(189,740 
+) 
+$ 
+8.40 
+4,625,148 
+Forfeited 
+(45,050 
+) 
+$ 
+13.38 
+Outstanding, end of year 
+1,274,920 
+$ 
+13.31 
+$ 
+26,684,106 
+Vested and exercisable at end of year 
+1,274,920 
+$ 
+13.31 
+$ 
+26,684,106 
+For the year ended December 31, 2010 
+Outstanding, start of year 
+1,274,920 
+$ 
+13.31 
+Exercised 
+(346,377 
+) 
+$ 
+13.77 
+11,281,865 
+Forfeited 
+(7,778 
+) 
+$ 
+16.66 
+Outstanding, end of year 
+920,765 
+$ 
+13.11 
+$ 
+42,192,057 
+Vested and exercisable at end of year 
+920,765 
+$ 
+13.11 
+$ 
+42,192,057 
+For the year ended December 31, 2011 
+Outstanding, start of year 
+920,765 
+$ 
+13.11 
+Exercised 
+(412,551 
+) 
+$ 
+12.19 
+24,359,240 
+Forfeited 
+— 
+$ 
+— 
+Outstanding, end of year 
+508,214 
+$ 
+13.86 
+$ 
+30,109,110 
+Vested and exercisable at end of year 
+508,214 
+$ 
+13.86 
+$ 
+30,109,110 
+A summary of additional information related to options outstanding as of December 31, 2011 , follows: 
+111 
+Table of Contents 
+Options Outstanding and Exercisable 
+Number 
+Weighted- 
+Of Options 
+Average 
+Weighted- 
+Outstanding 
+Remaining 
+Average 
+Range of 
+and 
+Contractual 
+Exercise 
+Exercise Prices 
+Exercisable 
+Life 
+Price 
+$ 
+10.86 
+- 
+$ 
+11.95 
+35,964 
+0.66 years 
+$ 
+11.76 
+12.03 
+- 
+12.03 
+29,043 
+0.50 years 
+12.03 
+12.08 
+- 
+12.08 
+13,080 
+0.39 years 
+12.08 
+12.50 
+- 
+12.50 
+80,261 
+1.0 years 
+12.50 
+12.53 
+- 
+12.53 
+43,001 
+1.3 years 
+12.53 
+12.66 
+- 
+12.66 
+48,055 
+1.8 years 
+12.66 
+13.39 
+- 
+13.39 
+21,051 
+1.8 years 
+13.39 
+13.65 
+- 
+13.65 
+54,189 
+1.5 years 
+13.65 
+14.25 
+- 
+14.25 
+134,710 
+2.0 years 
+14.25 
+20.87 
+- 
+20.87 
+48,860 
+3.0 years 
+20.87 
+Total 
+508,214 
+The fair value of options was measured at the date of grant using the Black-Scholes-Merton option-pricing model. 
+Cash flows resulting from excess tax benefits are to be classified as part of cash flows from financing activities. Excess tax benefits are realized tax benefits from tax deductions for vested RSUs, settled PSUs, and exercised options in excess of the deferred tax asset attributable to stock compensation costs for such equity awards. The Company recorded $854,000 of excess tax benefits for the year ended December 31, 2010 , as cash inflows from financing activities. The Company recorded no excess tax benefits for the years ended December 31, 2011 , and December 31, 2009 . Cash received from exercises under all share-based payment arrangements for the years ended December 31, 2011 , 2010 , and 2009 , was $5.0 million , $4.8 million , and $1.6 million , respectively. 
+Director Shares 
+In 2011 , 2010 , and 2009 , the Company issued 21,568 , 24,258 , and 50,094 shares, respectively, of the Company's common stock held as treasury shares to its non-employee directors pursuant to the Company’s Equity Plan. The Company recorded compensation expense related to these issuances of $1.2 million , $781,000 , and $688,000 for the years ended December 31, 2011 , 2010 , and 2009 , respectively. 
+Employee Stock Purchase Plan 
+Under the Company’s Employee Stock Purchase Plan ("ESPP"), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in fair market value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the purchase period. All shares issued under the ESPP as of December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of the IRC. The Company has 1.4 million shares available under the ESPP for issuance as of December 31, 2011 . Shares issued under the ESPP totaled 41,358 in 2011 , 52,948 in 2010 , and 86,308 in 2009 . Total proceeds to the Company for the issuance of these shares were $2.3 million in 2011 , $1.7 million in 2010 , and $1.5 million in 2009 , respectively. 
+The fair value of ESPP shares was measured at the date of grant using the Black-Scholes-Merton option-pricing model. Expected volatility was calculated based on the Company's historical daily common stock price, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with a six month vesting period. 
+112 
+Table of Contents 
+The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+Risk free interest rate 
+0.2 
+% 
+0.2 
+% 
+0.3 
+% 
+Dividend yield 
+0.2 
+% 
+0.3 
+% 
+0.5 
+% 
+Volatility factor of the expected market 
+price of the Company’s common stock 
+36.3 
+% 
+46.3 
+% 
+95.1 
+% 
+Expected life (in years) 
+0.5 
+0.5 
+0.5 
+The Company expensed $682,000 , $550,000 , and $848,000 for the years ended December 31, 2011 , 2010 , and 2009 , respectively, based on the estimated fair value of grants. 
+401(k) Plan 
+The Company has a defined contribution pension plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute up to 60 percent of their base salaries up to the contribution limits established under the IRC. The Company matches each employee’s contribution up to 6 percent of the employee’s base salary and may make additional contributions at its discretion. The Company’s contributions to the 401(k) Plan were $2.9 million , $2.5 million , and $2.5 million for the years ended December 31, 2011 , 2010 , and 2009 , respectively. No discretionary contributions were made by the Company to the 401(k) Plan for any of these years. 
+Net Profits Plan 
+Under the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during a year were designated within a specific pool. Key employees recommended by senior management and designated as participants by the Company’s Compensation Committee of the Board of Directors and employed by the Company on the last day of that year became entitled to payments under the Net Profits Plan after the Company has received net cash flows returning 100 percent of all costs associated with that pool. Thereafter, ten percent of future net cash flows generated by the pool are allocated among the participants and distributed at least annually. The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the Company has recovered 200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the ten percent level. In December 2007, the Board of Directors discontinued the creation of new pools under the Net Profits Plan. As a result, the 2007 Net Profits Plan pool was the last pool established by the Company. 
+Cash payments made or accrued under the Net Profits Plan that have been recorded as either general and administrative expense or exploration expense are detailed in the table below: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+General and administrative expense 
+$ 
+19,326 
+$ 
+19,798 
+$ 
+18,399 
+Exploration expense 
+2,091 
+2,633 
+1,463 
+Total 
+$ 
+21,417 
+$ 
+22,431 
+$ 
+19,862 
+Additionally, the Company made or accrued cash payments under the Net Profits Plan of $6.3 million , $26.1 million , and $724,000 for the years ended December 31, 2011 , 2010 , and 2009 , respectively, as a result of divestiture proceeds. The cash payments are accounted for as a reduction in the gain on divestiture activity in the accompanying statements of operations. 
+113 
+Table of Contents 
+The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate line item in the accompanying statements of operations. The change in the estimated liability is recorded as a non-cash expense or benefit in the current period. The amount recorded as an expense or benefit associated with the change in the estimated liability is not allocated to general and administrative expense or exploration expense because it is associated with the future net cash flows from oil and gas properties in the respective pools rather than results being realized through current period production. If the Company allocated the change in liability to these specific functional line items, based on the current allocation of actual distributions made by the Company, such expenses or benefits would predominately be allocated to general and administrative expense. The amount that would be allocated to exploration expense is minimal in comparison. Over time, less of the amount distributed relates to prospective exploration efforts as more of the amount distributed is to employees that have terminated employment and do not provide ongoing exploration support to the Company. 
+Note 8 – Pension Benefits 
+Pension Plans 
+The Company has a non-contributory defined benefit pension plan covering substantially all employees who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan”). 
+The Company recognizes the funded status (i.e, the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s pension plan in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment to accumulated other comprehensive income, net of tax. The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31. 
+Obligations and Funded Status for Both Pension Plans 
+For the Years Ended December 31, 
+2011 
+2010 
+(in thousands) 
+Change in benefit obligations 
+Projected benefit obligation at beginning of year 
+$ 
+23,867 
+$ 
+18,550 
+Service cost 
+3,800 
+3,392 
+Interest cost 
+1,184 
+1,120 
+Amendments 
+170 
+— 
+Actuarial loss 
+1,957 
+2,480 
+Benefits paid 
+(1,498 
+) 
+(1,675 
+) 
+Projected benefit obligation at end of year 
+$ 
+29,480 
+$ 
+23,867 
+Change in plan assets 
+Fair value of plan assets at beginning of year 
+$ 
+10,332 
+$ 
+9,101 
+Actual return on plan assets 
+(176 
+) 
+1,181 
+Employer contribution 
+5,260 
+1,725 
+Benefits paid 
+(1,476 
+) 
+(1,675 
+) 
+Fair value of plan assets at end of year 
+$ 
+13,940 
+$ 
+10,332 
+Funded status at end of year 
+$ 
+(15,540 
+) 
+$ 
+(13,535 
+) 
+The Company’s funded status for the Pension Plans for the years ended December 31, 2011 and 2010 , is $15.5 million and $13.5 million , respectively, and is recognized in the accompanying balance sheets as a portion of other noncurrent liabilities. No plan assets of the Qualified Pension Plan were returned to the Company during the 
+114 
+Table of Contents 
+fiscal year ended December 31, 2011 . There are no plan assets in the Nonqualified Pension Plan. The plan was amended to increase the vesting percent to 40% after attaining two years of service and increasing by 20% per year until fully vested. The impact of this change in the vesting schedule is reflected in amendments in the table above. 
+Information for Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets for Both Plans 
+As of December 31, 
+2011 
+2010 
+(in thousands) 
+Projected benefit obligation 
+$ 
+29,480 
+$ 
+23,867 
+Accumulated benefit obligation 
+$ 
+21,697 
+$ 
+17,457 
+Less: Fair value of plan assets 
+13,940 
+10,332 
+Underfunded accumulated benefit obligation 
+$ 
+7,757 
+$ 
+7,125 
+Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the interest cost on those liabilities, less the expected return on plan assets. The expected long-term rate on plan assets is applied to a calculated value of plan assets that recognizes changes in fair value over a five-year period. This practice is intended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences between actual returns on assets and expected returns based on long-term rate of return assumptions. Amortization of unrecognized net gain or loss resulting from experience different from that assumed and from changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of net periodic benefit cost for a year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds ten percent of the greater of the projected benefit obligation and the market-related value of plan assets, the amortization is the excess divided by the average remaining service period of participating employees expected to receive benefits under the plan. 
+Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated other comprehensive loss as of December 31, 2011 , and 2010 , consist of: 
+As of December 31, 
+2011 
+2010 
+(in thousands) 
+Unrecognized actuarial losses 
+$ 
+8,501 
+$ 
+(5,892 
+) 
+Unrecognized prior service costs 
+170 
+— 
+Unrecognized transition obligation 
+— 
+— 
+Accumulated other comprehensive loss 
+$ 
+8,671 
+$ 
+(5,892 
+) 
+The estimated net loss that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year is $586,000 . 
+Other pre-tax changes recognized in other comprehensive income during 2011 , 2010 , and 2009 , were as follows: 
+115 
+Table of Contents 
+As of December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+Net actuarial gain (loss) 
+$ 
+(3,014 
+) 
+$ 
+(1,937 
+) 
+$ 
+(239 
+) 
+Prior service cost 
+(170 
+) 
+— 
+— 
+Less: Amortization of: 
+Actuarial loss 
+(405 
+) 
+(367 
+) 
+(358 
+) 
+Total other comprehensive income (loss) 
+$ 
+(2,779 
+) 
+$ 
+(1,570 
+) 
+$ 
+119 
+Components of Net Periodic Benefit Cost for Both Pension Plans 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+Components of net periodic benefit cost 
+Service cost 
+$ 
+3,800 
+$ 
+3,392 
+$ 
+2,500 
+Interest cost 
+1,184 
+1,120 
+934 
+Expected return on plan assets that reduces periodic pension cost 
+(880 
+) 
+(638 
+) 
+(430 
+) 
+Amortization of prior service cost 
+— 
+— 
+— 
+Amortization of net actuarial loss 
+405 
+367 
+372 
+Net periodic benefit cost 
+$ 
+4,509 
+$ 
+4,241 
+$ 
+3,376 
+Gains and losses in excess of ten percent of the greater of the benefit obligation and the market-related value of assets are amortized over the average remaining service period of active participants. 
+Pension Plan Assumptions 
+Weighted-average assumptions to measure the Company’s projected benefit obligation and net periodic benefit cost are as follows: 
+As of December 31, 
+2011 
+2010 
+2009 
+Projected benefit obligation 
+Discount rate 
+4.7% 
+5.3% 
+6.1% 
+Rate of compensation increase 
+6.2% 
+6.2% 
+6.2% 
+Net periodic benefit cost 
+Discount rate 
+5.3% 
+6.1% 
+6.1% 
+Expected return on plan assets 
+7.5% 
+7.5% 
+7.5% 
+Rate of compensation increase 
+6.2% 
+6.2% 
+6.2% 
+The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans. The policy does not permit the direct investment of plan assets in the Company’s securities. The Company’s investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of diversification, assessment of risk, and targeting the optimal expected returns for given levels of risk are applied. 
+The Company’s investment portfolio contains a diversified blend of common stocks and bonds, which may 
+116 
+Table of Contents 
+reflect varying rates of return. The investments are further diversified within each asset classification. The portfolio diversification provides protection against a single security or class of securities having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a periodic basis to maintain the target allocations. The Company’s weighted-average asset allocation for the Qualified Pension Plan is as follows: 
+Target 
+As of December 31, 
+Asset Category 
+2012 
+2011 
+2010 
+Equity securities 
+60.0 
+% 
+61.8 
+% 
+60.8 
+% 
+Debt securities 
+40.0 
+% 
+37.7 
+% 
+39.2 
+% 
+Other 
+— 
+% 
+0.5 
+% 
+— 
+% 
+Total 
+100.0 
+% 
+100.0 
+% 
+100.0 
+% 
+There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in that plan. An expected return on plan assets of 7.5 percent was used to calculate the Company’s obligation under the Qualified Pension Plan for 2011 and 2010 . Factors considered in determining the expected return include the 60 percent equity and 40 percent debt securities mix of investment of plan assets and the long-term historical rate of return provided by the equity and debt securities markets. The difference in investment income using the projected rate of return compared to the actual rates of return for the past two years was not material and will not have a material effect on the accompanying statements of operations or cash flows from operating activities in future years. 
+Fair Value Assumptions 
+The Company’s pension plan assets consist of funds that have quoted net asset values within active markets. The individual funds are derived from quoted equity and debt securities within active markets with no judgment involved. As such, the funds are deemed to be Level 1. The fair value of the Company’s pension plan assets as of December 31, 2011 , utilizing the fair value hierarchy discussed in Note 11 – Fair Value Measurements is as follows: 
+Assets: 
+Level 1 
+Level 2 
+Level 3 
+(in thousands) 
+Cash and Money Market Funds 
+$ 
+66 
+— 
+— 
+Equity Securities 
+Foreign Large Blend (1) 
+2,048 
+— 
+— 
+U.S. Small Blend (2) 
+2,290 
+— 
+— 
+U.S. Large Blend (3) 
+4,278 
+— 
+— 
+Fixed Income Securities 
+Intermediate Term Bond (4) 
+5,258 
+— 
+— 
+Total 
+$ 
+13,940 
+— 
+— 
+(1) 
+International equities are invested in companies that trade on active exchanges outside the U.S. and are well diversified among a dozen or more developed markets. Active and passive strategies are employed. 
+(2) 
+U.S. equities are invested in companies that are well diversified by industry sector and equity style, such as growth and value strategies, that trade on active exchanges within the U.S. Active and passive management strategies are employed. At least 80% of this fund is invested in equity securities of small companies. 
+(3) 
+U.S. equities include companies that are well diversified by industry sector and equity style, such as growth and value strategies, that trade on active exchanges within the U.S. Active and passive management strategies are employed. At least 80% of this fund is invested in equity securities designed to replicate the holdings and weightings of the stocks listed in the S&P 500 index. 
+(4) 
+Intermediate term bonds seek total return. At least 80% of this fund is invested in a diversified portfolio of bonds, which include all types of securities. It invests primarily in bonds of corporate and governmental issues located in the U.S. and foreign countries, including emerging markets all of which trade on active exchanges. 
+117 
+Table of Contents 
+The fair value of the Company’s pension plan assets as of December 31, 2010 , is as follows (see footnotes above): 
+Assets: 
+Level 1 
+Level 2 
+Level 3 
+(in thousands) 
+Cash and Money Market Funds 
+$ 
+4 
+$ 
+— 
+$ 
+— 
+Equity Securities 
+Foreign Large Blend (1) 
+1,444 
+— 
+— 
+U.S. Small Blend (2) 
+1,647 
+— 
+— 
+U.S. Large Blend (3) 
+3,185 
+— 
+— 
+Fixed Income Securities 
+Intermediate Term Bond (4) 
+4,052 
+— 
+— 
+Total 
+$ 
+10,332 
+$ 
+— 
+$ 
+— 
+Contributions 
+The Company contributed $5.3 million , $1.7 million , and $2.0 million , to the Pension Plans in the years ended December 31, 2011 , 2010 , and 2009 , respectively. The Company is expected to make a $4.9 million contribution to the Pension Plans in 2012. 
+Benefit Payments 
+The Pension Plans made actual benefit payments of $1.5 million , $1.7 million , and $945,000 in the years ended December 31, 2011 , 2010 , and 2009 , respectively. Expected benefit payments over the next ten years are as follows (in thousands): 
+Years Ending December 31, 
+2012 
+$ 
+1,296 
+2013 
+2,360 
+2014 
+2,513 
+2015 
+2,205 
+2016 
+2,668 
+2017 through 2021 
+$ 
+23,258 
+Note 9 – Asset Retirement Obligations 
+The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement obligations is included in the operating section of the Company’s accompanying consolidated statements of cash flows. 
+The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s abandonment liabilities range from 6.5 percent to 12 percent . Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives or if federal or state regulators enact new requirements 
+118 
+Table of Contents 
+regarding the abandonment of wells. 
+A reconciliation of the Company’s asset retirement obligation liability is as follows: 
+As of December 31, 
+2011 
+2010 
+(in thousands) 
+Beginning asset retirement obligation 
+$ 
+82,849 
+$ 
+102,080 
+Liabilities incurred 
+5,465 
+4,738 
+Liabilities settled 
+(8,365 
+) 
+(30,523 
+) 
+Accretion expense 
+5,948 
+5,583 
+Revision to estimated cash flows 
+10,009 
+971 
+Ending asset retirement obligation 
+$ 
+95,906 
+$ 
+82,849 
+As of December 31, 2011 , and 2010 , the Company had $1.3 million and $2.1 million , respectively, of asset retirement obligation associated with the oil and gas properties held for sale included in a separate line item on the Company’s accompanying balance sheets. Additionally, as of December 31, 2011 , and 2010 , accounts payable and accrued expenses contain $7.5 million and $11.7 million , respectively, related to the Company’s current asset retirement obligation liability for estimated plugging and abandonment costs associated with platforms that are being relinquished or retired. 
+Note 10 – Derivative Financial Instruments 
+Oil, Natural Gas, and NGL Commodity Hedges 
+To mitigate a portion of the exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows, the Company has entered into various commodity derivative contracts. The Company’s derivative contracts in place include swap and collar arrangements for oil, natural gas, and NGLs. As of December 31, 2011 , the Company has commodity derivative contracts in place through the second quarter of 2014 for a total of 7.5 million Bbls of oil, 56.7 million MMBtu of gas, and 1.3 million Bbls of NGLs. As of February 16, 2012 , the Company had commodity derivative contracts in place through the fourth quarter of 2014 for a total of 11.0 million Bbls of oil, 77.9 million MMBtu of gas, and 1.5 million Bbls of NGLs. 
+The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The Company derives internal valuation estimates that take into consideration the counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The pertinent factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The commodity derivative markets are highly active. The fair value of the commodity derivative contracts was a net asset of $31.2 million and a net liability of $52.3 million at December 31, 2011 , and December 31, 2010 , respectively. 
+Discontinuance of Cash Flow Hedge Accounting 
+Prior to January 1, 2011 , the Company designated its commodity derivative contracts as cash flow hedges, for which unrealized changes in fair value were recorded to accumulated other comprehensive income (loss) (“AOCIL”), to the extent the hedges were effective. As of January 1, 2011 , the Company elected to de-designate all of its commodity derivative contracts that had been previously designated as cash flow hedges at December 31, 2010 . As a result, subsequent to December 31, 2010 , the Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in AOCIL. The Company decided to discontinue the use of hedge accounting prospectively. 
+119 
+Table of Contents 
+At December 31, 2010 , accumulated other comprehensive loss (“AOCL”) included $11.8 million of unrealized losses net of income tax, representing the change in fair value of the Company’s open commodity derivative contracts designated as cash flow hedges as of that balance sheet date, less any ineffectiveness recognized. As a result of discontinuing hedge accounting on January 1, 2011 , such fair values at December 31, 2010 , were frozen in AOCL as of the de-designation date and are reclassified into earnings as the original derivative transactions settle. During the year ended December 31, 2011 , $13.0 million of, net of income tax, derivative losses relating to de-designated commodity hedges were reclassified from AOCL into earnings. As of December 31, 2011 , AOCL included $1.1 million of, net of income tax, unrealized gains on commodity derivative contracts that had been previously designated as cash flow hedges. The Company expects to reclassify into earnings from AOCL a $2.4 million gain, net of income tax, related to de-designated commodity derivative contracts during the next twelve months. 
+Please refer to Note 11 – Fair Value Measurements for more information regarding the Company’s derivative instruments. The following table details the fair value of derivatives recorded in the accompanying balance sheets, by category: 
+As of December 31, 2011 
+Derivative Assets 
+Derivative Liabilities 
+Balance Sheet 
+Classification 
+Fair Value 
+Balance Sheet 
+Classification 
+Fair Value 
+(in thousands) 
+Commodity Contracts 
+Current Assets 
+$ 
+55,813 
+Current Liabilities 
+$ 
+42,806 
+Commodity Contracts 
+Noncurrent Assets 
+31,062 
+Noncurrent liabilities 
+12,875 
+Derivatives not designated as hedging instruments 
+$ 
+86,875 
+$ 
+55,681 
+As of December 31, 2010 
+Derivative Assets 
+Derivative Liabilities 
+Balance Sheet 
+Classification 
+Fair Value 
+Balance Sheet 
+Classification 
+Fair Value 
+(in thousands) 
+Commodity Contracts 
+Current Assets 
+$ 
+43,491 
+Current Liabilities 
+$ 
+82,044 
+Commodity Contracts 
+Noncurrent Assets 
+18,841 
+Noncurrent Liabilities 
+32,557 
+Derivatives designated as hedging instruments 
+$ 
+62,332 
+$ 
+114,601 
+The following table summarizes the unrealized and realized gains and losses on derivative cash settlements and changes in fair value of derivative contracts not designated as hedging instruments as presented in the accompanying statements of operations. 
+120 
+Table of Contents 
+For the year ended December 31, 2011 
+(in thousands) 
+Cash settlement (gain) loss: 
+Oil contracts 
+$ 
+22,633 
+Natural gas contracts 
+(10,711 
+) 
+NGL contracts 
+13,749 
+Total cash settlement loss 
+$ 
+25,671 
+Unrealized (gain) loss on changes in fair value: 
+Oil contracts 
+$ 
+(3,391 
+) 
+Natural gas contracts 
+(64,310 
+) 
+NGL contracts 
+4,944 
+Total net unrealized (gain) on change in fair value 
+$ 
+(62,757 
+) 
+Total unrealized and realized derivative (gain) loss 
+$ 
+(37,086 
+) 
+The following table details the effect of derivative instruments on AOCIL and the accompanying statements of operations (net of income tax): 
+Location on 
+Accompanying 
+Statements of 
+Operations 
+For the Years Ended December 31, 
+Derivatives 
+2011 
+2010 
+2009 
+(in thousands) 
+Amount reclassified from AOCIL to realized hedge (loss) gain 
+Commodity Contracts 
+Realized hedge (loss) gain 
+$ 
+12,997 
+$ 
+6,641 
+$ 
+(67,344 
+) 
+The realized net hedge loss for the year ended December 31, 2011 , is comprised of realized cash settlements on commodity derivative contracts that were previously designated as cash flow hedges, whereas the realized net hedge gain for the years ended December 31, 2010 and 2009 , is comprised of realized cash settlements on all commodity derivative contracts. Realized hedge gains or losses from the settlement of commodity derivatives previously designated as cash flow hedges are reported in the total operating revenues and other income section of the accompanying statements of operations. The Company realized a net loss of $20.7 million , a net gain of $23.5 million , and a net gain of $140.6 million from its commodity derivative contracts for the years ended December 31, 2011 , 2010 , and 2009 , respectively. 
+As noted above, effective January 1, 2011 , the Company elected to de-designate all of its commodity derivative contracts that had been previously designated as cash flow hedges, and as such no new gains or losses are deferred in AOCIL at December 31, 2011 . The following table details the effect of derivative instruments on AOCIL and the accompanying balance sheets (net of income tax): 
+Derivatives 
+Location on Accompanying Balance Sheets 
+For the years ended December 31, 
+2010 
+2009 
+(in thousands) 
+Amount of gain (loss) on derivatives recognized in AOCIL during the period (effective portion) 
+Commodity Contracts 
+AOCIL 
+$ 
+16,811 
+$ 
+(35,977 
+) 
+The Company has no derivatives designated as cash flow hedges at December 31, 2011 . The following table details the ineffective portion of derivative instruments classified as cash flow hedges on the accompanying 
+121 
+Table of Contents 
+statements of operations for the years ended December 31, 2010 and 2009 . 
+Loss Recognized in 
+Earnings 
+(Ineffective Portion) 
+Location on 
+Accompanying 
+Statements of 
+Operations 
+Derivatives Qualifying as Cash Flow Hedges 
+For the Years Ended December 31, 
+2010 
+2009 
+(in thousands) 
+Commodity Contracts 
+Unrealized and realized derivative (gain) loss 
+$ 
+8,899 
+$ 
+20,469 
+Credit Related Contingent Features 
+As of December 31, 2011 , and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility syndicate. The Company’s credit facility is secured by liens on substantially all of the Company’s proved oil and gas properties. 
+Convertible Note Derivative Instrument 
+The contingent interest provision of the 3.50% Senior Convertible Notes is an embedded derivative instrument. As of December 31, 2011 and 2010 , the value of this derivative was determined to be immaterial. 
+Note 11 – Fair Value Measurements 
+The Company follows fair value measurement authoritative accounting guidance for all assets and liabilities measured at fair value. That authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs: 
+• 
+Level 1 – Quoted prices in active markets for identical assets or liabilities 
+• 
+Level 2 – Quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable 
+• 
+Level 3 – Significant inputs to the valuation model are unobservable 
+The following is a listing of the Company’s assets and liabilities that are measured at fair value and where they are classified within the hierarchy as of December 31, 2011 : 
+Level 1 
+Level 2 
+Level 3 
+(in thousands) 
+Assets: 
+Derivatives (1) 
+$ 
+— 
+$ 
+86,875 
+$ 
+— 
+Proved oil and gas properties (2) 
+$ 
+— 
+$ 
+— 
+$ 
+139,992 
+Unproved oil and gas properties (2) 
+— 
+— 
+15,809 
+Liabilities: 
+Derivatives (1) 
+$ 
+— 
+$ 
+55,681 
+$ 
+— 
+Net Profits Plan (1) 
+$ 
+— 
+$ 
+— 
+$ 
+107,731 
+(1) This represents a financial asset or liability that is measured at fair value on a recurring basis. 
+122 
+Table of Contents 
+(2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. 
+The following is a listing of the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and where they are classified within the hierarchy as of December 31, 2010 : 
+Level 1 
+Level 2 
+Level 3 
+(in thousands) 
+Assets: 
+Derivatives 
+$ 
+— 
+$ 
+62,332 
+$ 
+— 
+Liabilities: 
+Derivatives 
+$ 
+— 
+$ 
+114,601 
+$ 
+— 
+Net Profits Plan 
+$ 
+— 
+$ 
+— 
+$ 
+135,850 
+Both financial and non-financial assets and liabilities are categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the hierarchy. There were no non-financial assets or liabilities measured at fair value on a nonrecurring basis at December 31, 2010 . 
+Derivatives 
+The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration the counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. 
+Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may ask counterparties to post collateral if their ratings deteriorate. In some instances the Company will attempt to novate the trade to a more stable counterparty. 
+Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any liability position with a counterparty. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date. All of the Company’s derivative counterparties are members of the Company's credit facility bank syndicate. 
+The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and with other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date. 
+Net Profits Plan 
+The Net Profits Plan is a standalone liability for which there is no available market price, principal market, or market participants. Certain inputs for this instrument are unobservable and are therefore classified as Level 3 
+123 
+Table of Contents 
+inputs. The Company employs the income approach, which converts expected future cash flow amounts to a single present value amount. This technique uses the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value. There is a direct correlation between realized oil, gas, and NGL commodity prices driving net cash flows and the Net Profits Plan liability. Generally, higher commodity prices result in a larger Net Profits Plan liability and vice versa. 
+The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool. The calculation of this liability is a significant management estimate. For those pools currently in payout, a discount rate of 12 percent is used to calculate this liability. A discount rate of 15 percent is being used to calculate the liability for pools that have not reached payout. These rates are intended to represent the best estimate of the present value of expected future payments under the Net Profits Plan. 
+The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions, and the discount rates used in the calculations. The Company continually evaluates the assumptions used in this calculation in order to consider the current market environment for oil, gas, and NGL prices, costs, discount rates, and overall market conditions. The Net Profits Plan liability is determined using price assumptions of five one -year strip prices with the fifth year’s pricing then carried out indefinitely. The average price is adjusted for realized price differentials and to include the effects of forecasted production covered by derivative contracts in the relevant periods. The non-cash expense associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the oil, gas, and NGL commodity markets. 
+If the commodity prices used in the calculation changed by five percent , the liability recorded at December 31, 2011 , would differ by approximately $9 million . A one percentage point change in the discount rate would result in a change to the liability of approximately $5 million . Actual cash payments to be made to participants in future periods are dependent on realized actual production, realized commodity prices, and actual costs associated with the properties in each individual pool of the Net Profits Plan. Consequently, actual cash payments are inherently different from the amounts estimated. 
+No published market quotes exist on which to base the Company’s estimate of fair value of the Net Profits Plan liability. As such, the recorded fair value is based entirely on management estimates that are described within this footnote. While some inputs to the Company’s calculation of fair value on the Net Profits Plan’s future payments are from published sources, others, such as the discount rate and the expected future cash flows, are derived from the Company’s own calculations and estimates. The following table reflects the activity for the Net Profits Plan liability measured at fair value using Level 3 inputs: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+Beginning balance 
+$ 
+135,850 
+$ 
+170,291 
+$ 
+177,366 
+Net increase in liability (1) 
+2,269 
+14,063 
+13,511 
+Net settlements (1) (2) (3) 
+(30,388 
+) 
+(48,504 
+) 
+(20,586 
+) 
+Transfers in (out) of Level 3 
+— 
+— 
+— 
+Ending balance 
+$ 
+107,731 
+$ 
+135,850 
+$ 
+170,291 
+(1) 
+Net changes in the Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations. 
+(2) 
+Settlements represent cash payments made or accrued under the Net Profits Plan. The Company accrued or made cash payments under the Net Profits Plan relating to divestiture proceeds of $6.3 million , $26.1 million , and $724,000 for the years ended December 31, 2011 , 2010 , and 2009 respectively. 
+(3) 
+During the first quarter of 2011, the Company elected to cash out several Net Profits Plan pools associated with the acquisition of Nance Petroleum Corporation in 1999, through a $2.6 million direct payment. As a result, the Company reduced its Net Profits Plan liability by that amount. There is no impact on the accompanying statements of operations for 
+124 
+Table of Contents 
+the period ended December 31, 2011, related to these settlements. 
+Long-term Debt 
+Based on the secondary market trading price of the 3.50% Senior Convertible Notes, the estimated fair value of the notes was approximately $394 million and $351 million as of December 31, 2011 , and 2010 , respectively. The fair value of the embedded contingent interest derivative was immaterial as of December 31, 2011 , and 2010 . 
+Based on the secondary market trading price, the fair market value of the 6.625% Senior Notes and the 6.50% Senior Notes as of December 31, 2011 , was approximately $359 million and $360 million , respectively. 
+Proved Oil and Gas Properties 
+Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the Company’s management. The calculation of the discount rate is based on the best information available and estimated to be 12 percent for the year ended December 31, 2011 . Management believes that the discount rate is representative of current market conditions and considers the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on NYMEX strip pricing, adjusted for basis differentials, for the first five years. At the end of the first five years, a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. 
+As a result of asset write-downs discussed in Note 1 - Summary of Significant Accounting Policies and Note 3 - Divestitures and Assets Held for Sale , the proved oil and gas properties measured at fair value within the accompanying balance sheets were $140.0 million as of December 31, 2011 . There were no proved oil and gas properties measured at fair value at December 31, 2010 . 
+Unproved Oil and Gas Properties 
+Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. The Company uses a market approach and Level 3 inputs to measure the fair value of unproved properties. The calculation of the discount rate is based on the best information available and estimated to be 12 percent for the year ended December 31, 2011. Management believes that the discount rate is representative of current market conditions and includes the following factors: estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. 
+As a result of the asset write-downs discussed in Note 3 - Divestitures and Assets Held for Sale , the unproved oil and gas properties measured at fair value within the accompanying balance sheets were $15.8 million as of December 31, 2011 . There were no unproved oil and gas properties measured at fair value at December 31, 2010 . 
+Materials Inventory 
+Materials inventory is valued at the lower of cost or market. The Company uses Level 2 inputs to measure the fair value of materials inventory, which is primarily comprised of tubular goods. The Company uses third party market quotes and compares the quotes to the book value of the materials inventory. If the book value exceeds the quoted market price, the Company reduces the book value to the market price. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing materials inventory. There were no materials inventory measured at fair value within the accompanying balance sheets at December 31, 2011 , and 2010 . 
+125 
+Table of Contents 
+Asset Retirement Obligations 
+The income valuation technique is utilized by the Company to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value within the accompanying balance sheets at December 31, 2011 and 2010 . 
+Please refer to Note 10 – Derivative Financial Instruments and Note 9 – Asset Retirement Obligations for more information regarding the Company’s derivative instruments and asset retirement obligations. 
+Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement 
+Acquisition and Development Agreement 
+In June 2011, the Company entered into an Acquisition and Development Agreement with Mitsui E&P Texas LP (“Mitsui”), an indirect subsidiary of Mitsui & Co., Ltd (the “Acquisition and Development Agreement”). Pursuant to the Acquisition and Development Agreement, the Company agreed to transfer to Mitsui a 12.5 percent working interest in certain non-operated oil and gas assets representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick, and Webb Counties, Texas. As consideration for the oil and gas interests transferred, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs attributable to the Company's remaining interest in these assets following the closing of the transaction, until Mitsui has expended an aggregate $680.0 million on behalf of the Company. Based on the Company's forecast of the operator's drilling plans, it will take three to four years to fully utilize the carry. The agreement also provided for the conveyance of one-half of the Company’s ownership in related gathering assets in exchange for the reimbursement by Mitsui of 50 percent of costs incurred on those assets by the Company through the closing date. The effective date of the transfer was March 1, 2011 , and the transaction closed on December 2, 2011. Mitsui has reimbursed the Company for capital expenditures and other costs, net of revenues, that the Company paid and attributable to the transferred interest during the period between the effective date and the closing date. The Company will apply these reimbursed costs to the remaining ten percent of the Company’s drilling and completion costs for the affected acreage. 
+As of December 31, 2011, the Company received $124.7 million of cash payments from Mitsui that are contractually restricted to be used solely for development operations pursuant to the Acquisition and Development Agreement and accordingly are classified as non-current assets. The Company has recorded a corresponding liability equal to the restricted cash balance. The portion of the liability related to development operations expected to occur within the next year is recorded in accounts payable and accrued expenses within the accompanying balance sheets. The portion of the liability related to development operations expected to occur more than one year in the future is recorded in other noncurrent liabilities within the accompanying balance sheets as of December 31, 2011. There was no net impact on the accompanying consolidated statement of cash flows as restricted cash was offset against the corresponding liability in investing activities. None of the carry had been utilized as of year-end. Legal and commission costs associated with the execution of the arrangement were recorded as other operating expense in the accompanying statements of operations. 
+Carry and Earning Agreement 
+On April 29, 2010 , the Company entered into a Carry and Earning Agreement, which effectively provided for a third party to earn 95 percent of SM Energy’s interest in approximately 8,400 net acres in a portion of the Company’s East Texas Haynesville shale acreage, as well as an interest in several wells and five percent of SM Energy’s interest in approximately 23,400 net acres in a separate portion of the Company’s Haynesville acreage in East Texas. In exchange for these interests, the third party invested $91.3 million to fund the drilling and completion costs of horizontal wells in the portion of the leases where the Company retained 95 percent of its interest. The parties now share all costs of operations within the area of joint ownership in accordance with their respective ownership interests. 
+126 
+Table of Contents 
+Note 13 - Suspended Well Costs 
+The following table reflects the net changes in capitalized exploratory well costs during 2011 , 2010 , and 2009 . The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+Beginning balance on January 1, 
+$ 
+35,862 
+$ 
+34,384 
+$ 
+9,437 
+Additions to capitalized exploratory well costs pending the determination of proved reserves 
+15,618 
+35,862 
+34,384 
+Reclassifications to wells, facilities, and equipment based on the determination of proved reserves 
+(32,880 
+) 
+(34,384 
+) 
+(7,569 
+) 
+Capitalized exploratory well costs charged to expense 
+— 
+— 
+(1,868 
+) 
+Ending balance at December 31, 
+$ 
+18,600 
+$ 
+35,862 
+$ 
+34,384 
+The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+Exploratory well costs capitalized for one year or less 
+$ 
+15,618 
+$ 
+35,862 
+$ 
+34,384 
+Exploratory well costs capitalized for more than one year 
+2,982 
+— 
+— 
+Ending balance at December 31, 
+$ 
+18,600 
+$ 
+35,862 
+$ 
+34,384 
+Number of projects with exploratory well costs that have been capitalized more than a year 
+2 
+— 
+— 
+The table above consists of two exploratory wells located in our Permian region. The Company drilled successful surrounding test wells in the same prospect as the above wells in late 2011 and early 2012 to assess the value of re-entering these exploratory wells to target the formation through horizontal drilling. Minimal capital has been spent on these wells during the year due to further development of the prospect using horizontal drilling. Management is currently analyzing the economics of advancing this project. 
+***************** 
+127 
+Table of Contents 
+Supplemental Oil and Gas Information (unaudited) 
+Costs Incurred in Oil and Gas Producing Activities 
+Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+Development costs 
+$ 
+1,208,255 
+$ 
+299,308 
+$ 
+213,971 
+Facility costs 
+112,372 
+80,328 
+9,137 
+Exploration costs 
+177,465 
+443,888 
+154,122 
+Acquisitions 
+Proved properties 
+— 
+664 
+76 
+Leasing activity 
+55,237 
+53,192 
+41,677 
+Total, including asset retirement obligation (1)(2) 
+$ 
+1,553,329 
+$ 
+877,380 
+$ 
+418,983 
+(1) 
+Includes capitalized interest of $10.8 million , $4.3 million , and $1.9 million for the years ended December 31, 2011 , 2010 , and 2009 , respectively. 
+(2) 
+Includes amounts relating to estimated asset retirement obligations of $19.3 million , $5.8 million , and $(805,000) for the years ended December 31, 2011 , 2010 , and 2009 , respectively. 
+Oil and Gas Reserve Quantities 
+The reserve estimates presented below were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance issued by the FASB effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC's " Modernization of Oil and Gas Reporting " rule, which was also effective for annual reports for fiscal years ending on or after December 31, 2009. 
+Proved reserves are the estimated quantities of oil, gas, and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. All of the Company’s estimated proved reserves are located in North America. 
+The table below presents a summary of changes in the Company's estimated proved reserves for each of the years in the three-year period ended December 31, 2011. The Company engaged Ryder Scott to audit internal engineering estimates for at least 80 percent of the PV-10 value of our estimated proved reserves in each year presented. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. 
+128 
+Table of Contents 
+For the Years Ended December 31, 
+2011 (1) 
+2010 (2) 
+2009 (3) 
+Oil 
+Gas 
+NGLs 
+Oil or Condensate 
+Gas 
+NGLs 
+Oil or Condensate 
+Gas 
+NGLs 
+(MMBbl) 
+(Bcf) 
+(MMBbl) 
+(MMBbl) 
+(Bcf) 
+(MMBbl) 
+(MMBbl) 
+(Bcf) 
+(MMBbl) 
+Total proved reserves 
+Beginning of year 
+57.4 
+640.0 
+— 
+53.8 
+449.5 
+— 
+51.4 
+557.4 
+— 
+Revisions of previous estimate 
+(0.9 
+) 
+(76.7 
+) 
+15.6 
+3.1 
+6.1 
+— 
+4.5 
+(76.8 
+) 
+— 
+Discoveries and extensions 
+26.9 
+223.5 
+17.8 
+16.2 
+172.9 
+— 
+3.4 
+51.9 
+— 
+Infill reserves in an existing proved field 
+2.8 
+14.8 
+0.5 
+2.8 
+97.2 
+— 
+1.2 
+29.9 
+— 
+Sales of 
+reserves (4) 
+(6.4 
+) 
+(37.3 
+) 
+(2.9 
+) 
+(12.1 
+) 
+(14.0 
+) 
+— 
+(0.4 
+) 
+(41.8 
+) 
+— 
+Purchases of minerals in place 
+— 
+— 
+— 
+— 
+0.2 
+— 
+— 
+— 
+— 
+Production 
+(8.1 
+) 
+(100.3 
+) 
+(3.5 
+) 
+(6.4 
+) 
+(71.9 
+) 
+— 
+(6.3 
+) 
+(71.1 
+) 
+— 
+End of year (5) 
+71.7 
+664.0 
+27.5 
+57.4 
+640.0 
+— 
+53.8 
+449.5 
+— 
+Proved developed reserves 
+Beginning of year 
+46.0 
+411.0 
+— 
+48.1 
+342.0 
+— 
+47.1 
+433.2 
+— 
+End of year 
+50.3 
+451.2 
+15.2 
+46.0 
+411.0 
+— 
+48.1 
+342.0 
+— 
+Proved undeveloped reserves 
+Beginning of year 
+11.4 
+229.0 
+— 
+5.7 
+107.5 
+— 
+4.3 
+124.2 
+— 
+End of year 
+21.4 
+212.8 
+12.3 
+11.4 
+229.0 
+— 
+5.7 
+107.5 
+— 
+(1) 
+Please refer to Part I, Item 1 and 2 and Part II, Item 7 for current year reserve discussion. 
+(2) 
+For the year ended December 31, 2010 , of the 24.7 BCFE upward revision of previous estimate, 42.6 BCFE and (17.9) BCFE relate to price and performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2010, were $79.43 per Bbl and $4.38 per MMBtu for oil and natural gas, respectively. These prices were 30 percent and 13 percent higher, respectively, than the prices used in 2009. Performance revisions in 2010 resulted in a net 11.2 BCFE decrease in our estimate of proved reserves. While the Company recognized positive performance revisions in every region on proved developed properties, we had approximately 19.3 BCFE of negative performance revisions related to estimated proved undeveloped reserves in primarily dry gas assets, resulting from lower gas prices and higher well costs on the economics of these assets. The Company added 384.2 BCFE from its drilling program, included in discoveries and extensions and infill reserves, the majority which related to its activity in the Eagle Ford shale in South Texas. 
+(3) 
+For the year ended December 31, 2009 , of the 49.6 BCFE downward revision of previous estimate, 12.0 BCFE and (61.6) BCFE relate to price and performance revisions, respectively. The largest portion of the performance revision related to producing properties in the Company’s Wolfberry tight oil program in the Permian Basin in West Texas. Well performance data collected during 2009 at the Sweetie Peck and Halff East programs that target the Wolfberry interval indicated that these assets were underperforming for year-end 2008 decline forecasts. 
+(4) 
+The Company divested of certain non-core assets during 2011 , 2010 , and 2009 . Please refer to Note 3 - Divestitures and Assets Held for Sale for additional information. 
+(5) 
+For the years ended December 31, 2011 , 2010 , and 2009 , amounts included approximately 175 , 356 , and 370 MMcf respectively, representing the Company’s net underproduced gas balancing position. 
+Note: Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head. 
+129 
+Table of Contents 
+Beginning in the first quarter of 2011, we changed our reporting for natural gas volumes to separately show natural gas and NGL production volumes, revenues, and pricing consistent with title transfer for each product. Please refer to additional discussion above under the caption Oil, Gas, and NGL Prices . 
+Standardized Measure of Discounted Future Net Cash Flows 
+The Company computes a standardized measure of future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. Each property the Company operates is also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using the current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. 
+Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using year-end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by the central administrative office attributable to operating activities. 
+The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the standardized measure: 
+2011 
+2010 
+2009 
+Gas (per Mcf) 
+$ 
+4.72 
+$ 
+5.54 
+$ 
+3.82 
+Oil (per Bbl) 
+$ 
+88.00 
+$ 
+70.60 
+$ 
+53.94 
+NGLs (per Bbl) 
+$ 
+51.95 
+$ 
+— 
+$ 
+— 
+The following summary sets forth the Company’s future net cash flows relating to proved oil, gas, and NGL reserves based on the standardized measure. 
+As of December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+Future cash inflows 
+$ 
+10,871,281 
+$ 
+7,598,159 
+$ 
+4,620,735 
+Future production costs 
+(3,786,887 
+) 
+(2,512,091 
+) 
+(1,968,096 
+) 
+Future development costs 
+(1,036,352 
+) 
+(789,493 
+) 
+(387,722 
+) 
+Future income taxes 
+(1,740,394 
+) 
+(1,335,576 
+) 
+(515,953 
+) 
+Future net cash flows 
+4,307,648 
+2,960,999 
+1,748,964 
+10 percent annual discount 
+(1,727,608 
+) 
+(1,294,632 
+) 
+(732,997 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+2,580,040 
+$ 
+1,666,367 
+$ 
+1,015,967 
+130 
+Table of Contents 
+The principle sources of change in the standardized measure of discounted future net cash flows are: 
+For the Years Ended December 31, 
+2011 
+2010 
+2009 
+(in thousands) 
+Standardized measure, beginning of year 
+$ 
+1,666,367 
+$ 
+1,015,967 
+$ 
+1,059,069 
+Sales of oil, gas, and NGLs produced, net of production costs 
+(1,042,281 
+) 
+(641,213 
+) 
+(409,153 
+) 
+Net changes in prices and production costs 
+454,646 
+557,681 
+154,008 
+Extensions, discoveries and other including infill reserves in an existing proved field, net of production costs 
+1,816,640 
+989,365 
+166,666 
+Sales of reserves in place 
+(369,820 
+) 
+(151,315 
+) 
+(44,823 
+) 
+Purchase of reserves in place 
+— 
+804 
+- 
+Development costs incurred during the year 
+49,246 
+43,900 
+33,742 
+Changes in estimated future development costs 
+(31,410 
+) 
+49,531 
+75,134 
+Revisions of previous quantity estimates 
+32,992 
+66,759 
+(96,354 
+) 
+Accretion of discount 
+234,433 
+128,408 
+126,538 
+Net change in income taxes 
+(203,169 
+) 
+(409,848 
+) 
+(61,801 
+) 
+Changes in timing and other 
+(27,604 
+) 
+16,328 
+12,941 
+Standardized measure, end of year 
+$ 
+2,580,040 
+$ 
+1,666,367 
+$ 
+1,015,967 
+Quarterly Financial Information (unaudited) 
+The Company’s quarterly financial information for fiscal years 2011 and 2010 is as follows (in thousands, except per share amounts): 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+Year Ended December 31, 2011 
+Total operating revenues 
+$ 
+315,329 
+$ 
+377,873 
+$ 
+530,574 
+$ 
+379,542 
+Total operating expenses 
+335,301 
+166,166 
+157,786 
+559,681 
+Income (loss) from operations 
+$ 
+(19,972 
+) 
+$ 
+211,707 
+$ 
+372,788 
+$ 
+(180,139 
+) 
+Income (loss) before income taxes 
+$ 
+(29,558 
+) 
+$ 
+197,384 
+$ 
+363,443 
+$ 
+(192,268 
+) 
+Net income (loss) 
+$ 
+(18,503 
+) 
+$ 
+124,533 
+$ 
+230,097 
+$ 
+(120,711 
+) 
+Basic net income (loss) per common share 
+$ 
+(0.29 
+) 
+$ 
+1.96 
+$ 
+3.60 
+$ 
+(1.89 
+) 
+Diluted net income (loss) per common share 
+$ 
+(0.29 
+) 
+$ 
+1.86 
+$ 
+3.41 
+$ 
+(1.89 
+) 
+Dividends declared per common share 
+$ 
+0.05 
+$ 
+— 
+$ 
+0.05 
+$ 
+— 
+Year Ended December 31, 2010 
+Total operating revenues 
+$ 
+360,135 
+$ 
+211,697 
+$ 
+226,884 
+$ 
+294,118 
+Total operating expenses 
+152,384 
+174,908 
+195,832 
+230,939 
+Income from operations 
+$ 
+207,751 
+$ 
+36,789 
+$ 
+31,052 
+$ 
+63,179 
+Income before income taxes 
+$ 
+201,093 
+$ 
+30,500 
+$ 
+24,798 
+$ 
+58,505 
+Net income 
+$ 
+126,178 
+$ 
+18,068 
+$ 
+15,452 
+$ 
+37,139 
+Basic net income per common share 
+$ 
+2.01 
+$ 
+0.29 
+$ 
+0.25 
+$ 
+0.59 
+Diluted net income per common share 
+$ 
+1.96 
+$ 
+0.28 
+$ 
+0.24 
+$ 
+0.56 
+Dividends declared per common share 
+$ 
+0.05 
+$ 
+— 
+$ 
+0.05 
+$ 
+— 
+131 
+Table of Contents 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+None. 
+ITEM 9A. CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Controls and Procedures 
+We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. 
+Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) ("Disclosure Controls") will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant. 
+An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls 
+are effective at a reasonable assurance level. 
+Changes in Internal Control Over Financial Reporting 
+There have been no changes during the fourth quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+132 
+Table of Contents 
+Management's Report on Internal Control over Financial Reporting 
+Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that: 
+(i) 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+(ii) 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+(iii) 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements. 
+Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. 
+Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011 . In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. 
+Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2011 . 
+The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal controls over financial reporting. That report immediately follows this report. 
+133 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Board of Directors and Stockholders of 
+SM Energy Company and Subsidiaries 
+Denver, Colorado 
+We have audited the internal control over financial reporting of SM Energy Company and subsidiaries (the “Company”) as of December 31, 2011 , based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011 , based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2011 , of the Company and our report dated February 23, 2012 , expressed an unqualified opinion on those financial statements. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 23, 2012 
+134 
+Table of Contents 
+ITEM 9B. OTHER INFORMATION 
+None. 
+PART III 
+ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE 
+The information required by this Item concerning SM Energy’s Directors and corporate governance is incorporated by reference to the information provided under the captions Structure of the Board of Directors, Proposal 1 - Election of Directors, and Corporate Governance in SM Energy’s definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from December 31, 2011 . 
+The information required by this Item concerning compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated by reference to the information provided under the caption Section 16(a) Beneficial Ownership Reporting Compliance in SM Energy’s definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from December 31, 2011 . 
+EXECUTIVE OFFICERS OF THE REGISTRANT 
+The following table sets forth the names, ages and positions held by SM Energy’s executive officers. The ages of our executive officers are listed as of February 16, 2012. 
+Name 
+Age 
+Position 
+Anthony J. Best 
+62 
+Chief Executive Officer and President 
+Javan D. Ottoson 
+53 
+Executive Vice President and Chief Operating Officer 
+A. Wade Pursell 
+46 
+Executive Vice President and Chief Financial Officer 
+David W. Copeland 
+55 
+Senior Vice President, General Counsel and Corporate Secretary 
+Gregory T. Leyendecker 
+54 
+Senior Vice President and Regional Manager 
+Mark D. Mueller 
+47 
+Senior Vice President and Regional Manager 
+Lehman E. Newton, III 
+56 
+Senior Vice President and Regional Manager 
+Paul M. Veatch 
+45 
+Senior Vice President and Regional Manager 
+Mark T. Solomon 
+43 
+Vice President and Controller 
+Dennis A. Zubieta 
+45 
+Vice President – Engineering and Evaluation 
+Anthony J. Best. Mr. Best joined the Company in June 2006 as President and Chief Operating Officer. In December 2006, Mr. Best relinquished his position as Chief Operating Officer when Javan D. Ottoson was elected to that office. Mr. Best was elected Chief Executive Officer of the Company in February 2007. From November 2005 to June 2006, Mr. Best was developing a business plan and securing capital commitments for a new exploration and production entity. From 2003 to October 2005, Mr. Best was President and Chief Executive Officer of Pure Resources, Inc., an independent oil and natural gas exploration and production company that was a subsidiary of Unocal, where he managed all of Unocal’s onshore U.S. assets. From 2000 to 2002, Mr. Best had an oil and gas consulting practice, working with various energy firms. From 1979 to 2000, Mr. Best was with ARCO in a variety of positions, including serving as President - ARCO Latin America, President - ARCO Permian, Field Manager for Prudhoe Bay and VP - External Affairs for ARCO Alaska. Mr. Best has over 30 years of experience in the energy industry. 
+Javan D. Ottoson. Mr. Ottoson joined the Company in December 2006 as Executive Vice President and Chief Operating Officer. Mr. Ottoson has been in the energy industry for over 30 years. From April 2006 until he joined the Company in December 2006, Mr. Ottoson was Senior Vice President - Drilling and Engineering at Energy Partners, Ltd., an independent oil and natural gas exploration and production company, where his responsibilities included overseeing all aspects of its drilling and engineering functions. Mr. Ottoson managed 
+135 
+Table of Contents 
+Permian Basin assets for Pure Resources, Inc., a Unocal subsidiary, and its successor owner, Chevron, from July 2003 to April 2006. From April 2000 to July 2003, Mr. Ottoson owned and operated a homebuilding company in Colorado and ran his family farm. Prior to 2000 Mr. Ottoson worked for ARCO in a variety of management and operational roles, including serving as President of ARCO China, Commercial Director of ARCO United Kingdom, and Vice President of Operations and Development, ARCO Permian. 
+A. Wade Pursell. Mr. Pursell joined the Company in September 2008 as Executive Vice President and Chief Financial Officer. Mr. Pursell was Executive Vice President and Chief Financial Officer for Helix Energy Solutions Group, Inc., a global provider of life-of-field services and development solutions to offshore energy producers and an oil and gas producer, from February 2007 to September 2008. From October 2000 to February 2007, he was Senior Vice President and Chief Financial Officer of Helix. He joined Helix in May 1997, as Vice President—Finance and Chief Accounting Officer. From 1988 through May 1997, Mr. Pursell was with Arthur Andersen LLP, serving lastly as an Experienced Manager specializing in the offshore services industry. Mr. Pursell has over 24 years of experience in the energy industry. 
+David W. Copeland. Mr. Copeland joined the Company in January 2011 as Senior Vice President and General Counsel. He was appointed as the Company's Corporate Secretary in July 2011. Mr. Copeland has over 30 years of experience in the legal profession, including over 20 years as internal counsel for various energy companies. Prior to joining the Company, he co-founded Concho Resources Inc., in Midland, Texas, where he served as its Vice President, General Counsel and Secretary from April 2004 through November 2009, and then as its Senior Counsel through December 2010. From August 1997 through March 2004, Mr. Copeland served as an executive officer and general counsel of two other energy companies he co-founded with others in Midland, Texas. Mr. Copeland started his career in 1982 with the Stubbeman, McRae, Sealy, Laughlin & Browder law firm in Midland, Texas. 
+Gregory T. Leyendecker. Mr. Leyendecker was appointed Senior Vice President and Regional Manager in May 2010. From July 2007 to May 2010, he served as Vice President and Regional Manager. Mr. Leyendecker joined the Company in December 2006 as Operations Manager for the South Texas & Gulf Coast Region in Houston, Texas. Mr. Leyendecker has over 31 years in the energy industry, and held various positions with Unocal Corporation, an independent oil and natural gas exploration and production company, from 1980 until its acquisition in 2005. During his career with Unocal, he was the Asset Manager for Unocal Gulf Region USA from 2003 to June 2004 and Production and Reservoir Engineering Technology Manager for Unocal from June 2004 to August 2005. He was appointed Drilling and Workover Manager for the San Joaquin Valley business unit of Chevron, as successor-by-merger of Unocal Corporation, in Bakersfield, California in August 2005, and held this position until January 2006. Immediately prior to joining the Company, Mr. Leyendecker was Vice President of Drilling Management Services from February 2006 to November 2006 for Enventure Global Technology, a provider of solid expandable tubular technology. 
+Mark D. Mueller. Mr. Mueller joined the Company in September 2007 as Senior Vice President. Mr. Mueller was appointed as the Regional Manager of the Rocky Mountain Region effective January 1, 2008. Mr. Mueller has been in the energy industry for over 25 years. From September 2006 to September 2007, he was Vice President and General Manager at Samson Exploration Ltd., an oil and gas exploration and production company that was a subsidiary of Samson Investment Company, in Calgary, Canada, where his responsibilities included fiscal performance, reserves, and all operational functions of the company. From April 2005 until its sale in August 2006, Mr. Mueller was Vice President and General Manager for Samson Canada Ltd., an oil and gas exploration and production company that was a subsidiary of Samson Investment Company, where he was responsible for all business units and the eventual sale of the company. Mr. Mueller joined Samson Canada Ltd. as Project Manager in May 2003 to build a new basin-centered gas business unit and was Vice President from December 2003 to August 2006. Prior to joining Samson, Mr. Mueller was West Central Alberta Engineering Manager for Northrock Resources Ltd., a Canadian oil and gas company that was a wholly-owned subsidiary of Unocal Corporation, in Calgary, Canada. From 1986 to 2003, Mr. Mueller held positions of increasing responsibility in engineering and management for Unocal throughout North America and Southeast Asia. 
+Lehman E. Newton, III. Mr. Newton joined the Company in December 2006 as General Manager for the 
+136 
+Table of Contents 
+Midland, Texas office, was appointed Vice President and Regional Manager of the Permian region in June 2007, and was appointed Senior Vice President and Regional Manager in May 2010. Mr. Newton has over 33 years of experience in the energy industry. From November 2005 to November 2006, Mr. Newton served as Project Manager for one of Chevron’s largest Lower 48 projects. Mr. Newton joined Pure Resources in February 2003 as the Business Development Manager and worked in that capacity until October 2005. Mr. Newton was a founding partner in Westwin Energy, an independent Permian Basin exploration and production company, from June 2000 to January 2003. Prior to that, Mr. Newton spent 21 years with ARCO in various engineering, operations and management roles, including as Asset Manager, ARCO’s East Texas operations, Vice President, Business Development, ARCO Permian, and Vice President of Operations and Development, ARCO Permian. 
+Paul M. Veatch. Mr. Veatch is a Senior Vice President and Regional Manager of the Company. He manages our Mid-Continent Region. Mr. Veatch joined the Company in April 2001 as Regional A & D Engineer. He served as the Company’s Vice President - General Manager, ArkLaTex from August 2004 to March 2006, and Manager of Engineering for the ArkLaTex region from April 2003 to August 2004. Mr. Veatch has over 21 years of experience in the energy industry. 
+Mark T. Solomon. Mr. Solomon was appointed Vice President - Controller and Assistant Secretary of the Company in May 2011. He was appointed Controller of the Company in January 2007. Mr. Solomon served as the Company’s Acting Principal Financial Officer from April 2008, to September 2008, which was during the period of time that the Company’s Chief Financial Officer position was vacant. Mr. Solomon joined the Company in 1996. He served as Financial Reporting Manager from February 1999 to September 2002, Assistant Vice President - Financial Reporting from September 2002 to May 2006 and Assistant Vice President - Assistant Controller from May 2006 to January 2007. Prior to joining the Company, Mr. Solomon was an auditor with Ernst & Young. Mr. Solomon has over 15 years of experience in the energy industry. 
+Dennis A. Zubieta. Mr. Zubieta was appointed Vice President - Engineering and Evaluation of the Company in August 2008. Mr. Zubieta joined the Company in June 2000 as Corporate A&D Engineer, assumed the role of Reservoir Engineer in February 2003, and was appointed Reservoir Engineering Manager in August 2005. Mr. Zubieta was employed by Burlington Resources from June 1988 to May 2000 in various operations and reservoir engineering capacities. Mr. Zubieta has over 24 years of experience in the energy industry. 
+ITEM 11. EXECUTIVE COMPENSATION 
+The information required by this Item is incorporated by reference to the information provided under the captions, Executive Compensation and Director Compensation in SM Energy’s definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from December 31, 2011 . 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The information required by this Item concerning security ownership of certain beneficial owners and management is incorporated by reference to the information provided under the caption Security Ownership of Certain Beneficial Owners and Management in SM Energy’s definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from December 31, 2011 . 
+Securities Authorized for Issuance Under Equity Compensation Plans. SM Energy has the Equity Plan under which options and shares of SM Energy common stock are authorized for grant or issuance as compensation to eligible employees, consultants, and members of the Board of Directors. Our stockholders have approved this plan. See Note 7 – Compensation Plans included in Part II, Item 8 of this report for further information about the material terms of our equity compensation plans. The following table is a summary of the shares of common stock authorized for issuance under the equity compensation plans as of December 31, 2011: 
+137 
+Table of Contents 
+(a) 
+(b) 
+(c) 
+Plan category 
+Number of securities to be issued upon exercise of outstanding options, warrants, and rights 
+Weighted-average exercise price of outstanding options, warrants, and rights 
+Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) 
+Equity compensation plans approved by security holders: 
+Equity Incentive Compensation Plan 
+Stock options and incentive stock options (1) 
+508,214 
+$ 
+13.86 
+Restricted stock (1)(3) 
+308,877 
+N/A 
+Performance share units (1)(3)(4) 
+1,232,225 
+N/A 
+Total for Equity Incentive Compensation Plan 
+2,049,316 
+$ 
+13.86 
+2,708,822 
+Employee Stock Purchase Plan (2) 
+- 
+- 
+1,373,969 
+Equity compensation plans not approved by security holders 
+- 
+- 
+- 
+Total for all plans 
+2,049,316 
+$ 
+13.86 
+4,082,791 
+(1) 
+In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and members of the Board of Directors of SM Energy or any affiliate of SM Energy. The Equity Plan serves as the successor to the St. Mary Land & Exploration Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock Option Plan, the SM Energy Company Restricted Stock Plan, and the SM Energy Company Non-Employee Director Stock Compensation Plan (collectively referred to as the “Predecessor Plans”). All grants of equity are now made under the Equity Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under a Predecessor Plan immediately prior to the effective date of the Equity Plan continues to be governed solely by the terms and conditions of the instruments evidencing such grants or issuances. Our Board of Directors approved amendments to the Equity Plan in 2009 and 2010 and each amended plan was approved by stockholders at the respective annual stockholders' meetings. The awards granted in 2011, 2010, and 2009 under the Equity Plan were 386,802, 540,774, and 1,016,931, respectively. 
+(2) 
+Under the SM Energy Company ESPP, eligible employees may purchase shares of our common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the six-month offering period, and shares issued under the ESPP as of December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. Shares issued under the ESPP totaled 41,358, 52,948, and 86,308 in 2011, 2010, and 2009, respectively. 
+(3) 
+RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per share fair value which is presented in order to provide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per share fair value for the outstanding RSUs and PSUs was $44.33 and $52.38, respectively. Please refer to Note 7 - Compensation Plan for additional discussion. 
+(4) 
+The number of awards vested assumes a one multiplier. The final number of shares issued may vary depending on the ending three -year multiplier, which ranges from zero to two . 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+The information required by this Item is incorporated by reference to the information provided under the caption Certain Relationships and Related Transactions, and Corporate Governance, in SM Energy’s definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from December 31, 2011 . 
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+138 
+Table of Contents 
+The information required by this Item is incorporated by reference to the information provided under the caption Independent Registered Public Accounting Firm and Audit Committee Preapproval Policy and Procedures in SM Energy’s definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from December 31, 2011 . 
+139 
+Table of Contents 
+PART IV 
+ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
+(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules: 
+Report of Independent Registered Public Accounting Firm 
+86 
+Consolidated Balance Sheets 
+87 
+Consolidated Statements of Operations 
+88 
+Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss ) 
+89 
+Consolidated Statements of Cash Flows 
+90 
+Notes to Consolidated Financial Statements 
+92 
+All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto. 
+(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K: 
+Exhibit 
+Number 
+Description 
+2.1 
+Purchase and Sale Agreement dated December 17, 2009 and effective as of November 1, 2009, between Legacy Reserves Operating LP and St. Mary Land & Exploration Company (filed as Exhibit 2.5 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference) 
+2.2 
+Purchase and Sale Agreement dated January 7, 2010 and effective as of November 1, 2009, between Sequel Energy Partners LP, Bakken Energy Partners, LLC, Three Forks Energy Partners, LLC and St. Mary Land & Exploration Company (filed as Exhibit 2.6 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference) 
+2.3 
+Purchase and Sale Agreement dated June 9, 2011, among SM Energy Company, Statoil Texas Onshore Properties LLC, and Tailsman Energy USA Inc. (filed as Exhibit 2.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 and incorporated herein by reference) 
+2.4 
+Acquisition and Development Agreement dated June 29, 2011 between SM Energy Company and Mitsui E&P Texas LP (filed as Exhibit 2.2 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 and incorporated herein by reference) 
+2.5 
+First Amendment to Acquisition and Development Agreement dated October 13, 2011 between SM Energy Company and Mitsui E&P Texas (filed as Exhibit 2.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 and incorporated herein by reference) 
+3.1 
+Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+3.2 
+Restated By-Laws of SM Energy Company amended effective as of June 1, 2010 (filed as Exhibit 3.2 to the registrant’s Current Report on Form 8-K filed on June 2, 2010, and incorporated herein by reference) 
+4.1 
+Indenture related to the 3.50% Senior Convertible Notes due 2027, dated as of April 4, 2007, between St. Mary Land & Exploration Company and Wells Fargo Bank, National Association, as trustee (including the form of 3.50% Senior Convertible Note due 2027) (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on April 4, 2007 and incorporated herein by reference) 
+140 
+Table of Contents 
+4.2 
+Registration Rights Agreement, dated as of April 4, 2007, among St. Mary Land & Exploration Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wachovia Capital Markets, LLC, for themselves and as representatives of the Initial Purchasers (filed Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on April 4, 2007, and incorporated herein by reference) 
+4.3 
+Indenture related to the 6.625% Senior Notes due 2019, dated as of February 7, 2011, by and between SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on February 10, 2011, and incorporated herein by reference) 
+4.4 
+Registration Rights Agreement, dated as of February 7, 2011, by and among SM Energy Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as representatives of the several initial purchasers (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on February 10, 2011, and incorporated herein by reference) 
+4.5 
+Indenture related to the 6.50% Senior Notes due 2021, dated as of November 8, 2011, by and among SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant's Current Report on Form 8-K filed on November 10, 2011, and incorporated herein by reference) 
+4.6 
+Registration Rights Agreement, dated as of November 8, 2011, by and among SM Energy Company and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as representatives of several purchasers (filed as Exhibit 4.2 to the registrant's Current Report on Form 8-K filed on November 10, 2011, and incorporated herein by reference) 
+10.1† 
+Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference) 
+10.2† 
+Incentive Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.2 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference) 
+10.3† 
+Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001 and incorporated herein by reference) 
+10.4† 
+Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.9 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein by reference) 
+10.5† 
+Employment Agreement of A.J. Best dated May 1, 2006 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 4, 2006 and incorporated herein by reference) 
+10.6† 
+Form of Performance Share Award Agreement (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q filed on August 5, 2008 and incorporated herein by reference) 
+10.7† 
+Form of Performance Share Award Notice (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q filed on August 5, 2008 and incorporated herein by reference) 
+10.8 
+Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement for the benefit of Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference) 
+10.9 
+Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference) 
+10.10† 
+Equity Incentive Compensation Plan as Amended and Restated as of March 26, 2009 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 27, 2009, and incorporated herein by reference) 
+10.11† 
+Equity Incentive Compensation Plan As Amended and Restated as of April 1, 2010 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on June 2, 2010, and incorporated herein by reference) 
+141 
+Table of Contents 
+10.12 s 
+SM Energy Company Equity Incentive Compensation Plan, As Amended as of July 30, 2010 (filed as Exhibit 10.7 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.13† 
+Form of Performance Share and Restricted Stock Unit Award Agreement (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, and incorporated herein by reference) 
+10.14† 
+Form of Performance Share and Restricted Stock Unit Award Notice (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, and incorporated herein by reference) 
+10.15† 
+Third Amendment to Employee Stock Purchase Plan dated September 23, 2009 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, and incorporated herein by reference) 
+10.16† 
+Fourth Amendment to Employee Stock Purchase Plan dated December 29, 2009 (filed as Exhibit 10.46 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein by reference) 
+10.17 s 
+Employee Stock Purchase Plan, As Amended and Restated as of July 30, 2010 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.18 
+Carry and Earning Agreement between St. Mary Land & Exploration Company and Encana Oil & Gas (USA) Inc. executed as of April 29, 2010 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.19† 
+Form of Performance Share and Restricted Stock Unit Award Agreement as of July 1, 2010 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.20† 
+Form of Performance Share and Restricted Stock Unit Award Notice as of July 1, 2010 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.21† 
+Form of Non-Employee Director Restricted Stock Award Agreement as of May 27, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.22*** 
+Gas Services Agreement effective as of July 1, 2010 between SM Energy Company and Eagle Ford Gathering LLC (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.23 s 
+Cash Bonus Plan, As Amended on July 30, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.24 s 
+Net Profits Interest Bonus Plan, As Amended by the Board of Directors on July 30, 2010 (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.25 s 
+SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan, As Amended as of July 30, 2010 (filed as Exhibit 10.8 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.26† 
+Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on December 29, 2010, and incorporated herein by reference) 
+10.27† 
+Amendment to A.J. Best Employment Agreement dated December 31, 2010 (filed as Exhibit 10.28 to the registrant's Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference) 
+10.28 
+Purchase Agreement, dated January 31, 2011, among SM Energy Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as representatives of the Initial Purchasers named therein (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on February 1, 2011, and incorporated herein by reference) 
+10.29 
+Pension Plan for Employees of SM Energy Company as Amended and Restated as of January 1, 2010 (filed as Exhibit 10.30 to the registrant's Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference) 
+142 
+Table of Contents 
+10.30+ 
+SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan as Amended as of November 9, 2010 (filed as Exhibit 10.31 to the registrant's Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference) 
+10.31*† 
+Summary of Compensation Arrangements for Non-Employee Directors 
+10.32 
+Fourth Amended and Restated Credit Agreement dated May 27, 2011 among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.33 
+Gas Gathering Agreement dated May 31, 2011 between Regency Field Services LLC and SM Energy Company (filed as Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.34 
+Gathering and Natural Gas Services Agreement effective as of April 1, 2011 between SM Energy Company and ETC Texas Pipeline, Ltd. (filed as Exhibit 10.3 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.35 
+Gas Processing Agreement effective as of April 1, 2011 between ETC Texas Pipeline, Ltd. and SM Energy Company (filed as Exhibit 10.4 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.36† 
+Employee Stock Purchase Plan, As Amended and Restated as of June 10, 2011 (filed as Exhibit 10.5 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.37† 
+Form of Performance Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.6 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.38† 
+Form of Restricted Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.7 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.39† 
+Form of Performance Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference) 
+10.40† 
+Form of Restricted Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference) 
+10.41* 
+Amendment No. 1 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2011 
+10.42* 
+Amendment No. 2 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2012 
+12.1* 
+Computation of Ratio of Earnings to Fixed Charges 
+21.1* 
+Subsidiaries of Registrant 
+23.1* 
+Consent of Deloitte & Touche LLP 
+23.2* 
+Consent of Ryder Scott Company L.P. 
+24.1* 
+Power of Attorney 
+31.1* 
+Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002 
+31.2* 
+Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002 
+32.1** 
+Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002 
+99.1* 
+Ryder Scott Audit Letter 
+101.INS**** 
+XBRL Instance Document 
+101.SCH**** 
+XBRL Schema Document 
+101.CAL**** 
+XBRL Calculation Linkbase Document 
+101.LAB**** 
+XBRL Label Linkbase Document 
+143 
+Table of Contents 
+101.PRE**** 
+XBRL Presentation Linkbase Document 
+101.DEF**** 
+XBRL Taxonomy Extension Definition Linkbase Document 
+* Filed with this Form 10-K 
+** Furnished with this Form 10-K 
+*** 
+Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934. 
+**** 
+Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections. 
+† 
+Exhibit constitutes a management contract or compensatory plan or agreement. 
+s 
+Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the recent change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the substantive terms and conditions in this document. 
++ 
+Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal Revenue Code. There were no material changes to the substantive terms and conditions in this document. 
+(c) Financial Statement Schedules. See Item 15(a) above. 
+144 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+SM ENERGY COMPANY 
+(Registrant) 
+Date: February 23, 2012 
+By: 
+/s/ ANTHONY J. BEST 
+Anthony J. Best 
+President and Chief Executive Officer 
+GENERAL POWER OF ATTORNEY 
+KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints each of Anthony J. Best and A. Wade Pursell his or her true and lawful attorney-in-fact and agent with full power of substitution and resubstitution, and each with full power to act alone, for the undersigned and in his or her name, place and stead, in any and all capacities, to sign any amendments to this Annual Report on Form 10-K for the fiscal year ended December 31, 2011 , and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorney-in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof. 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signature 
+Title 
+Date 
+/s/ ANTHONY J. BEST 
+President and Chief Executive Officer 
+February 23, 2012 
+Anthony J. Best 
+/s/ A. WADE PURSELL 
+Executive Vice President and Chief Financial Officer 
+February 23, 2012 
+A. Wade Pursell 
+/s/ MARK T. SOLOMON 
+Vice President and Controller 
+February 23, 2012 
+Mark T. Solomon 
+145 
+Table of Contents 
+Signature 
+Title 
+Date 
+/s/ WILLIAM D. SULLIVAN 
+Chairman of the Board of Directors 
+February 23, 2012 
+William D. Sullivan 
+/s/ BARBARA M. BAUMANN 
+Director 
+February 23, 2012 
+Barbara M. Baumann 
+/s/ LARRY W. BICKLE 
+Director 
+February 23, 2012 
+Larry W. Bickle 
+/s/ STEPHEN R. BRAND 
+Director 
+February 23, 2012 
+Stephen R. Brand 
+/s/ WILLIAM J. GARDINER 
+Director 
+February 23, 2012 
+William J. Gardiner 
+/s/ JULIO M. QUINTANA 
+Director 
+February 23, 2012 
+Julio M. Quintana 
+/s/ JOHN M. SEIDL 
+Director 
+February 23, 2012 
+John M. Seidl 
+146
\ No newline at end of file
diff --git a/raw/filings/0000893538/2011/0000893538-12-000012/filing_metadata.csv b/raw/filings/0000893538/2011/0000893538-12-000012/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..2767a5d6e8e6657ac664597f86e0e981fcefce5f
--- /dev/null
+++ b/raw/filings/0000893538/2011/0000893538-12-000012/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000893538,SM,SM Energy Co,10-K,2012-02-23,2011-12-31,2012-02-23T14:07:08.000Z,0000893538-12-000012,sm-20111231x10k.htm,FORM 10-K,17262276,1,0,https://www.sec.gov/Archives/edgar/data/893538/000089353812000012/sm-20111231x10k.htm,https://www.sec.gov/Archives/edgar/data/893538/000089353812000012/,2011,2011,1
diff --git a/raw/filings/0000893538/2011/0000893538-12-000012/item1.txt b/raw/filings/0000893538/2011/0000893538-12-000012/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2011/0000893538-12-000012/item13.txt b/raw/filings/0000893538/2011/0000893538-12-000012/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..58380044f5793e7a13957595bdce0512755d9c63
--- /dev/null
+++ b/raw/filings/0000893538/2011/0000893538-12-000012/item13.txt
@@ -0,0 +1,3 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+The information required by this Item is incorporated by reference to the information provided under the caption Certain Relationships and Related Transactions, and Corporate Governance, in SM Energy’s definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from December 31, 2011 .
\ No newline at end of file
diff --git a/raw/filings/0000893538/2011/0000893538-12-000012/item9a.txt b/raw/filings/0000893538/2011/0000893538-12-000012/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..6183a449ad106afadbfd072e50e76089a805887b
--- /dev/null
+++ b/raw/filings/0000893538/2011/0000893538-12-000012/item9a.txt
@@ -0,0 +1,39 @@
+ITEM 9A. CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Controls and Procedures 
+We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. 
+Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) ("Disclosure Controls") will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant. 
+An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls 
+are effective at a reasonable assurance level. 
+Changes in Internal Control Over Financial Reporting 
+There have been no changes during the fourth quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+132 
+Table of Contents 
+Management's Report on Internal Control over Financial Reporting 
+Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that: 
+(i) 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+(ii) 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+(iii) 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements. 
+Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. 
+Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011 . In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. 
+Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2011 . 
+The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal controls over financial reporting. That report immediately follows this report. 
+133 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Board of Directors and Stockholders of 
+SM Energy Company and Subsidiaries 
+Denver, Colorado 
+We have audited the internal control over financial reporting of SM Energy Company and subsidiaries (the “Company”) as of December 31, 2011 , based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011 , based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2011 , of the Company and our report dated February 23, 2012 , expressed an unqualified opinion on those financial statements. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 23, 2012 
+134 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000893538/2011/0000893538-12-000012/rp_note.txt b/raw/filings/0000893538/2011/0000893538-12-000012/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2011/0000893538-12-000012/rpt_disclosure.txt b/raw/filings/0000893538/2011/0000893538-12-000012/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..a8771ab3e70e5213a01053593154ea2c932d786f
--- /dev/null
+++ b/raw/filings/0000893538/2011/0000893538-12-000012/rpt_disclosure.txt
@@ -0,0 +1,41 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+Policies and Procedures on Transactions with Related Persons 
+We have adopted a Policy and Procedures with Respect to Related Person Transactions (the "Related Person Transactions Policy"), which
+sets forth the policies and procedures for the Audit Committee's review of any transaction, arrangement, or relationship (including any indebtedness or guarantee of indebtedness) or series of similar
+transactions, arrangements, or relationships in which (a) we are a participant, (b) the aggregate amount involved will or may be expected to exceed $120,000 per annum, and (c) a
+related person has or will have a direct or indirect material interest. For purposes of our Related Person Transactions Policy, a "related person" means (i) any of our directors, executive
+officers, or nominees for director, (ii) any stockholder that beneficially owns more than 5% of our outstanding shares of common stock, and (iii) any immediate family member of any of
+the foregoing. The Audit Committee approves or ratifies only those transactions that it determines in good faith are in, or are not inconsistent with, our best interests and the best interests of our
+stockholders. 
+In
+determining whether to approve or ratify a transaction with a related person, the Audit Committee takes into account the factors it deems appropriate, which may include, among others,
+the benefits to us, the availability of other sources for comparable products or services, the impact on a director's independence in the event the related person is a director, and the extent of the
+related person's interest in the transaction. The policy also provides for the delegation of Audit Committee authority to the Chair of the Audit Committee for any related person transaction requiring
+pre-approval or ratification between meetings of the Audit Committee. The Audit Committee reviews and assesses ongoing relationships with a related person on at least an annual basis to
+ensure that they are in compliance with the policy and remain appropriate. 
+In
+addition, our By-Laws provide that a director, officer, or employee of our company may not pursue for his or her own account a business or investment opportunity that he
+or she learned about 
+11 
+Table of Contents 
+through
+his or her affiliation with us. These restrictions do not apply to the acquisition of less than 1% of the publicly traded stock of another company. 
+Related Person Transactions 
+We recognize that transactions with related persons may raise questions among stockholders regarding whether those transactions are
+consistent with our best interests and the best interests of our stockholders. It is our policy to enter into or ratify such transactions only when the Board, acting through the Audit Committee or as
+otherwise described herein, determines that the transaction in question is in, or is not inconsistent with, our best interests and the best interests of our stockholders. Such transactions include,
+but are not limited to, situations where we may obtain products or services of a nature, quantity or quality, or on other terms, that are not readily available from alternate sources, or when we
+obtain products or services from, or provide products or services to, related persons on an arm's length basis on terms comparable to those obtained from or provided to unrelated third parties or on
+terms comparable to those obtained from or provided to employees generally. The only transaction between our company and a related person since January 1, 2012, is our relationship with Tesco,
+which was referenced above. Mr. Quintana is the President, Chief Executive Officer, and a director of Tesco, which designs, manufactures, and delivers technology based solutions for the
+upstream energy industry, including oilfield drilling and completion technology, services, and equipment. We have an agreement with Tesco for its provision of equipment and services to us in
+connection with our drilling and completion operations. This agreement continues until canceled by either us or Tesco on 30 days advance written notice. Pursuant to this agreement, we are
+obligated to pay Tesco only for services actually performed or equipment provided, as the case may be, as requested by us from time to time. This agreement does not require us to make any other
+payments to Tesco, nor does it obligate us to use Tesco for any services or equipment. Mr. Quintana does not have any direct or indirect interest in the transaction, other than as a result of
+serving as an executive officer and director of Tesco. Mr. Quintana had no input in our selection of Tesco for equipment and services or the terms of our agreement with Tesco. Decisions to use
+Tesco are made by technical professionals supervising the relevant regional activity, based on their assessment of Tesco's equipment and services and related costs in comparison to other providers. In
+2012, we paid Tesco $600,265. The amount we paid Tesco during 2012 for equipment and services represented approximately 6% of the total amount paid by us to all service providers (including Tesco) for
+similar equipment and services during 2012. As of March 31, 2013, we had paid Tesco $350,517 for equipment and services rendered during 2013. In accordance with our Related Person Transactions
+Policy, the Audit Committee reviewed the relationship between us and Tesco and determined that the relationship is in our best interests and the best interests of our stockholders. 
+12 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000893538/2012/0000893538-13-000011/filing.txt b/raw/filings/0000893538/2012/0000893538-13-000011/filing.txt
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--- /dev/null
+++ b/raw/filings/0000893538/2012/0000893538-13-000011/filing.txt
@@ -0,0 +1,8159 @@
+10-K
+1
+sm-20121231x10k.htm
+FORM 10-K
+SM-2012.12.31-10K 
+Table of Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+þ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 
+For the fiscal year ended December 31, 2012 
+or 
+o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 
+Commission file number 001-31539 
+SM ENERGY COMPANY 
+(Exact name of registrant as specified in its charter) 
+Delaware 
+(State or other jurisdiction 
+of incorporation or organization) 
+41-0518430 
+(I.R.S. Employer Identification No.) 
+1775 Sherman Street, Suite 1200, Denver, Colorado 
+(Address of principal executive offices) 
+80203 
+(Zip Code) 
+(303) 861-8140 
+(Registrant’s telephone number, including area code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+Common stock, $.01 par value 
+New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer þ 
+Accelerated filer o 
+Non-accelerated filer o (Do not check if a smaller reporting company) 
+Smaller reporting company o 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ 
+The aggregate market value of the 64,586,179 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant's common stock on June 29, 2012 , the last business day of the registrant’s most recently completed second fiscal quarter, of $49.11 per share, as reported on the New York Stock Exchange; was $3,171,827,251 . Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes. 
+As of February 14, 2013 , the registrant had 66,205,901 shares of common stock outstanding, which is net of 50,581 treasury shares held by the registrant. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its 2013 annual meeting of stockholders to be filed within 120 days after December 31, 2012 . 
+1 
+Table of Contents 
+TABLE OF CONTENTS 
+ITEM 
+PAGE 
+PART I 
+ITEMS 1. and 2. 
+BUSINESS and PROPERTIES 
+4 
+General 
+4 
+Strategy 
+4 
+Significant Developments in 2012 
+4 
+Outlook for 2013 
+5 
+Core Operational Areas 
+6 
+Reserves 
+8 
+Production 
+12 
+Productive Wells 
+13 
+Drilling Activity 
+13 
+Acreage 
+14 
+Delivery Commitments 
+15 
+Major Customers 
+15 
+Employees and Office Space 
+15 
+Title to Properties 
+15 
+Seasonality 
+15 
+Competition 
+16 
+Government Regulations 
+16 
+Cautionary Information about Forward-Looking Statements 
+20 
+Available Information 
+22 
+Glossary of Oil and Gas Terms 
+23 
+ITEM 1A. 
+RISK FACTORS 
+28 
+ITEM 1B. 
+UNRESOLVED STAFF COMMENTS 
+49 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+49 
+ITEM 4. 
+MINE SAFETY DISCLOSURES 
+50 
+PART II 
+51 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, 
+RELATED STOCKHOLDER MATTERS AND ISSUER 
+PURCHASES OF EQUITY SECURITIES 
+51 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+53 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF 
+FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+55 
+Overview of the Company 
+55 
+Financial Results of Operations and Additional Comparative Data 
+63 
+Comparison of Financial Results and Trends between 2012 and 2011 
+67 
+Comparison of Financial Results between 2011 and 2010 
+70 
+Overview of Liquidity and Capital Resources 
+73 
+Critical Accounting Policies and Estimates 
+83 
+Accounting Matters 
+86 
+Environmental 
+86 
+Non-GAAP Financial Measures 
+87 
+2 
+Table of Contents 
+TABLE OF CONTENTS 
+(Continued) 
+ITEM 
+PAGE 
+ITEM 7A. 
+QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT 
+MARKET RISK (included within the content of ITEM 7) 
+88 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+89 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS 
+ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+141 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+141 
+ITEM 9B. 
+OTHER INFORMATION 
+144 
+PART III 
+144 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE 
+GOVERNANCE 
+144 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+147 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL 
+OWNERS AND MANAGEMENT AND RELATED 
+STOCKHOLDER MATTERS 
+147 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, 
+AND DIRECTOR INDEPENDENCE 
+149 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+149 
+PART IV 
+150 
+ITEM 15. 
+EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
+150 
+3 
+Table of Contents 
+PART I 
+When we use the terms “SM Energy,” “the Company,” “we,” “us,” or “our,” we are referring to SM Energy Company and its subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business under Glossary of Oil and Gas Terms. Throughout this document we make statements that may be classified as “forward-looking.” Please refer to the Cautionary Information about Forward-Looking Statements section of this document for an explanation of these types of statements. 
+ITEMS 1. and 2. BUSINESS and PROPERTIES 
+General 
+We are an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout the document) in onshore North America, with a current focus on oil and liquids-rich resource plays. We were founded in 1908 and incorporated in Delaware in 1915. Our initial public offering of common stock was in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.” 
+Our principal offices are located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is (303) 861-8140. 
+Strategy 
+Our business strategy is to focus on the early capture of resource plays in order to create and then enhance value for our shareholders, while maintaining a strong balance sheet. We strive to leverage industry-leading acquisition, exploration, and operations teams to quickly acquire and test new resource play concepts at a reasonable cost. Once we have identified potential value through these efforts, our goal is to develop such potential through top-tier operational and project execution, and as appropriate, mitigate our risks by selectively divesting certain assets. We continually examine our portfolio for opportunities to improve the quality of our asset base in order to optimize our returns and preserve our financial strength. 
+Significant Developments in 2012 
+• 
+Resource Play Delineation and Development Results in Record Production and Increase in Year-End Proved Reserve Estimates. Our estimated proved reserves increased 40 percent to 1,760.6 BCFE ( 293.4 MMBOE) at December 31, 2012 , from 1,259.2 BCFE ( 209.9 MMBOE) at December 31, 2011 . We added 900.2 BCFE through drilling activity during the year, which was primarily led by our efforts in the Eagle Ford shale in South Texas and the Bakken/Three Forks plays in North Dakota. We achieved record levels of production in 2012 . Our average daily production was composed of 28.3 MBbl of oil, 328.0 MMcf of gas, and 16.7 MBbl of NGLs for an average equivalent production rate of 598.2 MMCFE per day, which was an increase of 29 percent from 465.0 MMCFE per day in 2011 . Costs incurred in 2012 for drilling and exploration activities and acquisitions increased nine percent , to $1.7 billion , compared with $1.6 billion in 2011 due mainly to increased activity in plays with significant oil and NGL-rich gas components, such as our Eagle Ford shale and Bakken/Three Forks programs. Please refer to Core Operational Areas below for additional discussion concerning our 2012 estimated proved reserves, production, and capital investment. 
+4 
+Table of Contents 
+• 
+Impairments. We recorded impairment of proved properties expense of $208.9 million for the year ended December 31, 2012 . During the fourth quarter of 2012, we recorded proved property impairment expense of $170.4 million . This non-cash charge was driven by downward engineering revisions that resulted in the write-down of Wolfberry assets in our Permian region. We also recorded proved property impairment expense of $38.5 million in the second quarter of 2012 related to our Haynesville shale assets in our Mid-Continent region due to low natural gas prices. 
+• 
+Volatility and Decline in Commodity Prices. Our financial condition and the results of our operations are significantly affected by the prices we receive for oil, natural gas, and NGLs, which can fluctuate dramatically. Oil prices were volatile throughout 2012 , reaching their peak for the year in February when the spot price for NYMEX crude oil hit a high of $109.49 per Bbl. The spot price for NYMEX crude oil during 2012 was at its lowest of $77.69 per Bbl in June. The average spot price for oil during 2012 was $94.10 per Bbl, down slightly from the $95.05 per Bbl average NYMEX price in 2011 . In 2012 , oil prices were impacted by concerns over international supply disruptions, rising U.S. oil production, and changes in global economic growth expectations throughout the year. 
+Natural gas prices were also volatile in 2012 . The spot price for natural gas at Henry Hub in Erath, Louisiana, a widely-used industry measuring point, averaged $2.75 per MMBtu in 2012 , down from an average price of $4.00 per MMBtu in 2011 . The 2012 average price was the lowest average annual price at Henry Hub since 1999. The high at Henry Hub for 2012 of $3.77 per MMBtu was recorded in November, and the low of $1.84 per MMBtu was reached in April. Natural gas prices were under downward pressure in 2012 as a result of sustained high natural gas inventories and rising natural gas production in the Marcellus and Eagle Ford basins. Natural gas prices rose throughout the remainder of the year after reaching their low in April. 
+NGL prices decreased throughout 2012 largely due to a growing supply of NGLs as increased numbers of industry participants targeted projects producing NGLs. The average spot price for NGLs in 2012 at Mont Belvieu was $44.91 per Bbl, which was down from $59.47 per Bbl in 2011 . Please refer to Overview of the Company and Oil, Gas, and NGL Prices included in Part II, Item 7 of this report for additional information regarding our NGL prices . 
+Outlook for 2013 
+We enter 2013 with a projected $1.5 billion capital program, approximately $1.2 billion of which we expect to allocate to drilling and completion activities. Our 2013 capital program allocates all drilling and completion capital to oil and liquids-rich programs. Please refer to Core Operational Areas below and Outlook for 2013 under Part II, Item 7 of this report for additional discussion surrounding our capital plans for 2013 . 
+5 
+Table of Contents 
+Core Operational Areas 
+Our operations are concentrated in four core operating areas in the onshore United States. Effective January 1, 2012, we combined our former ArkLaTex region with our Mid-Continent region, based in Tulsa, Oklahoma, for operational and reporting purposes. The following table summarizes estimated proved reserves, PV-10 reserve value, and production for the year ended December 31, 2012 , for our core operating areas: 
+South Texas & Gulf Coast 
+Rocky 
+Mountain 
+Mid- 
+Continent 
+Permian 
+Total (1) 
+Proved Reserves 
+Oil (MMBbl) 
+30.9 
+49.2 
+0.9 
+11.2 
+92.2 
+Gas (Bcf) 
+530.7 
+42.7 
+233.4 
+26.6 
+833.4 
+NGLs (MMBbl) 
+60.5 
+— 
+1.6 
+0.2 
+62.3 
+BCFE (1) 
+1,079.2 
+337.9 
+248.6 
+94.8 
+1,760.6 
+Relative percentage 
+61 
+% 
+19 
+% 
+14 
+% 
+6 
+% 
+100 
+% 
+Proved Developed % 
+43 
+% 
+65 
+% 
+89 
+% 
+93 
+% 
+57 
+% 
+PV-10 Values (in millions) (2) 
+Proved Developed 
+$ 
+1,308.7 
+$ 
+974.4 
+$ 
+295.9 
+$ 
+403.6 
+$ 
+2,982.6 
+Proved Undeveloped 
+591.5 
+248.5 
+4.8 
+21.7 
+866.5 
+Total Proved 
+$ 
+1,900.2 
+$ 
+1,222.9 
+$ 
+300.7 
+$ 
+425.3 
+$ 
+3,849.1 
+Relative percentage 
+49 
+% 
+32 
+% 
+8 
+% 
+11 
+% 
+100 
+% 
+Production 
+Oil (MMBbl) 
+3.2 
+5.4 
+0.4 
+1.3 
+10.4 
+Gas (Bcf) 
+59.1 
+4.4 
+53.4 
+3.2 
+120.0 
+NGLs (MMBbl) 
+5.7 
+— 
+0.4 
+— 
+6.1 
+BCFE (1) 
+112.7 
+36.9 
+58.1 
+11.3 
+218.9 
+Avg. Daily Equivalents 
+(MMCFE/d) 
+307.9 
+100.9 
+158.6 
+30.8 
+598.2 
+Relative percentage 
+51 
+% 
+17 
+% 
+27 
+% 
+5 
+% 
+100 
+% 
+(1) 
+Totals may not sum or recalculate due to rounding. 
+(2) 
+The standardized measure PV-10 calculation is presented in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown in the Reserves section below. 
+South Texas & Gulf Coast Region. Operations in our South Texas & Gulf Coast region are managed from our office in Houston, Texas. Our current operations in this region focus primarily on our Eagle Ford shale program. Our acreage position covers a significant portion of the western Eagle Ford shale play, including acreage in the oil, NGL-rich gas, and dry gas windows of the play. As of December 31, 2012 , we had roughly 191,500 net acres in the play. We operate approximately 145,000 of the 191,500 net acres, with an average working interest of nearly 100 percent. 
+Nearly all of our capital deployed in the South Texas & Gulf Coast region in 2012 targeted our operated Eagle Ford shale program. Production in 2012 increased 62 percent from the 69.7 BCFE produced in 2011 . Estimated proved reserves at year-end 2012 increased 123 percent from 483.6 BCFE at year-end 2011 . Of the 2012 reserve additions in this region, approximately 767.3 BCFE of estimated proved reserves were added through drilling activities. The increase in production and proved reserves reflects the success we are having in our Eagle Ford shale program and the resulting consistent pace of investment. Our capital expenditures in our South Texas & Gulf Coast region decreased from $932.3 million in 2011 to $848.4 million in 2012 , as a result of being carried for substantially all of our drilling and completion costs in our outside operated Eagle Ford program pursuant to our Acquisition and Development Agreement with Mitsui E&P Texas LP (“Mitsui”), an indirect subsidiary of Mitsui & Co., Ltd. (the “Acquisition and Development Agreement”). 
+6 
+Table of Contents 
+Rocky Mountain Region. Operations in our Rocky Mountain region are managed from our office in Billings, Montana. Our capital expenditures in 2012 primarily targeted the Bakken/Three Forks formations in the North Dakota portion of the Williston Basin, where we have approximately 80,500 net acres. In 2012 , we continued to focus our drilling and completion activities in three main areas. In our Raven and Bear Den prospects, in Williams and McKenzie Counties, North Dakota, we have largely completed our drilling program intended to establish held by production status and have transitioned our program primarily to infill drilling. Our efforts are focused on optimizing our completions and spacing for development of the Bakken formation. In our Gooseneck prospect in Divide County, North Dakota, our efforts focused on the Three Forks formation, where we are also transitioning to infill drilling. As our program moves to infill development, we will continue our transition to multi-well pad drilling to improve the efficiency of our drilling and completion operations. Elsewhere in our Rocky Mountain region, we are in the exploratory phase of drilling test wells of various formations in the Powder River Basin. At year-end 2012 , we had approximately 65,000 net acres in the Powder River Basin that we believe to be prospective in various target horizons. 
+Capital expenditures in our Rocky Mountain region increased from $288.0 million in 2011 to $406.8 million in 2012 , as we increased activity in our Bakken/Three Forks program. Estimated proved reserves for the region at the end of 2012 increased 11 percent from 303.4 BCFE at year-end 2011 . During the year, we added approximately 90.0 BCFE of proved reserves in this region through drilling activities. Total regional production for 2012 was up 38 percent from the 26.7 BCFE produced in 2011. The increase in capital, production, and proved reserves reflects the increased activity in our Bakken/Three Forks program. 
+Mid-Continent Region. Operations in our Mid-Continent region are managed from our office in Tulsa, Oklahoma. Our current operations in the Mid-Continent region are primarily focused on the horizontal development of the Granite Wash formation in western Oklahoma. Our Mid-Continent region also manages our Haynesville and Woodford shale assets, on which we minimized activity in 2012 due to the low natural gas price environment, which resulted in a decrease in our 2012 capital expenditures, production, and year-end reserves, as discussed below. Our 2012 Granite Wash program targeted the shallower, liquids-rich washes of our approximately 34,000 net acres in the play, substantially all of which are held by production. 
+In 2012 , we incurred costs of $168.2 million in our Mid-Continent region for exploration, development, and acquisition activities, compared to $247.0 million incurred in 2011 . In 2012 , our Mid-Continent region’s production was 58.1 BCFE, a decrease from the 61.8 BCFE produced in 2011 . Estimated proved reserves at the end of 2012 decreased 32 percent from 365.2 BCFE as of the end of 2011 . 
+Permian Region. Operations in our Permian region are managed from our office in Midland, Texas. Our Permian region covers western Texas and eastern New Mexico. Our primary area of focus in this region is the delineation of our Mississippian limestone play, in which we hold approximately 65,500 net acres. In addition to this delineation program, we have an exploration program targeting various shale intervals in the Midland Basin. These programs resulted in an increase in our 2012 capital expenditures, as discussed below. 
+We incurred costs of $232.5 million in the region for exploration, development, and acquisition activities in 2012 compared to $80.7 million in 2011 . A significant portion of the 2012 costs incurred in this region were for leasing activities and a drilling program that was weighted toward the last half of the year. The region’s 2012 production was 11.3 BCFE, compared to 2011 production of 11.5 BCFE. The decrease in production was due to natural decline in our Wolfberry assets as the field matured. Estimated proved reserves at the end of 2012 were 94.8 BCFE, which was a decrease from 2011 year-end proved reserves of 107.0 BCFE. 
+7 
+Table of Contents 
+Reserves 
+The table below presents summary information with respect to the estimates of our proved reserves for each of the years in the three-year period ended December 31, 2012 . We engaged Ryder Scott Company, L.P. (“Ryder Scott”) to audit our internal engineering estimates of at least 80 percent of the PV-10 value of our estimated proved reserves in each year presented. The prices used in the calculation of proved reserve estimates as of December 31, 2012 , were $94.71 per Bbl for oil, $2.76 per MMBtu for natural gas, and $45.65 per Bbl for NGLs. 
+Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. The PV-10 values shown in the following table are not intended to represent the current market value of our estimated proved reserves. Neither prices nor costs have been escalated. The actual quantities and present values of our estimated proved reserves may be less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the Securities and Exchange Commission (“SEC”), since the beginning of the last fiscal year. The following table should be read along with the section entitled Risk Factors – Risks Related to Our Business contained herein. 
+Our ability to replace our production is important to our sustainability. Please refer to the reserve replacement terms in the Glossary of Oil and Gas Terms section of this report for information describing how our reserve replacement metrics are calculated. Our reserve replacement percentages are calculated using information from the Oil and Gas Reserve Quantities section of Supplemental Oil and Gas Information located in Part II, Item 8 of this report. 
+8 
+Table of Contents 
+We believe the concept of reserve replacement as described in the Glossary of Oil and Gas Terms section of this report, as well as permutations that may include other captions of the Oil and Gas Reserve Quantities section of Supplemental Oil and Gas Information located in Part II, Item 8 of this report, are widely understood by those who make investment decisions related to the oil and gas exploration business. 
+As of December 31, 
+2012 
+2011 
+2010 
+Reserve data: 
+Proved developed 
+Oil (MMBbl) 
+58.8 
+50.3 
+46.0 
+Gas (Bcf) 
+483.2 
+451.2 
+411.0 
+NGLs (MMBbl) 
+27.2 
+15.2 
+— 
+BCFE (1) 
+999.1 
+844.0 
+687.3 
+Proved undeveloped 
+Oil (MMBbl) 
+33.5 
+21.4 
+11.4 
+Gas (Bcf) 
+350.2 
+212.8 
+229.0 
+NGLs (MMBbl) 
+35.1 
+12.3 
+— 
+BCFE (1) 
+761.5 
+415.2 
+297.2 
+Total Proved 
+Oil (MMBbl) 
+92.2 
+71.7 
+57.4 
+Gas (Bcf) 
+833.4 
+664.0 
+640.0 
+NGLs (MMBbl) 
+62.3 
+27.5 
+— 
+BCFE (1) 
+1,760.6 
+1,259.2 
+984.5 
+Proved developed reserves % 
+57 
+% 
+67 
+% 
+70 
+% 
+Proved undeveloped reserves % 
+43 
+% 
+33 
+% 
+30 
+% 
+Reserve value data (in millions): 
+Proved developed PV-10 
+$ 
+2,982.6 
+$ 
+2,836.3 
+$ 
+2,053.5 
+Proved undeveloped PV-10 
+866.5 
+624.9 
+290.8 
+Total proved PV-10 
+$ 
+3,849.1 
+$ 
+3,461.2 
+$ 
+2,344.3 
+Standardized measure of discounted future cash flows 
+$ 
+3,021.0 
+$ 
+2,580.0 
+$ 
+1,666.4 
+Reserve replacement – drilling, excluding revisions 
+411 
+% 
+310 
+% 
+349 
+% 
+All in – including sales of reserves 
+329 
+% 
+262 
+% 
+293 
+% 
+All in – excluding sales of reserves 
+337 
+% 
+317 
+% 
+372 
+% 
+Reserve life (years) 
+8.0 
+7.4 
+8.9 
+(1) Totals may not sum or recalculate due to rounding. 
+Note: NGL reserve data for 2010 has not been reclassified to conform to the current presentation given the immateriality of the volumes in 2010. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices under Part II, Item 7 of this report. 
+9 
+Table of Contents 
+The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 value (Non-GAAP). The difference is a result of the PV-10 value measure excluding the impact of income taxes. Please see the definitions of standardized measure of discounted future net cash flows and PV-10 value in the Glossary of Oil and Gas Terms . 
+As of December 31, 
+2012 
+2011 
+2010 
+(in millions) 
+Standardized measure of discounted future net cash flows 
+$ 
+3,021.0 
+$ 
+2,580.0 
+$ 
+1,666.4 
+Add: 10 percent annual discount, net of income taxes 
+1,742.1 
+1,727.6 
+1,294.6 
+Add: future undiscounted income taxes 
+1,609.4 
+1,740.4 
+1,335.5 
+Undiscounted future net cash flows 
+$ 
+6,372.5 
+$ 
+6,048.0 
+$ 
+4,296.5 
+Less: 10 percent annual discount without tax effect 
+(2,523.4 
+) 
+(2,586.8 
+) 
+(1,952.2 
+) 
+PV-10 value 
+$ 
+3,849.1 
+$ 
+3,461.2 
+$ 
+2,344.3 
+Proved Undeveloped Reserves 
+Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period. As of December 31, 2012 , we had no undrilled proved undeveloped reserves that had been on our books in excess of five years. 
+During 2012 , the Company utilized reliable geologic and engineering technology to add approximately 177.7 BCFE of proved undeveloped reserves for locations that are more than one location removed from developed locations in the more developed portions of our Eagle Ford shale position. We incorporated public and proprietary data from multiple sources to establish geologic continuity of the formation and its producing properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (both vertically and horizontally collected), and petrophysical analysis of the log data, mud logs, gas sample analysis, measurements of total organic content, thermal maturity, test production, fluid properties, and core data as well as significant statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas where both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonably certain results. In all other areas, we restricted proved undeveloped locations to immediate offsets to producing wells. 
+As of December 31, 2012 , we had 761.5 BCFE of proved undeveloped reserves, which is an increase of 346.3 BCFE, or 83 percent , over proved undeveloped reserves of 415.2 BCFE at December 31, 2011 . We added 549.7 BCFE of proved undeveloped reserves through our drilling program, 278.1 BCFE of which were extensions and discoveries, primarily in our Eagle Ford shale play, as well as an additional 271.6 BCFE of infill proved undeveloped reserves that were mostly concentrated in our assets in the Bakken/Three Forks and the Eagle Ford shale plays. A negative price revision of 29.1 BCFE was primarily due to gas weighted projects in our South Texas & Gulf Coast and Mid-Continent regions that no longer generated positive cash flow utilizing 12-month average benchmark pricing required by the SEC. Extensive delineation drilling in our Eagle Ford shale program during 2012 resulted in an increase in statistical data available in the play. This information, combined with extensive data demonstrating the geologic continuity of the reservoir, allowed us to add 491.2 BCFE of new proved undeveloped reserves in the Eagle Ford shale play and led to a downward engineering revision of 39.2 BCFE primarily r 
+10 
+Table of Contents 
+elated to previously booked Eagle Ford shale proved undeveloped locations. We removed 42.7 BCFE of proved undeveloped reserves from our books, primarily in the Woodford shale, due to low natural gas prices and as a result of the five-year limitation on the number of years that proved undeveloped reserves may be booked without being developed. During the year, we sold proved undeveloped assets in our Rocky Mountain region, comprising 3.2 BCFE. During 2012 , we converted 89.2 BCFE of proved undeveloped reserves to proved developed reserves, primarily in our Eagle Ford shale and Bakken/Three Forks plays at a total capital cost of $203.6 million, of which $159.4 million was incurred in 2012. Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement for discussion of the carry of 90 percent of certain of our drilling and completion costs. As of December 31, 2012 , estimated future development costs relating to our proved undeveloped reserves are approximately $660 million, $451 million, and $359 million in 2013, 2014, and 2015, respectively. 
+Internal Controls Over Reserves Estimates 
+Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with the SEC’s regulations. Our process for managing and monitoring the Company’s proved reserves is delegated to our reservoir engineering group, which is managed by Dennis A. Zubieta, our Vice President - Engineering, Evaluation and A&D, subject to the oversight of our management and the Audit Committee of our Board of Directors, as discussed below. Mr. Zubieta joined us in June 2000 as a Corporate Acquisition & Divestiture Engineer, assumed the role of Reservoir Engineer in February 2003, was appointed Reservoir Engineering Manager in August 2005, was appointed Vice President - Engineering and Evaluation in August 2008, and was appointed Vice President - Engineering, Evaluation and A&D in October 2012. Mr. Zubieta was employed by Burlington Resources Oil and Gas Company from June 1988 to May 2000 in various operations and reservoir engineering capacities. Mr. Zubieta received a Bachelor of Science degree in Petroleum Engineering from Montana Tech of The University of Montana in May 1988. Technical reviews are performed throughout the year by regional staff who evaluate geological and engineering data. This data, in conjunction with economic data and our ownership information, is used in making a determination of estimated proved reserve quantities. Our regional engineering technical staff do not report directly to Mr. Zubieta; they report to either their respective regional technical managers or directly to the regional manager. This is intended to promote objective and independent analysis within our regions in the reserves estimation process. 
+Third-party Reserves Audit 
+Ryder Scott performed an independent audit using its own engineering assumptions but with economic and ownership data we provided. Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve PV-10 value. In the aggregate, the proved reserve values of our audited properties determined by Ryder Scott are required to be within 10 percent of our proved reserve valuations for the total company, as well as for each respective region. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world for over seventy years. The technical person at Ryder Scott primarily responsible for overseeing our reserves audit is a Managing Senior Vice President who received a Bachelor of Science degree in Petroleum Engineering from the University of Missouri at Rolla in 1970, and who is a registered Professional Engineer in Colorado and Utah. He is also a member of the Society of Petroleum Engineers. The Ryder Scott 2012 report concerning our reserves is included as Exhibit 99.1. 
+In addition to a third party audit, our reserves are reviewed by management with the Audit Committee of our Board of Directors. Management, which includes our Chief Executive Officer, President and Chief Operating Officer, Executive Vice President and Chief Financial Officer, and Senior Vice President - Portfolio Development and Technical Services, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate in conjunction with Ryder Scott’s results and also meets with Ryder Scott representatives from time to time to discuss its processes and findings. 
+11 
+Table of Contents 
+Production 
+The following table summarizes the volumes and realized prices of oil, gas, and NGLs produced and sold from properties in which we held an interest during the periods indicated. Realized prices presented below exclude the effects of hedges and derivative contracts. Also presented is a summary of related production costs per MCFE. 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+Net production 
+Oil (MMBbl) 
+10.4 
+8.1 
+6.4 
+Gas (Bcf) 
+120.0 
+100.3 
+71.9 
+NGLs (MMBbl) 
+6.1 
+3.5 
+— 
+BCFE 
+218.9 
+169.7 
+110.0 
+Eagle Ford net production (1) 
+Oil (MMBbl) 
+3.1 
+2.5 
+0.8 
+Gas (Bcf) 
+58.1 
+32.9 
+13.0 
+NGLs (MMBbl) 
+5.7 
+3.1 
+— 
+BCFE 
+110.9 
+66.6 
+17.6 
+Average net daily production 
+Oil (MBbl per day) 
+28.3 
+22.1 
+17.4 
+Gas (MMcf per day) 
+328.0 
+274.8 
+196.9 
+NGLs (MBbl per day) 
+16.7 
+9.6 
+— 
+MMCFE per day 
+598.2 
+465.0 
+301.4 
+Eagle Ford average net daily production (1) 
+Oil (MBbl per day) 
+8.6 
+6.8 
+2.1 
+Gas (MMcf per day) 
+158.8 
+90.1 
+35.6 
+NGLs (MBbl per day) 
+15.5 
+8.6 
+— 
+MMCFE per day 
+303.1 
+182.5 
+48.3 
+Realized price 
+Oil (per Bbl) 
+$ 
+85.45 
+$ 
+88.23 
+$ 
+72.65 
+Gas (per Mcf) 
+$ 
+2.98 
+$ 
+4.32 
+$ 
+5.21 
+NGLs (per Bbl) 
+$ 
+37.61 
+$ 
+53.32 
+$ 
+— 
+Per MCFE 
+$ 
+6.73 
+$ 
+7.85 
+$ 
+7.60 
+Production costs per MCFE 
+Lease operating expense 
+$ 
+0.82 
+$ 
+0.88 
+$ 
+1.10 
+Transportation costs 
+$ 
+0.63 
+$ 
+0.51 
+$ 
+0.19 
+Production taxes 
+$ 
+0.33 
+$ 
+0.32 
+$ 
+0.48 
+(1) In each of the years 2012, 2011, and 2010, total estimated proved reserves attributed to our Eagle Ford shale properties exceeded 15 percent of our total proved reserves expressed on an equivalent basis. 
+Note: NGL production volumes and prices for 2010 have not been reclassified to conform to the current presentation given the immateriality of the volumes in 2010. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices under Part II, Item 7 of this report. 
+12 
+Table of Contents 
+Productive Wells 
+As of December 31, 2012 , we had working interests in 1,184 gross (730 net) productive oil wells and 3,018 gross (1,078 net) productive gas wells. Productive wells are either wells producing in commercial quantities or wells that are mechanically capable of commercial production, but are currently shut-in. Multiple completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of the current production mix. 
+Drilling Activity 
+All of our drilling activities are conducted using independent drilling contractors. We do not own any drilling equipment. The following table summarizes the number of operated and non-operated wells drilled or recompleted on our properties in 2012 , 2011 , and 2010 , excluding non-consented projects, active injector wells, and any wells in which we own only a royalty interest: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development wells: 
+Oil 
+127 
+47.2 
+125 
+32.1 
+191 
+36.5 
+Gas 
+337 
+124.5 
+273 
+81.0 
+72 
+17.0 
+Non-productive 
+10 
+6.3 
+11 
+4.0 
+4 
+1.1 
+474 
+178.0 
+409 
+117.1 
+267 
+54.6 
+Exploratory wells: 
+Oil 
+9 
+6.9 
+16 
+6.3 
+36 
+11.5 
+Gas 
+8 
+6.8 
+48 
+8.6 
+83 
+37.9 
+Non-productive 
+8 
+6.8 
+3 
+1.0 
+1 
+0.8 
+25 
+20.5 
+67 
+15.9 
+120 
+50.2 
+Total 
+499 
+198.5 
+476 
+133.0 
+387 
+104.8 
+A productive well is an exploratory, development, or extension well that is producing oil, gas, and/or NGLs or that is capable of commercial production of those products. A non-productive well, frequently referred to within the industry as a dry hole, is an exploratory, development, or extension well that proves to be incapable of producing either oil, gas, and/or NGLs in commercial quantities. 
+As defined by the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive and is part of a development project, which is defined as the means by which petroleum resources are brought to economically producible status. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of equipment for production of oil, gas, and/or NGLs, or in the case of a dry well, the reporting to the appropriate authority that the well has been plugged and abandoned. 
+13 
+Table of Contents 
+In addition to the wells drilled and completed in 2012 (included in the table above), as of February 14, 2013 , we were participating in the drilling of 44 gross wells. We operate 25 of these wells on a gross basis (17 on a net basis) and other companies operate the remaining 19 gross wells (two on a net basis). With respect to completion activity, at such date, there were 234 gross wells in which we have an interest that were being completed. We operate 45 of these completion activities on a gross basis (40 on a net basis), and were participating in 189 gross (34 net) non-operated completion activities. Substantially all of these operations relate to the drilling of wells during the primary term of the respective oil and gas lease or leases. 
+Acreage 
+The following table sets forth the gross and net acres of developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held by us as of December 31, 2012 . Undeveloped acreage includes leasehold interests that contain proved undeveloped reserves. 
+Developed Acres (1) 
+Undeveloped Acres (2) 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Louisiana 
+71,750 
+24,794 
+39,104 
+30,989 
+110,854 
+55,783 
+Montana 
+57,586 
+39,877 
+312,758 
+210,226 
+370,344 
+250,103 
+Nevada 
+— 
+— 
+197,634 
+197,634 
+197,634 
+197,634 
+North Dakota 
+158,489 
+102,579 
+105,932 
+62,115 
+264,421 
+164,694 
+Oklahoma 
+249,706 
+82,441 
+64,642 
+28,433 
+314,348 
+110,874 
+Pennsylvania 
+282 
+282 
+26,270 
+22,803 
+26,552 
+23,085 
+Texas 
+245,699 
+152,195 
+570,504 
+320,510 
+816,203 
+472,705 
+Wyoming 
+45,261 
+21,897 
+267,961 
+189,825 
+313,222 
+211,722 
+Other (3) 
+4,430 
+2,011 
+42,926 
+29,937 
+47,356 
+31,948 
+833,203 
+426,076 
+1,627,731 
+1,092,472 
+2,460,934 
+1,518,548 
+Louisiana Fee Properties 
+10,499 
+10,499 
+14,415 
+14,415 
+24,914 
+24,914 
+Louisiana Mineral Servitudes 
+7,426 
+4,217 
+4,769 
+4,407 
+12,195 
+8,624 
+17,925 
+14,716 
+19,184 
+18,822 
+37,109 
+33,538 
+Total (4) 
+851,128 
+440,792 
+1,646,915 
+1,111,294 
+2,498,043 
+1,552,086 
+(1) 
+Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but has been included only as developed acreage in the presentation above. 
+(2) 
+Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves. 
+(3) 
+Includes interests in Arkansas, Colorado, Kansas, Illinois, Mississippi, Nebraska, New Mexico, and Utah. 
+(4) 
+As of the filing date of this report, we had approximately 63,368, 79,048, and 162,422 net acres scheduled to expire by December 31, 2013, 2014, and 2015, respectively, if production is not established or we take no other action to extend the terms of the applicable lease or leases. 
+14 
+Table of Contents 
+Delivery Commitments 
+As of December 31, 2012 , we had gathering, processing, and transportation through-put commitments with various parties that require us to deliver fixed, determinable quantities of production over specified time frames. We have an aggregate minimum commitment to deliver 1,515 Bcf of natural gas and 36 MMBbls of oil. These contracts expire at various dates through 2023. We are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. If a shortfall in the minimum volume commitment for natural gas is projected, we have rights under certain contracts to arrange for third party gas to be delivered, and such volume will count toward our minimum volume commitment. Our current production is insufficient to offset these aggregate contractual liabilities, but we expect to fulfill the delivery commitments with production from the future development of our proved undeveloped reserves and from the future development of resources not yet characterized as proved reserves in our Eagle Ford shale and Haynesville shale resource plays. Therefore, we currently do not expect any significant shortfalls. 
+Major Customers 
+For the year ended December 31, 2012 , we had two major customers, Regency Gas Services LLC and Plains Marketing LP , which accounted for approximately 21 percent and 13 percent , respectively, of our total revenue. During 2011 and 2010 , we had one major customer, Regency Gas Services LLC , which individually accounted for approximately 18 percent and 11 percent , respectively, of our total revenue. 
+Employees and Office Space 
+As of February 14, 2013 , we had 725 full-time employees. None of our employees are subject to a collective bargaining agreement, and we consider our relations with our employees to be good. 
+As of December 31, 2012 , we leased approximately 98,000 square feet of office space in Denver, Colorado for our executive and administrative offices; approximately 45,000 square feet of office space in Tulsa, Oklahoma; approximately 62,000 square feet in Houston, Texas; approximately 30,000 square feet in Billings, Montana; approximately 22,000 square feet in Midland, Texas; approximately 7,000 total square feet in Williston and Watford City, North Dakota; and approximately 2,000 square feet in Casper, Wyoming. As of December 31, 2012 , we own field office facilities containing approximately 12,000 square feet of office space in Catarina, Texas; approximately 3,000 square feet of office space in Belfield, North Dakota; and approximately 4,000 square feet of office space in Sidney, Montana. 
+Title to Properties 
+Substantially all of our interests are held pursuant to oil and gas leases from third parties. A title opinion is usually obtained prior to the commencement of initial drilling operations. We have obtained title opinions or have conducted other title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. Substantially all of our producing properties are subject to mortgages securing indebtedness under our credit facility, royalty and overriding royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere with the use of, or affect the value of, such properties. We typically perform only minimal title investigation before acquiring undeveloped leasehold acreage. 
+Seasonality 
+Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal 
+15 
+Table of Contents 
+anomalies, such as mild winters, sometimes lessen these fluctuations. The impact of seasonality on oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of worldwide production capacity in excess of existing worldwide demand for oil. Certain of our drilling, completion, and other operations are also subject to seasonal limitations. Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. See Risk Factors - Risks Related to Our Business for additional discussion. 
+Competition 
+The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We believe our leasehold position provides a sound foundation for a solid drilling program and our future growth. Our competitive position also depends on our geological, geophysical, and engineering expertise, as well as our financial resources. We believe the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams enable us to compete in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies, which in some cases have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs and other equipment, and generate electricity. 
+We also compete with other oil and gas companies in attempting to secure drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells. Consequently, we may face shortages or delays in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may be affected by future new energy, climate-related, financial, and/or other policies, legislation, and regulations. 
+In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals. Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the availability of individuals with these skills is becoming more limited due to the evolving demographics of our industry. We are not insulated from the competition for quality people, and we must compete effectively in order to be successful. 
+Government Regulations 
+Our business is extensively regulated by numerous federal, state, and local laws and governmental regulations. These laws and regulations may be changed from time to time in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations have the potential of increasing our cost of doing business and, consequently, could affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry. 
+Energy Regulations. Many of the states in which we conduct our operations have adopted laws and regulations governing the exploration for and production of oil, gas, and NGLs, including laws and regulations that require permits for the drilling of wells, impose bonding requirements in order to drill or operate wells, and govern the timing of drilling and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to various state conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the unitization or pooling of oil and gas properties. In addition, state conservation laws sometimes establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. 
+16 
+Table of Contents 
+Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of Land Management (“BLM”). These leases contain relatively standardized terms and require compliance with detailed regulations and orders that are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and must comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may suspend or terminate our operations on federal leases. 
+In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes have increased the amount of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM. 
+Our sales of natural gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce. FERC’s current regulatory framework generally provides for a competitive and open access market for sales and transportation of natural gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for natural gas production. In addition, the less stringent regulatory approach currently pursued by FERC and the United States Congress may not continue indefinitely. 
+Environmental, Health and Safety Matters 
+General. Our operations are subject to stringent and complex federal, state, tribal and local laws and regulations governing protection of the environment and worker health and safety as well as the discharge of materials into the environment. These laws and regulations may, among other things: 
+• 
+require the acquisition of various permits before drilling commences; 
+• 
+restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities; 
+• 
+limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and 
+• 
+require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells. 
+These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes that result in more stringent and costly permitting, waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs. 
+17 
+Table of Contents 
+The following is a summary of some of the existing laws, rules and regulations to which our business is subject. 
+Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. 
+Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. 
+Water discharges. The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, U.S. Army Corps of Engineers or analogous state agencies. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. 
+The Oil Pollution Act of 1990 (“OPA”) addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil liability. 
+18 
+Table of Contents 
+Air emissions. The federal Clean Air Act (“CAA”), and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. 
+Climate change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change could have an adverse effect on our operations and the demand for oil and gas. See “ Risk Factors - Risks Related to Our Business - Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for crude oil, natural gas and NGLs .” In addition to the effects of regulation, the meteorological effects of global climate change could pose additional risks to our operations, including physical damage risks associated with more frequent, more intensive storms and flooding, and could adversely affect the demand for our products. 
+Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our well drilling operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas. 
+National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay development of some of our oil and natural gas projects. 
+OSHA and other laws and regulation. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe that we are in substantial compliance with the applicable requirements of OSHA and comparable laws. 
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+Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of our drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s (the “SDWA”) Underground Injection Control Program. The federal SDWA protects the quality of the nation’s public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas activities using hydraulic fracturing techniques, which could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and delays, all of which could adversely affect our financial position, results of operations and cash flows. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. 
+We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. While we believe that we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot give any assurance that we will not be adversely affected in the future. 
+Cautionary Information about Forward-Looking Statements 
+This Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear in a number of places in this Form 10-K, and include statements about such matters as: 
+• 
+the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures; 
+• 
+the drilling of wells and other exploration and development activities and plans, as well as possible future acquisitions; 
+• 
+the possible divestiture or farm-down of, or joint venture relating to, certain properties; 
+• 
+proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those proved reserve estimates; 
+• 
+future oil, gas, and NGL production estimates; 
+• 
+our outlook on future oil, gas, and NGL prices, well costs, and service costs; 
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+• 
+cash flows, anticipated liquidity, and the future repayment of debt; 
+• 
+business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and 
+• 
+other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in Item 7 of this report. 
+Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. These risks are described in the Risk Factors section of this report, and include such factors as: 
+• 
+the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves; 
+• 
+the continued weakness in economic conditions and uncertainty in financial markets; 
+• 
+our ability to replace reserves in order to sustain production; 
+• 
+our ability to raise the substantial amount of capital that is required to replace our reserves; 
+• 
+our ability to compete against competitors that have greater financial, technical, and human resources; 
+• 
+our ability to attract and retain key personnel; 
+• 
+the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves; 
+• 
+the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities; 
+• 
+the possibility that exploration and development drilling may not result in commercially producible reserves; 
+• 
+our limited control over activities on non-operated properties; 
+• 
+our reliance on the skill and expertise of third-party service providers on our operated properties; 
+• 
+the possibility that title to properties in which we have an interest may be defective; 
+• 
+the possibility that our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production; 
+• 
+the uncertainties associated with divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate; 
+• 
+the uncertainties associated with enhanced recovery methods; 
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+• 
+our commodity derivative contracts may result in financial losses or may limit the prices that we receive for oil, gas, and NGL sales; 
+• 
+the inability of one or more of our vendors, customers, or contractual counterparties to meet their obligations; 
+• 
+price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values; 
+• 
+the impact that lower oil, gas, or NGL prices could have on the amount we are able to borrow under our credit facility; 
+• 
+the possibility that our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt; 
+• 
+operating and environmental risks and hazards that could result in substantial losses; 
+• 
+complex laws and regulations, including environmental regulations, that result in substantial costs and other risks; 
+• 
+the availability and capacity of gathering, transportation, processing, and/or refining facilities; 
+• 
+our ability to sell and/or receive market prices for our oil, gas, and NGLs; 
+• 
+new technologies may cause our current exploration and drilling methods to become obsolete; 
+• 
+the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and 
+• 
+litigation, environmental matters, the potential impact of government regulations, and the use of management estimates regarding such matters. 
+We caution you that forward-looking statements are not guarantees of future performance and that actual results or performance may be materially different from those expressed or implied in the forward-looking statements. The forward-looking statements in this report speak as of the filing date of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws. 
+Available Information 
+Our internet website address is www.sm-energy.com. We routinely post important information for investors on our website. Within our website’s investor relations section, we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. We also make available through our website’s corporate governance section our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Financial Code of Ethics, and the Charters of the Audit, Compensation, Executive, and Nominating and Corporate Governance Committees of our Board of Directors. Information on our website is not incorporated by reference into this report and should not be considered part of this document. 
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+Glossary of Oil and Gas Terms 
+The oil and gas terms defined in this section are used throughout this report. The definitions of the terms developed reserves, exploratory well, field, proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under SEC Rule 4-10(a) of Regulation S-X, as amended effective for fiscal years ending on or after December 31, 2009. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located through the SEC’s website at www.sec.gov. 
+Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used in reference to oil or other liquid hydrocarbons. 
+Bcf . Billion cubic feet, used in reference to natural gas. 
+BCFE. Billion cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs. 
+BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs. 
+BTU. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit. 
+Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production. 
+Developed reserves. Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. 
+Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+Dry hole. A well found to be incapable of producing either oil, natural gas, and/or NGLs in commercial quantities. 
+Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. 
+Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil and natural gas) rights. 
+Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. 
+Finding and development cost. Expressed in dollars per MCFE. Finding and development cost metrics provide information as to the cost of adding proved reserves from various activities, and are widely utilized within the exploration and production industry, as well as by investors. The information used to calculate these metrics is included in the Supplemental Oil and Gas Information section in Part II, Item 8 of this report. It should be noted that finding and development cost metrics have limitations. For example, exploration efforts related to a particular set of proved reserve additions may extend over several years. As a result, the exploration costs incurred in earlier periods are not included in the amount of exploration costs incurred during the period in which that set of proved reserves is added. In addition, consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred. Since the additional development costs that will need to be incurred in 
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+the future before the proved undeveloped reserves are ultimately produced are not included in the amount of costs incurred during the period in which those reserves were added, those development costs in future periods will be reflected in the costs associated with adding a different set of reserves. The calculations of various finding and development cost metrics are explained below. 
+Finding and development cost – Drilling, excluding revisions. Calculated by dividing the amount of costs incurred for development and exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, and infill drilling, during the same period. 
+Finding and development cost – Drilling, including revisions. Calculated by dividing the amount of costs incurred for development and exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, and revisions of previous estimates, during the same period. 
+Finding and development cost – Drilling and acquisitions, excluding revisions. Calculated by dividing the amount of costs incurred for development, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, and acquisitions, during the same period. 
+Finding and development cost – Drilling and acquisitions, including revisions. Calculated by dividing the amount of costs incurred for development, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, revisions of previous estimates, and acquisitions, during the same period. 
+Finding and development cost –All in, including sales of reserves. Calculated by dividing the amount of total capital expenditures for oil and natural gas activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates less sales of reserves, during the same period. 
+Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions. 
+Gross acre. An acre in which a working interest is owned. 
+Gross well. A well in which a working interest is owned. 
+Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical. 
+Lease operating expenses. The expenses incurred in the lifting of crude oil, natural gas, and/or associated liquids from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs. 
+MBbl. One thousand barrels of crude oil or other liquid hydrocarbons. 
+MMBbl. One million barrels of crude oil or other liquid hydrocarbons. 
+Mcf. One thousand cubic feet, used in reference to natural gas. 
+MCFE. One thousand cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs. 
+MMcf. One million cubic feet, used in reference to natural gas. 
+MMCFE. One million cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs. 
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+MMBtu. One million British thermal units. 
+Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells. 
+Net asset value per share. The result of the fair market value of total assets less total liabilities, divided by the total number of outstanding shares of common stock. 
+NGLs. The combination of ethane, propane, butanes, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressures and lower temperatures. 
+NYMEX WTI. New York Mercantile Exchange West Texas Intermediate. 
+OPIS . Oil Price Information Service Mont Belvieu. 
+PV-10 value (Non-GAAP). The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period. This is a Non-GAAP measure. 
+Productive well. A well that is producing crude oil, natural gas, and/or NGLs or that is capable of commercial production of those products. 
+Proved reserves. Those quantities of oil, gas, and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 
+Recompletion. The completion in an existing wellbore in a formation other than that in which the well has previously been completed. 
+Reserve life. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period. 
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+Reserve replacement. Reserve replacement metrics are used as indicators of a company’s ability to replenish annual production volumes and grow its reserves, and provide information related to how successful a company is at growing its proved reserve base. These are believed to be useful non-GAAP measures that are widely utilized within the exploration and production industry, as well as by investors. They are easily calculable metrics, and the information used to calculate these metrics is included in the Supplemental Oil and Gas Information section of Part II, Item 8 of this report. It should be noted that reserve replacement metrics have limitations. They are limited because they typically vary widely based on the extent and timing of new discoveries and property acquisitions. Their predictive and comparative value is also limited for the same reasons. In addition, because the metrics do not embed the cost or timing of future production of new reserves, they cannot be used as a measure of value creation. The calculations of various reserve replacement metrics are explained below. 
+Reserve replacement – Drilling, excluding revisions. Calculated as a numerator comprised of the sum of reserve extensions and discoveries and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling activity. 
+Reserve replacement – Drilling, including revisions. Calculated as a numerator comprised of the sum of reserve extensions, discoveries, and infill reserves, and revisions of previous estimates in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling activity with an adjustment for revisions. 
+Reserve replacement – Drilling and acquisitions, excluding revisions. Calculated as a numerator comprised of the sum of reserve acquisitions and reserve extensions, discoveries, and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities. 
+Reserve replacement – Drilling and acquisitions, including revisions. Calculated as a numerator comprised of the sum of reserve acquisitions and reserve extensions, discoveries, and infill reserves, and revisions of previous estimates in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities with an adjustment for revisions. 
+Reserve replacement percentage – All in, excluding sales of reserves. The sum of reserve extensions and discoveries, infill drilling, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period. 
+Reserve replacement percentage –All in, including sales of reserves. The sum of sales of reserves, infill drilling, reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period. 
+Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude oil, natural gas, and/or associated liquid resources that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 
+Resource play. A term used to describe an accumulation of crude oil, natural gas, and/or associated liquid resources known to exist over a large areal expanse, which when compared to a conventional play typically has a lower expected geological and/or commercial development risk. 
+Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil, natural gas, and NGLs produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well. 
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+Royalty interest. An interest in an oil and natural gas property entitling the owner to shares of crude oil, natural gas, and NGL production free of costs of exploration, development, and production operations. 
+Seismic. The sending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape, and depth of subsurface rock formations. 
+Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock. 
+Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a 10 percent annual discount rate. The information for this calculation is included in the supplemental information regarding disclosures about oil and gas producing activities following the Notes to Consolidated Financial Statements included in this report. 
+Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves. 
+Undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. 
+Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share in the production, sales, and costs. 
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+ITEM 1A. RISK FACTORS 
+In addition to the other information included in this report, the following risk factors should be carefully considered when evaluating an investment in us. 
+Risks Related to Our Business 
+Crude oil, natural gas, and NGL prices are volatile, and declines in prices adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow. 
+Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and natural gas properties depend heavily on the prices we receive for crude oil, natural gas and NGL sales. Crude oil, natural gas, and NGL prices also affect our cash flows available for capital expenditures and other items, our borrowing capacity, and the amount and value of our crude oil, natural gas, and NGL reserves. For example, the amount of our borrowing base under our credit facility is subject to periodic redeterminations based on crude oil, natural gas, and NGL prices specified by our bank group at the time of redetermination. In addition, we may have crude oil and natural gas property impairments or downward revisions of estimates of proved reserves if prices fall significantly. 
+Historically, the markets for crude oil, natural gas, and NGLs have been volatile, and they are likely to continue to be volatile. Wide fluctuations in crude oil, natural gas, and NGL prices may result from relatively minor changes in the supply of and demand for crude oil, natural gas, and NGLs, market uncertainty, and other factors that are beyond our control, including: 
+• 
+global and domestic supplies of crude oil, natural gas, and NGLs, and the productive capacity of the industry as a whole; 
+• 
+the level of consumer demand for crude oil, natural gas, and NGLs; 
+• 
+overall global and domestic economic conditions; 
+• 
+weather conditions; 
+• 
+the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas that may affect the realized price for crude oil, natural gas, or NGLs; 
+• 
+liquefied natural gas deliveries to and from the United States; 
+• 
+the price and level of foreign imports of crude oil, refined petroleum products, and liquefied natural gas; 
+• 
+the price and availability of alternative fuels; 
+• 
+technological advances and regulations affecting energy consumption and conservation; 
+• 
+the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to agree to and maintain crude oil price and production controls; 
+• 
+political instability or armed conflict in crude oil or natural gas producing regions; 
+• 
+strengthening and weakening of the United States dollar relative to other currencies; and 
+• 
+governmental regulations and taxes. 
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+These factors and the volatility of crude oil, natural gas, and NGL markets make it extremely difficult to predict future crude oil, natural gas, and NGL price movements with any certainty. Declines in crude oil, natural gas, and NGL prices would reduce our revenues and could also reduce the amount of crude oil, natural gas, and NGLs that we can produce economically, which could have a materially adverse effect on us. 
+Continued weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict. 
+United States and global economies and financial systems have recently experienced turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, increased levels of unemployment, and an unprecedented level of intervention by the United States federal government and other governments. Although some portions of the economy appear to have stabilized and there have been signs of the beginning of a recovery, the extent and timing of a recovery, and whether it can be sustained, are uncertain. Continued weakness in the United States or other large economies could materially adversely affect our business and financial condition. For example: 
+• 
+the demand for crude oil, natural gas, and NGLs in the United States has declined and may remain at low levels or further decline if economic conditions remain weak, and continue to negatively impact our revenues, margins, profitability, operating cash flows, liquidity, and financial condition; 
+• 
+natural gas prices have recently been lower than at various times in the last decade because of increased supply resulting from, among other things, increased drilling in unconventional reservoirs, and reduced demand in connection with the recent recession, which sustained low prices could affect our financial condition and results of operations; 
+• 
+the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables; 
+• 
+the liquidity available under our credit facility could be reduced if any lender is unable to fund its commitment; 
+• 
+our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for exploration and/or development of our reserves; 
+• 
+our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; and 
+• 
+variable interest rate spread levels, including for LIBOR and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our credit facility. 
+If we are unable to replace reserves, we will not be able to sustain production. 
+Our future operations depend on our ability to find, develop, or acquire crude oil, natural gas, and NGL reserves that are economically producible. Our properties produce crude oil, natural gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate and develop or acquire new crude oil, natural gas, and NGL reserves to replace those being depleted by production. In addition, competition for crude oil and natural gas properties is intense, and many of our competitors have financial, technical, human, and other resources needed to evaluate and integrate acquisitions that are substantially greater than those available to us. 
+In the event we do complete an acquisition, its successful impact on our business will depend on a number of factors, many of which are beyond our control. These factors include the purchase price, future crude oil, natural 
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+gas, and NGL prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and development activities on the acquired properties, and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates, and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems. 
+Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited. 
+Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions. Without successful drilling or acquisition activities, our reserves and production will decline over time. 
+Substantial capital is required to replace our reserves. 
+We must make substantial capital expenditures to find, acquire, develop, and produce crude oil, natural gas, and NGL reserves. Future cash flows and the availability of financing are subject to a number of factors, such as the level of production from existing wells, prices received for crude oil, natural gas, and NGL sales, our success in locating and developing and acquiring new reserves, and the orderly functioning of credit and capital markets. If crude oil, natural gas, and NGL prices decrease or if we encounter operating difficulties that result in our cash flows from operations being less than expected, we must reduce our capital expenditures unless we can raise additional funds through debt or equity financing or the divestment of assets. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms, and the proceeds offered to us for potential divestitures may not always be of acceptable value to us. 
+If our revenues decrease due to lower crude oil, natural gas, or NGL prices, decreased production, or other reasons, and if we cannot obtain funding through our credit facility, other acceptable debt or equity financing arrangements, or through the sale of assets, our ability to execute development plans, replace our reserves, maintain our acreage, or maintain production levels could be greatly limited. 
+Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do. 
+We face intense competition from major oil and gas companies, independent oil and gas exploration and production companies, financial buyers, and institutional and individual investors who seek oil and gas investments throughout the world, as well as the equipment, expertise, labor, and materials required to operate crude oil and natural gas properties. Many of our competitors have financial, technical, and other resources vastly exceeding those available to us, and many crude oil and natural gas properties are sold in a competitive bidding process in which our competitors may be able and willing to pay more for development prospects and productive properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for the properties. In addition, shortages of equipment, labor, or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. We may not be successful in acquiring and developing profitable properties in the face of this competition. 
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+We also compete for human resources. Over the last few years, the need for talented people across all disciplines in the industry has grown, while the number of talented people available has not grown at the same pace, and in many cases, is declining due to the demographics of the industry. 
+The loss of key personnel could adversely affect our business. 
+We depend to a large extent on the efforts and continued employment of our executive management team and other key personnel. The loss of the services of these or other key personnel could adversely affect our business. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen and other professionals. Competition for many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed. 
+The actual quantities and present value of our proved crude oil, natural gas, and NGL reserves may be less than we have estimated. 
+This report and other of our SEC filings contain estimates of our proved crude oil, natural gas, and NGL reserves and the estimated future net revenues from those reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to crude oil, natural gas, and NGL prices, drilling and completion costs, gathering and transportation costs, operating expenses, capital expenditures, effects of governmental regulation, taxes, timing of operations, and availability of funds. The process of estimating crude oil, natural gas, and NGL reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent on many variables, and therefore changes often occur as our knowledge of these variables evolve. Therefore, these estimates are inherently imprecise. In addition, the reserve estimates we make for properties that do not have a significant production history may be less reliable than estimates for properties with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing of development expenditures. 
+Actual future production, prices for crude oil, natural gas, and NGLs, revenues, production taxes, development expenditures, operating expenses, and quantities of producible crude oil, natural gas, and NGL reserves will most likely vary from those estimated. Any significant variance of any nature could materially affect the estimated quantities of and present value related to proved reserves disclosed by us, and the actual quantities and present value may be significantly less than we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration, operations and development activity, prevailing crude oil, natural gas, and NGL prices, costs to develop and operate properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties. 
+As of December 31, 2012 , 43 percent , or 761.5 BCFE, of our estimated proved reserves were proved undeveloped, and two percent , or 40.8 BCFE, were proved developed non-producing. In order to develop our proved undeveloped reserves, as of December 31, 2012 , we estimate approximately $1.6 billion of capital expenditures would be required. Production revenues from proved developed non-producing reserves will not be realized until sometime in the future and after some investment of capital. In order to develop our proved developed non-producing reserves, as of December 31, 2012 , we estimate capital expenditures of approximately $30 million would be required. Although we have estimated our proved reserves and the costs associated with these proved reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled, and actual results may not occur as estimated. 
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+You should not assume that the PV-10 value and standardized measure of discounted future net cash flows included in this report represent the current market value of our estimated proved crude oil, natural gas, and NGL reserves. Management has based the estimated discounted future net cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. For example, values of our reserves as of December 31, 2012 , were estimated using a calculated 12-month average sales price of $2.76 per MMBtu of natural gas (NYMEX Henry Hub spot price), $94.71 per Bbl of oil (NYMEX WTI spot price), and $45.65 per Bbl of NGL (OPIS spot price). We then adjust these base prices to reflect appropriate basis, quality, and location differentials over that period in estimating our proved reserves. During 2012 , our monthly average realized natural gas prices, excluding the effect of derivative cash settlements, were as high as $3.79 per Mcf and as low as $2.18 per Mcf. For the same period, our monthly average realized crude oil prices before the effect of derivative cash settlements were as high as $92.23 per Bbl and as low as $71.33 per Bbl, and were as high as $47.08 per Bbl and as low as $27.84 per Bbl for NGLs. Many other factors will affect actual future net cash flows, including: 
+• 
+amount and timing of actual production; 
+• 
+supply and demand for crude oil, natural gas, and NGLs; 
+• 
+curtailments or increases in consumption by oil purchasers and natural gas pipelines; and 
+• 
+changes in government regulations or taxes, including severance and excise taxes. 
+The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing the PV-10 value. In addition, the 10 percent discount factor required by the SEC to be used to calculate the PV-10 value for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and natural gas industry in general are subject. 
+Our property acquisitions may not be worth what we paid due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities. 
+Successful property acquisitions require an assessment of a number of factors sometimes beyond our control. These factors include exploration potential, future crude oil, natural gas, and NGL prices, operating costs, and potential environmental and other liabilities. These assessments are not precise and their accuracy is inherently uncertain. 
+In connection with our acquisitions, we typically perform a customary review of the acquired properties that will not necessarily reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. 
+In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such acquisitions may be limited. 
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+Integrating acquired properties and businesses involves a number of other special risks, including the risk that management may be distracted from normal business concerns by the need to integrate operations and systems as well as retain and assimilate additional employees. Therefore, we may not be able to realize all of the anticipated benefits of our acquisitions. 
+We have limited control over the activities on properties we do not operate. 
+Some of our properties, including a portion of our operations in the Eagle Ford shale in South Texas, are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including the nature and timing of drilling and operational activities, the operator’s skill and expertise, compliance with environmental, safety and other regulations, the approval of other participants in such properties, the selection and application of suitable technology, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs and materially and adversely affect our financial condition and results of operations. 
+We rely on third-party service providers to conduct the drilling and completion operations on properties we operate. 
+Where we are the operator of a property, we rely on third-party service providers to perform necessary drilling and completion operations. The ability of third-party service providers to perform such drilling and completion operations will depend on those service providers’ ability to compete for and retain qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the supply and demand for oil, natural gas liquids and natural gas, prevailing economic conditions and financial, business and other factors. The failure of a third-party service provider to adequately perform operations could delay drilling or completion or reduce production from the property and adversely affect our financial condition and results of operations. 
+Title to the properties in which we have an interest may be impaired by title defects. 
+We generally rely on title reports in acquiring oil and gas leasehold interests and obtain title opinions only on significant properties that we drill. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Title insurance is not available for oil and gas properties. As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work of examining records in the appropriate governmental offices and title abstract facilities before attempting to acquire or place under lease a specific mineral interest and/or undertake drilling activities. We, in some cases, perform curative work to correct deficiencies in the marketability of the title to us. Generally, under the terms of the operating agreements affecting our properties, any monetary loss attributable to a loss of title is to be borne by all parties to any such agreement in proportion to their interests in such property. A material title defect can reduce the value or render a property worthless, thus adversely affecting our financial condition, results of operations and operating cash flow if such property is of sufficient value. 
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+Exploration and development drilling may not result in commercially producible reserves. 
+Crude oil and natural gas drilling and production activities are subject to numerous risks, including the risk that no commercially producible crude oil, natural gas, or associated liquids will be found. The cost of drilling and completing wells is often uncertain, and crude oil, natural gas or associated liquids drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors include: 
+• 
+unexpected drilling conditions; 
+• 
+title problems; 
+• 
+disputes with owners or holders of surface interests on or near areas where we operate; 
+• 
+pressure or geologic irregularities in formations; 
+• 
+engineering and construction delays; 
+• 
+equipment failures or accidents; 
+• 
+hurricanes or other adverse weather conditions; 
+• 
+compliance with environmental and other governmental requirements; and 
+• 
+shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies. 
+The prevailing prices for crude oil, natural gas, and NGLs affect the cost of and the demand for drilling rigs, completion and production equipment, and other related services. However, changes in costs may not occur simultaneously with corresponding changes in commodity prices. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region. In addition, the recent economic and financial downturn has adversely affected the financial condition of some drilling contractors, which may constrain the availability of drilling services in some areas. 
+Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a materially adverse effect on our ability to explore on or develop our properties. 
+The wells we drill may not be productive, and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well if crude oil, natural gas, or NGLs are present, or whether they can be produced economically. The cost of drilling, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover drilling and completion costs. Even if sufficient amounts of crude oil, natural gas, or NGLs exist, we may damage a potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing a well, resulting in a reduction in or no production from the well, significant expense to repair the well, or the loss and abandonment of the well. 
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+Drilling results in our newer shale plays may be more uncertain than results in shale plays that are more developed and have longer established production histories. For example, our experience with horizontal drilling in the Eagle Ford shale play, as well as the industry’s drilling and production history, is more limited than in many shale plays, such as the Barnett or Woodford shales, and we and the industry generally have less information with respect to the ultimate recoverability of reserves and the production decline rates in these shales than other areas with longer histories of drilling and production. Completion techniques that have proven to be successful in other shale formations to maximize recoveries are being used in the early development of these new shales; however, we can provide no assurance of the ultimate success of these drilling and completion techniques. 
+In addition, a significant part of our strategy involves increasing our inventory of drilling locations. Such multi-year drilling inventories can be more susceptible to long-term uncertainties that could materially alter the occurrence or timing of actual drilling. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled, although we have the present intent to do so, or if we will be able to produce crude oil, natural gas, or NGLs from these or any other potential drilling locations. 
+Our future drilling activities may not be successful. Our overall drilling success rate or our drilling success rate within a particular area may decline. In addition, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Unless production is established within the spacing units covering undeveloped acres on which our drilling locations are identified, the leases for such acreage will expire and we would lose our right to develop the related properties. Our total net acreage expiring in the next three years represents approximately 27 percent of our total net undeveloped acreage at December 31, 2012. Although we have identified numerous potential drilling locations, we may not be able to economically produce crude oil, natural gas, or NGLs from all of them and our actual drilling activities may materially differ from those presently identified, which could adversely affect our financial condition, results of operations and operating cash flow. 
+Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory and delineation drilling in these plays are subject to drilling and completion technique risks, and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs, and the value of our undeveloped acreage could decline if drilling results are unsuccessful. 
+Many of our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore, and being able to run tools and recover equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools and other equipment the entire length of the well bore during completion operations, being able to recover such tools and other equipment, and successfully cleaning out the well bore after completion of the final fracture stimulation. 
+Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or prices for crude oil, natural gas, and NGL decline, then the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of our undeveloped acreage could decline in the future. 
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+Uncertainties associated with enhanced recovery methods may result in us not realizing an acceptable return on our investments in such projects. 
+We inject water into formations on some of our properties to increase the production of crude oil, natural gas, and associated liquids. We may in the future expand these efforts to more of our properties or employ other enhanced recovery methods in our operations. The additional production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of crude oil, natural gas, and associated liquids in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects. In addition, if proposed legislation and regulatory initiatives relating to hydraulic fracturing become law, the cost of some of these enhanced recovery methods could increase substantially. 
+Our commodity derivative contract activities may result in financial losses or may limit the prices that we receive for crude oil, natural gas, and NGL sales. 
+To mitigate a portion of the exposure to potentially adverse market changes in crude oil, natural gas, and NGL prices and the associated impact on cash flows, the Company has entered into various derivative contracts. The Company’s derivative contracts in place include swap and collar arrangements for crude oil, natural gas, and NGLs. As of December 31, 2012 , we were in a net accrued asset position of $38.7 million with respect to our crude oil, natural gas, and NGL derivative activities. These activities may expose us to the risk of financial loss in certain circumstances, including instances in which: 
+• 
+our production is less than expected; 
+• 
+one or more counterparties to our commodity derivative contracts default on their contractual obligations; or 
+• 
+there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement. 
+The risk of one or more counterparties defaulting on their obligations is heightened by the recent global and domestic economic and financial downturn affecting many banks and other financial institutions, including our counterparties and their affiliates. These circumstances may adversely affect the ability of our counterparties to meet their obligations to us pursuant to derivative transactions, which could reduce our revenues and cash flows from realized derivative cash settlements. As a result, our financial condition, results of operations, and cash flows could be materially affected in an adverse way if our counterparties default on their contractual obligations under our commodity derivative contracts. 
+In addition, commodity derivative contracts may limit the prices that we receive for our crude oil, natural gas and NGL sales if crude oil, natural gas, or NGL prices rise substantially over the price established by the commodity derivative contract. 
+The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results. 
+Substantially all of our accounts receivable result from crude oil, natural gas, and NGL sales or joint interest billings to co-owners of oil and gas properties we operate. This concentration of customers and joint interest owners may impact our overall credit risk because these entities may be similarly affected by various economic and other conditions, including the recent global and domestic economic and financial downturn. 
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+In addition, for the year ended December 31, 2012 , we had two major customers, Regency Gas Services LLC and Plains Marketing LP , which accounted for approximately 21 percent and 13 percent , respectively, of our total production revenue. During 2011 and 2010 , we had one major customer, Regency Gas Services LLC , individually account for approximately 18 percent and 11 percent , respectively, of our total production revenue. The loss of one or more of these customers could reduce competition for our products and negatively impact the prices at which we sell such products. 
+We have entered into firm transportation contracts that require us to pay fixed amounts of money to our counterparties regardless of quantities actually shipped, processed, or gathered. If we are unable to deliver the necessary quantities of natural gas to our counterparties, our results of operations and liquidity could be adversely affected. 
+As of December 31, 2012 , we were contractually committed to deliver 1,515 Bcf of natural gas and 36 MMBbls of oil pursuant to contracts expiring at various dates through 2023. We may enter into additional firm transportation agreements as our development of our shale plays, including the Eagle Ford and Haynesville shales, expand. At the current time, we do not have enough proved developed reserves to offset these contractual liabilities, but we intend to develop reserves that will exceed the commitments and therefore do not expect any shortfalls. We expect our production volumes, as well as that of our competitors, to increase significantly in the Eagle Ford shale. The use of firm transportation commitments gives us the strategic advantage of priority space in a transportation pipeline. In the event we encounter delays in drilling and completing our wells or otherwise due to construction, interruptions of operations, or delays in connecting new volumes to gathering systems or pipelines for an extended period of time, the requirements to pay for quantities not delivered could have a material impact on our results of operations and liquidity. 
+Future crude oil, natural gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values. 
+We follow the successful efforts method of accounting for our crude oil and natural gas properties. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If commercial quantities of hydrocarbons are not discovered with an exploratory well, the costs of drilling the well are expensed. 
+The capitalized costs of our crude oil, natural gas, and NGL properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net revenues, we generally must write down the costs of each depletion pool to the estimated discounted future net cash flows of that depletion pool. Unproved properties are evaluated at the lower of cost or fair market value. We incurred an impairment of proved property and impairment of unproved properties totaling $208.9 million and $16.3 million , respectively, during 2012 , $219.0 million and $7.4 million , respectively, during 2011 , and $6.1 million and $2.0 million , respectively, during 2010 . Significant further declines in crude oil, natural gas, or NGL prices in the future or unsuccessful exploration efforts could cause further impairment write-downs of capitalized costs. 
+We review the carrying value of our properties for indicators of impairment on a quarterly basis using the prices in effect as of the end of each quarter. Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date, even if crude oil, natural gas, or NGL prices increase. 
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+Lower crude oil, natural gas, or NGL prices could limit our ability to borrow under our credit facility. 
+Our credit facility has a current commitment amount of $1.0 billion , subject to a borrowing base that the lenders redetermine semi-annually based largely on the bank group’s assessment of the value of our crude oil, natural gas, and NGL properties, which in turn is impacted by crude oil, natural gas, and NGL prices. The current borrowing base under our credit facility is $1.55 billion . Declines in crude oil, natural gas, or NGL prices in the future could limit our borrowing base and reduce the amount we can borrow under our credit facility. Additionally, divestitures of properties could result in a reduction of our borrowing base. 
+Our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt. 
+As of December 31, 2012 , we had $350.0 million of long-term senior unsecured debt outstanding relating to our 6.625% Senior Notes due 2019 (the “2019 Notes”) that we issued on February 7, 2011; $350.0 million of long-term senior unsecured debt outstanding relating to our 6.50% Senior Notes due 2021 (the “2021 Notes”) that we issued on November 8, 2011; and $400.0 million of long-term senior unsecured debt outstanding relating to our 6.50% Senior Notes due 2023 (the “2023 Notes”) that we issued on June 29, 2012, (collectively referred to as our “Senior Notes”); and $340.0 million of outstanding borrowings under our secured credit facility. We had three outstanding letters of credit in the aggregate amount of $808,000 , (which reduce the amount available for borrowings under the facility on a dollar-for-dollar basis), resulting in $659.2 million of available debt capacity under our credit facility, assuming the borrowing conditions under this facility will be met. Our long-term debt represented 50 percent of our total book capitalization as of December 31, 2012 . 
+Our indebtedness could have important consequences for our operations, including: 
+• 
+making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements; 
+• 
+requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to productive investments; 
+• 
+limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends; 
+• 
+placing us at a competitive disadvantage compared to our competitors that have less debt; and 
+• 
+making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business. 
+Our ability to make payments on our debt and to refinance our debt and fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory, and other factors that are beyond our control. If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our credit facility or from other sources, we might not be able to service our debt or fund our other liquidity needs. If we are unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity securities, divest assets, or restructure or refinance our debt. We might not be able to sell our equity securities, sell our assets, or restructure or refinance our debt on a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our existing and future credit agreements, may prohibit us from pursuing any of these alternatives. Further, changes in the credit ratings of our debt may negatively affect the cost, terms, conditions, and availability of future financing. 
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+Our debt agreements, including the agreement governing our credit facility and the indentures governing the 2019 Notes, 2021 Notes, and 2023 Notes, permit us to incur additional debt in the future, subject to compliance with restrictive covenants under those agreements. In addition, entities we may acquire in the future could have significant amounts of debt outstanding that we could be required to assume, and in some cases accelerate repayment thereof, in connection with the acquisition, or we may incur our own significant indebtedness to consummate an acquisition. 
+As discussed above, our credit facility is subject to periodic borrowing base redeterminations. We could be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowing base or arrange new financing, we may be forced to sell significant assets. 
+The agreements governing our debt contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt. 
+Our debt agreements contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under our credit facility is subject to compliance with certain financial covenants, including (i) maintenance of a quarterly ratio of total debt to consolidated earnings before interest, taxes, depreciation, amortization, and exploration expense of no greater than 4.0 to 1.0, and (ii) maintenance of an adjusted current ratio of no less than 1.0 to 1.0, each as defined in our credit facility. Our credit facility also requires us to comply with certain financial covenants, including requirements that we maintain certain levels of stockholders’ equity and limit our annual cash dividends to no more than $50.0 million . These restrictions on our ability to operate our business could seriously harm our business by, among other things, limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate opportunities. 
+The respective indentures governing the 2019 Notes, 2021 Notes, and 2023 Notes also contain covenants that, among other things, limit our ability and the ability of our subsidiaries to: 
+• 
+incur additional debt; 
+• 
+make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire capital stock; 
+• 
+sell assets, including capital stock of our subsidiaries; 
+• 
+restrict dividends or other payments of our subsidiaries; 
+• 
+create liens that secure debt; 
+• 
+enter into transactions with affiliates; and 
+• 
+merge or consolidate with another company. 
+Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all or a portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness. 
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+We are subject to operating and environmental risks and hazards that could result in substantial losses. 
+Crude oil and natural gas operations are subject to many risks, including human error and accidents that could cause personal injury, death and property damage, well blowouts, craterings, explosions, uncontrollable flows of crude oil, natural gas and associated liquids or well fluids, migration of fracture fluids into surrounding groundwater, spills or releases from facilities and equipment used to deliver these materials, spills or releases of brine or other produced or flowback water, subsurface conditions that prevent us from stimulating the planned number of stages, accessing the entirety of the wellbore with our tools during completion, or removing fracturing materials from the wellbore to allow production to begin, fires, adverse weather such as hurricanes in the South Texas & Gulf Coast region, freezing conditions in the Williston Basin of our Rocky Mountain region, floods, droughts, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas such as hydrogen sulfide, and other environmental risks and hazards. If any of these types of events occurs, we could sustain substantial losses. 
+Furthermore, if we experience any of the problems with well stimulation and completion activities referenced above, such as hydraulic fracturing, our ability to explore for and produce crude oil, natural gas, or NGLs may be adversely affected. We could incur substantial losses or otherwise fail to realize reserves in particular formations as a result of the need to shutdown, abandon and relocate drilling operations, the need to sample, test and monitor drinking water in particular areas and to provide filtration or other drinking water supplies to users of water supplies that may have been impacted or threatened by potential contamination from fracturing fluids, the need to modify drill sites to ensure there are no spills or releases off-site and to investigate and/or remediate any spills or releases that might have occurred, and suspension of our operations. 
+There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our current and past generation, handling and disposal of materials, including solid and hazardous wastes and petroleum hydrocarbons. We may incur joint and several, strict liability under applicable United States federal and state environmental laws in connection with releases of petroleum hydrocarbons and other hazardous substances at, on, under or from our leased or owned properties, some of which have been used for natural gas and oil exploration and production activities for a number of years, often by third parties not under our control. For our non-operated properties, we are dependent on the operator for operational and regulatory compliance, and could be subject to liabilities in the event of non-compliance. These properties and the wastes disposed thereon or away from could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including the CERCLA or the Superfund law, the RCRA, the Clean Water Act, the CAA, the OPA, and analogous state laws. Under any implementing regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damage allegedly caused by the release of petroleum hydrocarbons or other wastes into the environment. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur losses. 
+We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden environmental damage. We do not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damage or insurance coverage for environmental damage that occurs over time is available at a reasonable cost. In addition, pollution and environmental risks generally are not fully insurable. Further, we may elect not to obtain other insurance coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks to which we are subject. Accordingly, we may be subject to liability or may lose substantial assets in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer a material loss. 
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+Following the severe Atlantic hurricanes in 2004, 2005, and 2008, the insurance markets suffered significant losses. As a result, insurance coverage for wind storms has become substantially more expensive, and future availability and costs of coverage are uncertain. 
+Our operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs and other risks. 
+Federal, state, tribal, and local authorities extensively regulate the oil and natural gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may become more stringent and, as a result, may affect, among other things, the pricing or marketing of crude oil, natural gas and NGL production. Noncompliance with statutes and regulations and more vigorous enforcement of such statutes and regulations by regulatory agencies may lead to substantial administrative, civil, and criminal penalties, including the assessment of natural resource damages, the imposition of significant investigatory and remedial obligations and may also result in the suspension or termination of our operations. The overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells and related facilities and, in turn, decreases profitability. 
+Governmental authorities regulate various aspects of drilling for and the production of crude oil, natural gas, and NGLs, including the permit and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in crude oil and natural gas properties, rights-of-way and easements, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment, and restoration standards, oil and gas operations, and restoration. Public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain projects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or impose conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or develop certain properties. Federal authorities also may require any of our ongoing or planned operations on federal leases to be delayed, suspended, or terminated. Any such delay, suspension, or termination could have a materially adverse effect on our operations. 
+Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, tribal and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, including the designation of previously unprotected wildlife or plant species as threatened or endangered in areas we operate, could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. Under existing or future environmental laws and regulations, we could incur significant liability, including joint and several, strict liability under federal, state, and tribal environmental laws for noise emissions and for discharges of crude oil, natural gas, and associated liquids or other pollutants into the air, soil, surface water, or groundwater. We could be required to spend substantial amounts on investigations, litigation, and remediation for these emissions and discharges and other compliance issues. Any unpermitted release of petroleum or other pollutants from our operations could result not only in cleanup costs, but also natural resources, real or personal property and other compensatory damages and civil and criminal liability. The listing of additional wildlife or plant species as federally endangered or threatened could result in limitations on exploration and production activities in certain locations. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a materially adverse effect on us. 
+Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. 
+Operations in certain of our regions, such as our Rocky Mountain and Permian regions, are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife or plant species. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during 
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+limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. Wildlife seasonal restrictions may limit access to federal leases or across federal lands. Possible restrictions may include seasonal restrictions in greater sage-grouse habitat during breeding and nesting seasons, within a certain distance of active raptor nests during fledging, and in big game winter or parturition ranges during winter or calving seasons. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. 
+Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. 
+Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of oil, natural gas and associated liquids from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques to many of our oil and natural gas properties, including our unconventional resource plays in the Granite Wash of Texas and Oklahoma, the Eagle Ford shale of south Texas, and the Bakken/Three Forks formations in North Dakota. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and natural gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving the use of diesel in the fluid system under SDWA and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress during prior sessions and is likely to be introduced during the 113th Congress, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. If hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit or disclosure requirements or operational restrictions and also to associated permitting delays, litigation risk, and potential cost increases. 
+Certain states that we operate in, including Pennsylvania, Texas, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (“RCT”) and the public of certain information regarding the components and volume of water used in the hydraulic fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling and/or completion of wells. 
+There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating a review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a progress report, but no research results or findings, issued in December 2012 and a draft report of results to be issued in 2014 for independent peer review by the Science Advisory Board. In addition, the United States Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the United States Department of the Interior is developing disclosure requirements or other mandates for hydraulic fracturing on federal lands; the Department of the Interior anticipates issuing during the first quarter of 2013 a revised proposed rule relating to hydraulic fracturing activities on federal lands. 
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+Additionally, certain members of Congress have called upon the United States Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the United States Securities and Exchange Commission to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the United States Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. The United States Geological Survey Offices of Energy Resources Program, Water Resources and Natural Hazards and Environmental Health Offices have ongoing research projects on hydraulic fracturing. These ongoing or proposed studies, depending on their course and outcomes, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory processes. 
+Further, on August 16, 2012, the EPA issued final rules subjecting all oil and gas operations (production, processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. The EPA rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards require the use of reduced emission completion (“REC”) techniques developed in EPA's Natural Gas STAR program along with the pit flaring of gas not sent to the gathering line beginning in January 2015. The standards are applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (“MACT”) standards for those glycol dehydrators and certain storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. The EPA stated in January 2013, however, that it intends to reconsider portions of the final rule. We are currently evaluating the effect of these rules on our business. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing such activity to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. Additional legislation or regulation could also lead to operational delays or increased costs in the exploration for and production of oil, natural gas, and associated liquids, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state, or local laws, or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and delays, which could adversely affect our financial position, results of operations, and cash flows. The EPA is in the process of updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act. Flowback and produced water from the hydraulic fracturing process contains total dissolved solids, including chlorides. The EPA anticipates issuing a draft criteria document in 2013. 
+On October 20, 2011, the EPA announced a schedule for development of standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works (“POTWs”). The regulations will be developed under the EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. The EPA anticipates issuing the proposed rules in 2014. 
+Our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations and/or completions or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules. 
+The hydraulic fracturing process on which we depend to drill for commercial quantities of crude oil, natural gas, and associated liquids requires the use and disposal of significant quantities of water. 
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+Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of natural gas. 
+Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition. 
+Certain United States federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation . 
+During his first term, President Obama sent to Congress a legislative package that included proposed legislation that, if enacted into law, would eliminate certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes included, among other proposals: 
+• 
+the repeal of the percentage depletion allowance for oil and natural gas properties; 
+• 
+the elimination of current deductions for intangible drilling and development costs; 
+• 
+the elimination of the deduction for certain domestic production activities; and 
+• 
+an extension of the amortization period for certain geological and geophysical expenditures. 
+It is unclear when or if these or similar changes will be enacted. The passage of legislation enacting these or similar changes in federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows. 
+Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for crude oil, natural gas, and NGLs. 
+In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. For example, the EPA has adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other regulates the permitting and emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011. In the courts, several cases are pending that may increase the risk of claims being filed against companies that have significant greenhouse gas emissions. Such cases seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property. Any laws or regulations that restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas that we produce. 
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+In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. 
+The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, gas, and NGLs we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition, results of operations, and cash flows. Finally, it should be noted that some scientists have predicted that increasing concentrations of greenhouse gases in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If such effects were to occur, our operations could be adversely affected. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from flooding or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. 
+The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which was signed into law on July 21, 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act also establishes margin requirements and certain transaction clearing and trade execution requirements. On October 18, 2011, the Commodities Futures Trading Commission (the “CFTC”) approved regulations to set position limits for certain futures and option contracts in the major energy markets, which were successfully challenged in federal district court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. The CFTC has filed a notice of appeal with respect to this ruling. Under CFTC final rules promulgated under the Dodd-Frank Act, we believe our derivatives activity will qualify for the non-financial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement. The Dodd-Frank Act may also require us to comply with margin requirements in our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. 
+The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in 
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+part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows. 
+Our ability to sell crude oil, natural gas and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines and other transportation systems owned or operated by others or by other interruptions. 
+The marketability of our crude oil, natural gas, and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing facilities, and pipeline and other transportation systems owned or operated by third parties. The lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay or discontinuance of development plans for our properties, or lower price realizations. Although we have some contractual control over the processing and transportation of our operated production, material changes in these business relationships could materially affect our operations. Federal and state regulation of crude oil, natural gas, and NGL production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process, and transport crude oil, natural gas, and NGLs. 
+In particular, if drilling in the Eagle Ford shale, Haynesville shale, Bakken/Three Forks resource play, and Granite Wash resource play continues to be successful, the amount of crude oil, natural gas, and NGLs being produced by us and others could exceed the capacity of, and result in strains on, the various gathering and transportation systems, pipelines, processing facilities, and other infrastructure available in these areas. It will be necessary for additional infrastructure, pipelines, gathering and transportation systems and processing facilities to be expanded, built or developed to accommodate anticipated production from these areas. Because of the current economic climate, certain processing, pipeline, and other gathering or transportation projects that might be, or are being, considered for these areas may not be developed timely or at all due to lack of financing or other constraints. Capital and other constraints could also limit our ability to build or access intrastate gathering and transportation systems necessary to transport our production to interstate pipelines or other points of sale or delivery. In such event, we might have to delay or discontinue development activities or shut in our wells to wait for sufficient infrastructure development or capacity expansion and/or sell production at significantly lower prices, which would adversely affect our results of operations and cash flows. In addition, the operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state, and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations. 
+A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily and adversely affect our cash flows and results of operations. 
+New technologies may cause our current exploration and drilling methods to become obsolete. 
+The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, 
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+and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected. 
+Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions. 
+As a crude oil, natural gas, and NGL producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows. 
+Cybersecurity attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. 
+The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for crude oil, natural gas, and NGLs, all of which could adversely affect the markets for our operations. Energy assets might be specific targets of terrorist attacks. These developments have subjected our operations to increased risk and, depending on their occurrence and ultimate magnitude, could have a material adverse effect on our business. 
+Risks Related to Our Common Stock 
+The price of our common stock may fluctuate significantly, which may result in losses for investors. 
+From January 1, 2012, to February 14, 2013 , the closing daily sale price of our common stock as reported by the New York Stock Exchange ranged from a low of $41.80 per share in August 2012 to a high of $83.35 per share in February 2012. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include: 
+• 
+changes in crude oil, natural gas, or NGL prices; 
+• 
+variations in drilling, recompletion, and operating activity; 
+• 
+changes in financial estimates by securities analysts; 
+• 
+changes in market valuations of comparable companies; 
+• 
+additions or departures of key personnel; 
+• 
+future sales of our common stock; and 
+• 
+changes in the national and global economic outlook. 
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+We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could decline as a result. 
+Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment. 
+Our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or preventing a change of control. These provisions, among other things, provide for non-cumulative voting in the election of members of the Board of Directors and impose procedural requirements on stockholders who wish to make nominations for the election of directors or propose other actions at stockholder meetings. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock. 
+Shares eligible for future sale may cause the market price of our common stock to drop significantly, even if our business is doing well. 
+The potential for sales of substantial amounts of our common stock in the public market may have a materially adverse effect on our stock price. As of February 14, 2013 , 66,153,847 shares of our common stock were freely tradable without substantial restriction or the requirement of future registration under the Securities Act of 1933. Also as of that date, options to purchase 257,180 shares of our common stock were outstanding, all of which were exercisable. These options are exercisable at prices ranging from $12.53 to $20.87 per share. In addition, restricted stock units (“RSUs”) providing for the issuance of up to a total of 493,968 shares of our common stock and 898,145 performance share units were outstanding. Performance share units are structurally the same as the previously granted Performance Share Awards or (“PSAs”) (collectively known as “Performance Share Units” or “PSUs”). The PSUs represent the right to receive, upon settlement of the PSUs after the completion of a three-year performance period, a number of shares of our common stock that may be from zero to two times the number of PSUs granted, depending on the extent to which the underlying performance criteria have been achieved and the extent to which the PSUs have vested. As of February 14, 2013 , there were 66,205,901 shares of our common stock outstanding, which is net of 50,581 treasury shares. 
+We may not always pay dividends on our common stock. 
+Payment of future dividends remains at the discretion of our Board of Directors, and will continue to depend on our earnings, capital requirements, financial condition, and other factors. In addition, the payment of dividends is subject to a covenant in our credit facility limiting our annual cash dividends to no more than $50.0 million , and to covenants in the indentures for our 2019 Notes, 2021 Notes, and 2023 Notes that limit our ability to pay dividends beyond a certain amount. Our Board of Directors may determine in the future to reduce the current semi-annual dividend rate of $0.05 per share, or discontinue the payment of dividends altogether. 
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+ITEM 1B. UNRESOLVED STAFF COMMENTS 
+We have no unresolved comments from the SEC staff regarding our periodic or current reports under the Securities Exchange Act of 1934. 
+ITEM 3. LEGAL PROCEEDINGS 
+From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. As of the filing date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows. 
+We were a defendant in litigation, captioned W.H. Sutton, et al. vs. St. Mary Land & Exploration Co., et al. , wherein the plaintiffs claimed an aggregate overriding royalty interest of 7.46875 percent in production from approximately 22,000 of our net acres in the Eagle Ford shale play in South Texas. The plaintiffs sought to quiet title to their claimed overriding royalty interest and to recover unpaid overriding royalty interest proceeds allegedly due. We believed that the claimed overriding royalty interest had been terminated under the governing agreements and the applicable law, and contested the plaintiffs’ claims. Both parties filed motions for summary judgment, and on February 8, 2011, the District Court in Webb County, Texas, issued an order granting plaintiffs’ motion for summary judgment and denying our motion for summary judgment. On September 30, 2011, the District Court entered final judgment for the plaintiffs and awarded then current damages of approximately $5.1 million, which included prejudgment interest. The District Court also awarded attorneys fees and costs to the plaintiffs. We appealed the District Court’s judgment and obtained a stay pending appeal that prevented the plaintiffs from executing on the judgment. 
+On May 23, 2012, the Fourth Court of Appeals for the State of Texas delivered its opinion in this matter, which reversed the summary judgment granted to the plaintiffs by the District Court and rendered judgment that the plaintiffs take nothing. Accordingly, based on the judgment of the Fourth Court of Appeals, the plaintiffs are not entitled to their claimed 7.46875 percent overriding royalty interest, nor are they entitled to the claimed damages related to the overriding royalty interest, attorneys fees or costs. The plaintiffs petitioned the Supreme Court of Texas for a review of the judgment of the Fourth Court of Appeals. The Supreme Court of Texas denied this petition for review on February 15, 2013, and as a result, the decision of the Fourth Court of Appeals is dispositive and its dismissal of the plaintiffs’ claims is final. 
+We also filed a declaratory judgment action in Webb County, Texas, captioned SM Energy Company vs. W.H. Sutton, et al. , seeking a judgment declaring that the lease at issue in W.H. Sutton, et al. vs. St. Mary Land & Exploration Co., et al. had terminated with respect to the remaining 18,000 acres, based upon a failure of continuous development, and that any overriding royalty interest claimed by the defendants has been extinguished. On September 19, 2012, the District Court in Webb County, Texas, granted our motion for summary judgment, concluding that the defendants’ claims for any overriding royalty interest had been extinguished. The plaintiffs filed their notice of appeal to the Fourth Court of Appeals on November 15, 2012, but due to the numerous requests for an extension, have not yet filed their brief. We will continue to contest this litigation. 
+We, and our working interest partners, filed an action against Endeavour Operating Corporation (“Endeavour”) in Harris County, Texas, captioned SM Energy Company, et al. v. Endeavour Operating Corporation , seeking an order requiring Endeavour to honor its obligations to consummate the purchase of certain assets located in Pennsylvania, or in the alternative, for damages. We are required to take reasonable measures to attempt to mitigate our potential losses, and during 2012 we initiated efforts to remarket such assets. If we are successful in such efforts and complete a sale of these assets for less than the $110 million ($80 million of which is attributable to our interest) Endeavour agreed to pay to us and our working interest partners, we will continue to prosecute this action to recover any such deficiency and any amounts expended in our efforts to remarket the assets, and to obtain any other relief to which we are entitled. As of the filing date of this report, we have no commitment from another party to purchase these assets. 
+49 
+Table of Contents 
+On January 27, 2011, Chieftain Royalty Company (“Chieftain”) filed a Class Action Petition against us in the District Court of Beaver County, Oklahoma, claiming damages related to royalty valuation on all of our Oklahoma wells. These claims include breach of contract, breach of fiduciary duty, fraud, unjust enrichment, tortious breach of contract, conspiracy, and conversion, based generally on asserted improper deduction of post-production costs. We removed this lawsuit to the United States District Court for the Western District of Oklahoma on February 22, 2011. We have responded to the petition and denied the allegations. The court has not yet ruled on Chieftain's motion to certify the putative class, and has stayed any such ruling until the United States Court of Appeals for the Tenth Circuit issues its ruling on class certification in two similar royalty class action lawsuits, where the defendants have appealed such certification. The opinion from the Tenth Circuit is expected during the summer of 2013. We believe we properly valued and paid royalty under Oklahoma law and have and will continue to vigorously defend this case. 
+ITEM 4. MINE SAFETY DISCLOSURES 
+These disclosures are not applicable to us. 
+50 
+Table of Contents 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Market Information. Our common stock is currently traded on the New York Stock Exchange under the ticker symbol “SM”. The following table presents the range of high and low intraday sales prices per share for the indicated quarterly periods in 2012 and 2011 , as reported by the New York Stock Exchange: 
+Quarter Ended 
+High 
+Low 
+December 31, 2012 
+$ 
+62.09 
+$ 
+45.25 
+September 30, 2012 
+$ 
+59.39 
+$ 
+39.44 
+June 30, 2012 
+$ 
+71.81 
+$ 
+43.12 
+March 31, 2012 
+$ 
+84.40 
+$ 
+69.40 
+December 31, 2011 
+$ 
+88.50 
+$ 
+53.45 
+September 30, 2011 
+$ 
+85.55 
+$ 
+60.52 
+June 30, 2011 
+$ 
+78.55 
+$ 
+61.37 
+March 31, 2011 
+$ 
+75.00 
+$ 
+54.59 
+PERFORMANCE GRAPH 
+The following performance graph compares the cumulative return on our common stock, for the period beginning December 31, 2007, and ending on December 31, 2012 , with the cumulative total returns of the Dow Jones U.S. Exploration and Production Board Index, and the Standard & Poor’s 500 Stock Index. 
+COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURNS 
+The preceding information under the caption Performance Graph shall be deemed to be furnished, but not filed with the Securities and Exchange Commission. 
+Holders. As of February 14, 2013 , the number of record holders of SM Energy’s common stock was 88. Based upon inquiry, management believes that the number of beneficial owners of our common stock is approximately 35,200. 
+Dividends. We have paid cash dividends to our stockholders every year since 1940. Annual dividends of $0.05 per share were paid in each of the years 1998 through 2004. Annual dividends of $0.10 per share were paid in 2005 through 2012 . We expect that our practice of paying dividends on our common stock will continue, 
+51 
+Table of Contents 
+although the payment of future dividends will continue to depend on our earnings, cash flow, capital requirements, financial condition, and other factors, including the discretion of our Board of Directors. In addition, the payment of dividends is subject to covenants in our credit facility that limit our annual dividend payment to no more than $50.0 million per year. We are also subject to certain covenants under our 2019 Senior Notes, our 2021 Senior Notes, and our 2023 Senior Notes that restrict certain payments, including dividends; provided, however, the first $6.5 million of dividends paid each year are not restricted by this covenant. Based on our current performance, we do not anticipate that these covenants will restrict future annual dividend payments of $0.10 per share of common stock. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $6.5 million in 2012 and $6.4 million in 2011 . 
+Restricted Shares. We have no restricted shares outstanding as of December 31, 2012 , aside from Rule 144 restrictions on shares held by insiders and shares issued to members of the Board of Directors under our Equity Incentive Compensation Plan (“Equity Plan”). 
+Purchases of Equity Securities by the Issuer and Affiliated Purchasers. The following table provides information about purchases by the Company and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the indicated quarters and year ended December 31, 2012 , of shares of the Company’s common stock, which is the sole class of equity securities registered by the Company pursuant to Section 12 of the Exchange Act. 
+ISSUER PURCHASES OF EQUITY SECURITIES 
+Total Number of Shares Purchased (1) 
+Average Price Paid per Share 
+Total Number of Shares Purchased as Part of Publicly Announced Program 
+Maximum Number of Shares that May Yet be Purchased Under the Program (2) 
+January 1, 2012 – 
+March 31, 2012 
+176 
+$ 
+79.93 
+— 
+3,072,184 
+April 1, 2012 - 
+June 30, 2012 
+— 
+$ 
+— 
+— 
+3,072,184 
+July 1, 2012 - 
+September 30, 2012 
+456,227 
+$ 
+47.32 
+— 
+3,072,184 
+October 1, 2012 - 
+October 31, 2012 
+— 
+$ 
+— 
+— 
+3,072,184 
+November 1, 2012 - 
+November 30, 2012 
+162 
+$ 
+49.43 
+— 
+3,072,184 
+December 1, 2012 - 
+December 31, 2012 
+158 
+$ 
+53.92 
+— 
+3,072,184 
+Total October 1, 2012 - 
+December 31, 2012 
+320 
+$ 
+51.66 
+— 
+3,072,184 
+Total 
+456,723 
+$ 
+47.34 
+— 
+3,072,184 
+(1) 
+All shares purchased in 2012 were to offset tax withholding obligations that occur upon the delivery of outstanding shares underlying RSUs and PSUs delivered under the terms of grants under the Equity Plan. 
+(2) 
+In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of this filing, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility, the indentures governing our Senior Notes and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow, or borrowings under our credit facility. The stock repurchase program may be suspended or discontinued at any time. Please refer to Dividends above for a description of our dividend limitations. 
+52 
+Table of Contents 
+ITEM 6. SELECTED FINANCIAL DATA 
+The following table sets forth selected supplemental financial and operating data for us as of the dates and periods indicated. The financial data for each of the five years presented were derived from our consolidated financial statements. The following data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report, which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our consolidated financial statements included in this report. 
+Years Ended December 31, 
+2012 
+2011 
+2010 
+2009 
+2008 
+(in millions, except per share data) 
+Total operating revenues 
+$ 
+1,505.1 
+$ 
+1,603.3 
+$ 
+1,092.8 
+$ 
+832.2 
+$ 
+1,301.3 
+Net income (loss) 
+$ 
+(54.2 
+) 
+$ 
+215.4 
+$ 
+196.8 
+$ 
+(99.4 
+) 
+$ 
+87.3 
+Net income (loss) per share: 
+Basic 
+$ 
+(0.83 
+) 
+$ 
+3.38 
+$ 
+3.13 
+$ 
+(1.59 
+) 
+$ 
+1.40 
+Diluted 
+$ 
+(0.83 
+) 
+$ 
+3.19 
+$ 
+3.04 
+$ 
+(1.59 
+) 
+$ 
+1.38 
+Total assets at year-end 
+$ 
+4,199.5 
+$ 
+3,799.0 
+$ 
+2,744.3 
+$ 
+2,360.9 
+$ 
+2,697.2 
+Long-term debt: 
+Line of credit 
+$ 
+340.0 
+$ 
+— 
+$ 
+48.0 
+$ 
+188.0 
+$ 
+300.0 
+3.50% Senior Convertible Notes, net of debt discount 
+$ 
+— 
+$ 
+285.1 
+$ 
+275.7 
+$ 
+266.9 
+$ 
+258.7 
+6.625% Senior Notes due 2019 
+$ 
+350.0 
+$ 
+350.0 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+6.50% Senior Notes due 2021 
+$ 
+350.0 
+$ 
+350.0 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+6.50% Senior Notes due 2023 
+$ 
+400.0 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Cash dividends declared and paid per common share 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+53 
+Table of Contents 
+Supplemental Selected Financial and Operations Data 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+2009 
+2008 
+Balance Sheet Data (in millions) 
+Total working capital (deficit) 
+$ 
+(201.0 
+) 
+$ 
+(42.6 
+) 
+$ 
+(227.4 
+) 
+$ 
+(87.6 
+) 
+$ 
+15.2 
+Total stockholders’ equity 
+$ 
+1,414.5 
+$ 
+1,462.9 
+$ 
+1,218.5 
+$ 
+973.6 
+$ 
+1,162.5 
+Weighted-average common shares outstanding (in thousands) 
+Basic 
+65,138 
+63,755 
+62,969 
+62,457 
+62,243 
+Diluted 
+65,138 
+67,564 
+64,689 
+62,457 
+63,133 
+Reserves 
+Oil (MMBbl) 
+92.2 
+71.7 
+57.4 
+53.8 
+51.4 
+Gas (Bcf) 
+833.4 
+664.0 
+640.0 
+449.5 
+557.4 
+NGLs (MMBbl) 
+62.3 
+27.5 
+— 
+— 
+— 
+BCFE 
+1,760.6 
+1,259.2 
+984.5 
+772.2 
+865.5 
+Production and Operational (in millions) 
+Oil, gas, and NGL production revenues 
+$ 
+1,473.9 
+$ 
+1,332.4 
+$ 
+836.3 
+$ 
+616.0 
+$ 
+1,259.4 
+Oil, gas, and NGL production expenses 
+$ 
+391.9 
+$ 
+290.1 
+$ 
+195.1 
+$ 
+206.8 
+$ 
+271.4 
+DD&A 
+$ 
+727.9 
+$ 
+511.1 
+$ 
+336.1 
+$ 
+304.2 
+$ 
+314.3 
+General and administrative 
+$ 
+119.8 
+$ 
+118.5 
+$ 
+106.7 
+$ 
+76.0 
+$ 
+79.5 
+Production Volumes 
+Oil (MMBbl) 
+10.4 
+8.1 
+6.4 
+6.3 
+6.6 
+Gas (Bcf) 
+120.0 
+100.3 
+71.9 
+71.1 
+74.9 
+NGLs (MMBbl) 
+6.1 
+3.5 
+— 
+— 
+— 
+BCFE 
+218.9 
+169.7 
+110.0 
+109.1 
+114.6 
+Realized price 
+Oil (per Bbl) 
+$ 
+85.45 
+$ 
+88.23 
+$ 
+72.65 
+$ 
+54.40 
+$ 
+92.99 
+Gas (per Mcf) 
+$ 
+2.98 
+$ 
+4.32 
+$ 
+5.21 
+$ 
+3.82 
+$ 
+8.60 
+NGL (per Bbl) 
+$ 
+37.61 
+$ 
+53.32 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Adjusted price (net of derivative cash settlements) 
+Oil (per Bbl) 
+$ 
+83.52 
+$ 
+78.89 
+$ 
+66.85 
+$ 
+56.74 
+$ 
+75.59 
+Gas (per Mcf) 
+$ 
+3.48 
+$ 
+4.80 
+$ 
+6.05 
+$ 
+5.59 
+$ 
+8.79 
+NGL (per Bbl) 
+$ 
+38.90 
+$ 
+47.90 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Expense per MCFE 
+LOE 
+$ 
+0.82 
+$ 
+0.88 
+$ 
+1.10 
+$ 
+1.33 
+$ 
+1.46 
+Transportation 
+$ 
+0.63 
+$ 
+0.51 
+$ 
+0.19 
+$ 
+0.19 
+$ 
+0.19 
+Production taxes 
+$ 
+0.33 
+$ 
+0.32 
+$ 
+0.48 
+$ 
+0.37 
+$ 
+0.71 
+DD&A 
+$ 
+3.32 
+$ 
+3.01 
+$ 
+3.06 
+$ 
+2.79 
+$ 
+2.74 
+General and administrative 
+$ 
+0.55 
+$ 
+0.70 
+$ 
+0.97 
+$ 
+0.70 
+$ 
+0.69 
+Statement of Cash Flow Data (in millions) 
+Provided by operations 
+$ 
+922.0 
+$ 
+760.5 
+$ 
+497.1 
+$ 
+436.1 
+$ 
+679.2 
+(Used in) investing 
+$ 
+(1,457.3 
+) 
+$ 
+(1,264.9 
+) 
+$ 
+(361.6 
+) 
+$ 
+(304.1 
+) 
+$ 
+(673.8 
+) 
+Provided by (used in) financing 
+$ 
+422.1 
+$ 
+618.5 
+$ 
+(141.1 
+) 
+$ 
+(127.5 
+) 
+$ 
+(42.8 
+) 
+Note: 2010 and prior NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of the amounts. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices in Part II, Item 7 of this report. 
+54 
+Table of Contents 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+This discussion includes forward-looking statements. Please refer to Cautionary Information about Forward-Looking Statements in Part I, Items 1 and 2 of this report for important information about these types of statements. 
+Overview of the Company 
+General Overview 
+We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America. Our assets include leading positions in the Eagle Ford shale and Bakken/Three Forks resource plays, as well as exposure to the Granite Wash play and emerging oil-focused plays in the Permian Basin. We have built a portfolio of onshore properties in the contiguous United States primarily through early entry into existing and emerging resource plays. This portfolio is comprised of properties with established production and reserves, prospective drilling opportunities, and unconventional resource prospects. We believe our strategy provides for stable and predictable production and reserve growth. Furthermore, by entering these plays early, we believe we can capture larger resource potential at a lower cost. 
+Our principal business strategy is to focus on the early capture of resource plays in order to create and then enhance value for our shareholders while maintaining a strong balance sheet. We strive to leverage industry-leading exploration and leasehold acquisition teams to quickly acquire and test new resource play concepts at a reasonable cost. Once we have identified potential value through these efforts, our goal is to develop such potential through top-tier operational and project execution and to mitigate our risks by selectively divesting of certain assets when deemed appropriate by us. We continually examine our portfolio for opportunities to improve the quality of our asset base in order to optimize our returns and preserve our financial strength. 
+In 2012 we had the following financial and operational results: 
+• 
+At year-end 2012 , we had estimated proved reserves of 1,760.6 BCFE ( 293.4 MMBOE), of which 53 percent were liquids (oil and NGLs) and 57 percent was characterized as proved developed. We added 900.2 BCFE from our drilling program, the majority of which related to our activity in the Eagle Ford shale in South Texas and the Bakken/Three Forks plays in North Dakota. We had negative price revisions that decreased our estimated proved reserves by 72.7 BCFE primarily due to gas weighted projects in our South Texas & Gulf Coast and Mid-Continent regions that do not generate positive cash flow utilizing historical 12-month average benchmark pricing required by the SEC. The prices used in the calculation of proved reserve estimates as of December 31, 2012 , were $94.71 per Bbl, $2.76 per MMBtu, and $45.65 per Bbl, for oil, gas, and NGLs, respectively. These prices were two percent , 33 percent , and 23 percent lower for oil, gas, and NGLs, respectively, than the prices used at year-end 2011 . We had downward engineering revisions of 49.2 BCFE related primarily to Eagle Ford shale proved undeveloped locations as well as downward engineering revisions of Wolfberry assets in our Permian region. Additionally, we removed 42.7 BCFE of proved undeveloped reserves primarily in the Woodford shale due to low natural gas prices and as a result of the five-year limitation on the number of years proved undeveloped reserves may remain on the books without being developed. Please refer to the caption Proved Undeveloped Reserves under the section Reserves included in Part I, Items 1 and 2 of this report for additional discussion. We had immaterial acquisitions of 1.6 BCFE, and we divested of 16.9 BCFE of proved reserves during the year related to non-core assets located primarily in our Rocky Mountain and Mid-Continent regions. 
+55 
+Table of Contents 
+• 
+The PV-10 value of our estimated proved reserves was $3.8 billion as of December 31, 2012 , compared with $3.5 billion as of December 31, 2011 . The after tax value, represented by the standardized measure calculation, was $3.0 billion as of December 31, 2012 compared with $2.6 billion as of December 31, 2011 . The standardized measure calculation is presented in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown under Reserves in Part I, Items 1 and 2 of this report. 
+• 
+We had record production in 2012 . Our average daily production in 2012 was 28.3 MBbl of oil, 328.0 MMcf of gas, and 16.7 MBbl of NGLs, for an average equivalent production rate of 598.2 MMCFE, compared with 465.0 MMCFE in 2011 , an increase of 29 percent year-over-year. Please refer to the caption Production Results below for additional discussion. 
+• 
+We recorded a net loss of $54.2 million , or a loss of $0.83 per diluted share, for the year ended December 31, 2012 , due to an impairment of proved properties. This compares with net income of $215.4 million , or $3.19 per diluted share, for the year ended December 31, 2011 . Please refer to the caption Comparison of Financial Results and Trends Between 2012 and 2011 below for additional discussion regarding the components of net income (loss) and 2012 Highlights for additional discussion on impairment of proved properties. 
+• 
+We had record cash flow provided by operating activities of $922.0 million for the year ended December 31, 2012 , compared with $760.5 million for the year ended December 31, 2011 , which was an increase of 21 percent year-over-year. Please refer to Analysis of cash flow changes between 2012 and 2011 below for additional discussion. 
+• 
+Costs incurred for oil and gas producing activities for the year ended December 31, 2012 , were $1.7 billion , compared with $1.6 billion for the same period in 2011 . Please refer to the caption Costs Incurred in Oil and Gas Producing Activities below for additional discussion. 
+• 
+EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2012 , was $1.0 billion , compared with $886.6 million for the same period in 2011 . Please refer to the caption Non-GAAP Financial Measures below for additional discussion, including our definition of EBITDAX and reconciliations of our GAAP net income (loss) and net cash provided by operating activities to EBITDAX. 
+Reserve Replacement, Finding and Development Costs, and Growth 
+Like all oil and gas exploration and production companies, we face the challenge of growing proved reserves. An exploration and production company depletes part of its asset base with each unit of oil, gas, or NGL it produces. Our future growth will depend on our ability to organically and economically add reserves in excess of production. 
+56 
+Table of Contents 
+The following table provides various reserve replacement and finding and development cost metrics for the year ended December 31, 2012 : 
+Reserve Replacement Percentage 
+Finding and Development Cost per MCFE (1) 
+Excluding Divestitures 
+Including Divestitures 
+Excluding Divestitures 
+Including Divestitures 
+Drilling, excluding revisions 
+411 
+% 
+403 
+% 
+$ 
+1.74 
+$ 
+1.77 
+Drilling, including revisions 
+336 
+% 
+328 
+% 
+$ 
+2.13 
+$ 
+2.18 
+Drilling and acquisitions, excluding revisions 
+412 
+% 
+404 
+% 
+$ 
+1.74 
+$ 
+1.78 
+Drilling and acquisitions, including revisions 
+337 
+% 
+329 
+% 
+$ 
+2.13 
+$ 
+2.18 
+Reserve Acquisitions 
+1 
+% 
+N/M 
+$ 
+3.59 
+N/M 
+All-in 
+337 
+% 
+329 
+% 
+$ 
+2.29 
+$ 
+2.34 
+* N/M – Percentage or amount, as applicable, is not meaningful. 
+(1) Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement for discussion on how we are being carried on 90 percent of certain drilling and completion costs. 
+The following table provides average reserve replacement and finding and development cost metrics for the three-year period ended December 31, 2012 : 
+Reserve Replacement Percentage 
+Finding and Development Cost per MCFE (1) 
+Excluding Divestitures 
+Including Divestitures 
+Excluding Divestitures 
+Including Divestitures 
+Drilling, excluding revisions 
+363 
+% 
+324 
+% 
+$ 
+2.15 
+$ 
+2.41 
+Drilling, including revisions 
+337 
+% 
+298 
+% 
+$ 
+2.31 
+$ 
+2.62 
+Drilling and acquisitions, excluding revisions 
+363 
+% 
+324 
+% 
+$ 
+2.15 
+$ 
+2.41 
+Drilling and acquisitions, including revisions 
+338 
+% 
+298 
+% 
+$ 
+2.31 
+$ 
+2.62 
+Reserve Acquisitions 
+N/M 
+N/M 
+$ 
+3.52 
+N/M 
+All-in 
+338 
+% 
+298 
+% 
+$ 
+2.45 
+$ 
+2.77 
+* N/M – Percentage or amount, as applicable, is not meaningful. 
+(1) Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement for discussion on how we are being carried on 90 percent of certain drilling and completion costs. 
+Our challenge is to grow net asset value per share, which we believe drives appreciation in our stock price over the long term. To accomplish this, we believe it is important to organically and economically replace annual production with new reserves. We believe annual reserve replacement percentage and finding and development costs are important analytical measures that are widely used by investors and industry peers in evaluating and comparing the performance of oil and gas companies. While single-year measurements have some meaning in terms of a trend, we believe aberrations, causing both positive and negative results, will occur over short intervals of time. The information used to calculate the above reserve replacement and finding and development cost metrics is included in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. For additional information about these metrics, see the reserve replacement and finding and development cost terms in the Glossary of Oil and Gas Terms at the end of Part I, Items 1 and 2 of this report. 
+Oil, Gas, and NGL Prices 
+Our financial condition and the results of our operations are significantly affected by the prices we receive for oil, gas, and NGL production, which can fluctuate dramatically. We sell the majority of our natural gas under contracts using first-of-the-month index pricing, which means gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day the gas is produced. For assets where high BTU gas is sold 
+57 
+Table of Contents 
+at the wellhead, we also receive additional value for the high energy content contained in the gas stream. Our NGL production is generally sold using contracts paying us a monthly average of the posted OPIS daily settlement prices, adjusted for processing, transportation, and location differentials. Our oil and condensate are sold using contracts paying us either the average of the NYMEX WTI daily settlement price or the average of alternative posted prices for the periods in which the product is produced, adjusted for quality, transportation, and location differentials. 
+Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head. As a result, we reported realized prices for our natural gas production for periods through December 31, 2010, that were higher than industry benchmarks due to the price uplift associated with incremental value contained in the higher BTU content of our produced gas stream. Beginning in 2011, we changed our reporting for natural gas volumes to show natural gas and NGL production volumes consistent with title transfer for each product. Projected rapid production growth from our NGL-rich assets associated with plant product sales contracts necessitated a change in our reporting of production volumes. Our 2010 production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of the NGL volumes produced in that period. 
+The following table is a summary of commodity price data for the years ended December 31, 2012 , 2011 , and 2010 : 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+Crude Oil (per Bbl): 
+Average NYMEX price 
+$ 
+94.10 
+$ 
+95.05 
+$ 
+79.51 
+Realized price 
+$ 
+85.45 
+$ 
+88.23 
+$ 
+72.65 
+Natural Gas: 
+Average NYMEX price (per MMBtu) 
+$ 
+2.75 
+$ 
+4.00 
+$ 
+4.37 
+Realized price (per Mcf) 
+$ 
+2.98 
+$ 
+4.32 
+$ 
+5.21 
+NGLs (per Bbl): 
+Average OPIS price 
+$ 
+44.91 
+$ 
+59.47 
+$ 
+34.61 
+Realized price 
+$ 
+37.61 
+$ 
+53.32 
+N/A 
+Note: 2010 NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of NGL volumes. Please refer to additional discussion above. Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent the Company’s product mix for NGL production. The Company's actual product mix is reflected in actual prices received for NGLs produced. 
+We expect future prices for oil, gas, and NGLs to be volatile. In addition to supply and demand fundamentals, as a global commodity, the price of oil will likely continue to be impacted by real or perceived geopolitical risks in oil producing regions of the world, particularly in the Middle East. The relative strength of the U.S. dollar compared to other currencies could also affect the price of oil. The supply of NGLs in the U.S. is expected to continue to grow in the near term as a result of the number of industry participants targeting projects that produce these products. The pace of NGL production is growing faster than the capacity to process or consume NGLs, which will likely negatively impact pricing in the near term. The prices of several of the specific NGL products correlate to the price of oil and accordingly are likely to directionally follow that market. Gas prices have been under downward pressure for several years due to market oversupply resulting from continued high levels of natural gas production and insufficient demand for natural gas as a result of tepid economic growth, although gas prices increased moderately in the last half of 2012. The 12-month strip prices for NYMEX WTI oil, NYMEX 
+58 
+Table of Contents 
+Henry Hub gas, and OPIS NGLs (same product mix as discussed above) as of December 31, 2012 , were $93.19 per Bbl of oil, $3.60 per MMBtu of gas, and $41.20 per Bbl of NGLs, respectively. Comparable prices as of February 14, 2013 , were $98.38 per Bbl, $3.51 per MMBtu, and $41.03 per Bbl, respectively. 
+While changes in quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products. Consistent with all prior periods reported, our realized prices shown in the table above do not include the impact of cash settlements from derivative contracts. 
+Derivative Activity 
+We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives. The amount of our production covered by derivatives is driven by the amount of debt on our balance sheet and the level of capital commitments and long-term obligations we have in place. With our current derivative contracts, we believe we have established a base cash flow stream for our future operations and have partially reduced our exposure to volatility in commodity prices. We utilize swaps as well as costless collars for a portion of our derivatives since collars allow us to participate in some of the upward movements in oil, gas, and NGL prices while also setting a price floor for a portion of our production. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional information regarding our oil, gas, and NGL derivatives, and the caption, Summary of Oil, Gas, and NGL Derivative Contracts in Place, below. 
+The following table presents a reconciliation from our realized price to our adjusted price for the commodities indicated, including the effects of derivative cash settlements, for 2012 , 2011 , and 2010 : 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+Crude Oil (per Bbl): 
+Realized price 
+$ 
+85.45 
+$ 
+88.23 
+$ 
+72.65 
+Less the effects of derivative cash settlements 
+(1.93 
+) 
+(9.34 
+) 
+(5.80 
+) 
+Adjusted price, including the effects of derivative cash settlements 
+$ 
+83.52 
+$ 
+78.89 
+$ 
+66.85 
+Natural Gas (per Mcf): 
+Realized price 
+$ 
+2.98 
+$ 
+4.32 
+$ 
+5.21 
+Add the effects of derivative cash settlements 
+0.50 
+0.48 
+0.84 
+Adjusted price, including the effects of derivative cash settlements 
+$ 
+3.48 
+$ 
+4.80 
+$ 
+6.05 
+Natural Gas Liquids (per Bbl): 
+Realized price 
+$ 
+37.61 
+$ 
+53.32 
+$ 
+— 
+Add (less) the effects of derivative cash settlements 
+1.29 
+(5.42 
+) 
+— 
+Adjusted price, including the effects of derivative cash settlements 
+$ 
+38.90 
+$ 
+47.90 
+$ 
+— 
+Note: 2010 NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of the volumes. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices above. 
+The Dodd-Frank Act included provisions requiring over-the-counter derivative transactions to be executed through an exchange or centrally cleared. On July 10, 2012, the CFTC and the SEC adopted final joint rules under Title VII of the Dodd-Frank Act, which define certain terms and determine what types of transactions will be subject to heightened scrutiny under the Dodd-Frank Act swap rules. The issuance of these final rules also triggers compliance dates for a number of other final Dodd-Frank Act rules, including new rules proposed by the CFTC governing margin requirements for uncleared swaps entered into by non-bank swap entities, and new rules proposed 
+59 
+Table of Contents 
+by U.S. banking regulators regarding margin requirements for uncleared swaps entered into by bank swap entities. The ultimate effect on our business of these new rules and any additional regulations is currently uncertain. Under CFTC rules we believe our derivative activity will qualify for the non-financial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement. However, we are not certain whether the provisions of the final rules and regulations will exempt us from the requirements to post margin in connection with commodity price risk management activities. Final rules and regulations on major provisions of the legislation, such as new margin requirements, are to be established through regulatory rulemaking. Although we cannot predict the ultimate outcome of these rulemakings, new rules and regulations in this area may result in increased costs and cash collateral requirements for the types of derivative instruments we use to manage our financial risks related to volatility in oil, gas, and NGL commodity prices. 
+2012 Highlights 
+Operational Activities. We operated between 15 and 18 drilling rigs company-wide for most of 2012 . The primary focus of our operated drilling activity this year was oil and NGL-rich gas projects. We also participated in non-operated drilling activity primarily in oil and NGL-rich plays. 
+In our Eagle Ford shale program in South Texas, we operated six rigs throughout most of 2012 until releasing one of our operated rigs at the end of the third quarter due to increased drilling rig efficiencies. We focused our drilling in areas with higher BTU gas content and condensate yields. We believe we have secured most of the requisite services, such as gas pipeline takeaway capacity and drilling and completion services, to support our current development plans. We will continue to explore additional arrangements to facilitate the continued growth of our operated program. Please refer to Note 6 – Commitments and Contingencies under Part II, Item 8 of this report and Delivery Commitments and Core Operational Areas under Part I, Items 1 and 2 of this report for additional discussion concerning these agreements. 
+In our non-operated Eagle Ford program, the operator had nine drilling rigs and one spudder rig running throughout 2012 . We expect the majority of our non-operated Eagle Ford drilling and completion costs to be funded by Mitsui over approximately the next two years under the terms of our previously announced Acquisition and Development Agreement. 
+We started 2012 operating three drilling rigs in our Bakken/Three Forks program in the North Dakota portion of the Williston Basin and increased to four drilling rigs in the third quarter, focusing on our Gooseneck, Raven, and Bear Den prospects. In the southern portion of our Rocky Mountain region, we operated one rig testing various formations in the Powder River Basin of Wyoming as part of our exploration program. 
+Effective January 1, 2012, we combined our ArkLaTex region into our Mid-Continent region, based in Tulsa, Oklahoma, for operational and reporting purposes. Throughout 2012 , we operated three drilling rigs in our Granite Wash program in western Oklahoma and the Texas Panhandle, focusing primarily on the Marmaton washes due to their higher oil and NGL content. Essentially all of our acreage position in this play is held by production. We completed our operated Haynesville shale program early in the year after achieving held by production status on substantially all of our acreage. 
+In our Permian region, we began the year with one operated rig and increased to four during the third quarter of 2012, with two of the rigs testing the Mississippian limestone formation on our properties in the northeast Midland Basin where we have approximately 65,500 net acres. A third rig focused on the Bone Spring formation on our properties in New Mexico. Finally, the fourth rig operated in the Midland Basin, focusing on testing the Leonard shale. We added approximately 38,000 net acres to our Permian Basin Texas acreage position in 2012. 
+60 
+Table of Contents 
+Production Results. The table below provides a regional breakdown of our 2012 production: 
+South Texas & Gulf Coast 
+Rocky 
+Mountain 
+Mid-Continent 
+Permian 
+Total (1) 
+Production: 
+Oil (MMBbl) 
+3.2 
+5.4 
+0.4 
+1.3 
+10.4 
+Gas (Bcf) 
+59.1 
+4.4 
+53.4 
+3.2 
+120.0 
+NGLs (MMBbl) 
+5.7 
+— 
+0.4 
+— 
+6.1 
+BCFE (1) 
+112.7 
+36.9 
+58.1 
+11.3 
+218.9 
+Avg. Daily Equivalents 
+(MMCFE/d) 
+307.9 
+100.9 
+158.6 
+30.8 
+598.2 
+Relative percentage 
+51 
+% 
+17 
+% 
+27 
+% 
+5 
+% 
+100 
+% 
+(1) Totals may not sum or recalculate due to rounding. 
+We had record production in 2012 , which was primarily driven by the development of our operated and non-operated Eagle Ford shale programs in our South Texas & Gulf Coast region. Please refer to Comparison of Financial Results and Trends between 2012 and 2011 below for additional discussion on production. 
+Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows: 
+For the Year Ended December 31, 2012 
+(in millions) 
+Development costs 
+$ 
+1,346.2 
+Exploration costs 
+220.9 
+Acquisitions 
+Proved properties 
+5.8 
+Unproved properties 
+115.0 
+Total, including asset retirement obligation 
+$ 
+1,687.9 
+The majority of costs incurred for oil and gas producing activities during 2012 related to the development of our Eagle Ford shale and Bakken/Three Forks programs. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital program in 2013. 
+Impairment of Proved Properties. We recorded impairment of proved properties expense of $208.9 million for the year ended December 31, 2012 , related to the write-down of our Wolfberry assets in our Permian region due to downward engineering revisions, as well as write-downs of our Haynesville shale assets due to low natural gas prices. 
+Divestiture Activity and Unsuccessful Sale of Properties . During 2012, we divested of various non-strategic properties located in our Rocky Mountain and Mid-Continent regions for $57.4 million in total divestiture proceeds. Additionally in 2012, we reclassified assets located in both regions that were previously classified as held for sale to assets held and used, as these assets were no longer being actively marketed, which resulted in a $33.9 million non-cash loss. Please refer to Note 3 - Divestitures and Assets Held for Sale in Part II, Item 8 of this report for additional discussion. 
+61 
+Table of Contents 
+Equity Compensation. During 2012, we granted 379,332 RSUs and 314,853 PSUs pursuant to our long-term equity compensation program. Additionally, we issued 929,375 shares of our common stock to settle PSU and RSU awards granted in previous years. Please refer to Note 7 - Compensation Plans in Part II, Item 8 of this report for additional discussion. 
+3.50% Senior Convertible Notes . In April 2012, we called for the redemption of our outstanding 3.50% Senior Convertible Notes, which triggered the conversion feature of these notes. We settled the principal amount of all converted 3.50% Senior Convertible Notes in cash with the excess value settled in shares of common stock, and settled all redeemed notes in cash. Please refer to Note 5 - Long-term Debt in Part II, Item 8 of this report for additional discussion. 
+2023 Notes . In June 2012, we issued $400.0 million in aggregate principal amount of 6.50% Senior Notes. The notes were issued at par and mature on January 1, 2023. We received net proceeds of $392.1 million from this issuance, which we used to pay down outstanding borrowings under our credit facility. Please refer to Note 5 - Long-term Debt in Part II, Item 8 of this report for additional discussion. 
+Marketing of Properties . During the second quarter of 2012, we began to re-market our Marcellus shale assets located in Pennsylvania. Please refer to Note 3 - Divestitures and Assets Held for Sale in Part II, Item 8 of this report, as well as Legal Proceedings in Part I, Item 3 of this report for additional discussion. 
+Credit Facility. In the third quarter of 2012, the borrowing base under our credit facility was increased by our lenders to $1.55 billion from $1.4 billion . Please refer to Overview of Liquidity and Capital Resources below for additional discussion. 
+Outlook for 2013 
+We enter 2013 with a capital program of approximately $1.5 billion, of which approximately $1.2 billion will be focused on drilling and completion activities. We expect that approximately 90 percent of our drilling budget will be spent on our operated Eagle Ford shale, Bakken/Three Forks and operated Permian programs. 
+In 2013 , we plan to invest approximately $650 million of drilling and completion capital in our operated Eagle Ford shale play. Throughout 2013, we plan to operate five drilling rigs supported by two frac spreads, all of which will be primarily focused on pad drilling in the northern portion of our acreage position where there is a higher liquid contribution to our production mix. In 2013, our firm contracted wet gas takeaway capacity will increase with the addition of incremental capacity on existing pipelines and the addition of a third pipeline with firm transportation capacity contracted to begin in the third quarter. During 2013 , we plan to continue to refine our development program and well designs to optimize well performance and capital efficiency. 
+In our non-operated Eagle Ford shale program, the operator is currently operating nine drilling rigs and one spudder rig. Based on the operator’s stated plans, our expectation is that the number of rigs will decrease to eight drilling rigs and one spudder rig during the year. Mitsui will carry the majority of our non-operated drilling activity through 2013, so we expect to deploy minimal drilling and completion capital in this program. Costs associated with items such as infrastructure are not carried by Mitsui, and we will be responsible for our proportionate share of those costs. 
+We plan to deploy $290 million of our capital budget in our Bakken/Three Forks program in the Williston Basin in 2013. Currently, we are operating four drilling rigs in this program and plan to operate an average of 3.5 drilling rigs throughout the year. Our plan with these rigs is to continue infill drilling in our three focus areas and leverage efficiencies through pad drilling. 
+62 
+Table of Contents 
+In our Permian program, we plan to deploy approximately $170 million of drilling and completion capital. Our program will focus two drilling rigs in our Mississippian limestone play as we continue to delineate our position of approximately 65,500 net acres. During the year, we will also continue to run an exploratory program in the Midland Basin testing various shale formations. 
+The remaining $90 million of our drilling and completion capital planned for this year will be deployed in our operated Granite Wash program and various other operated and non-operated programs. Our Granite Wash program will have one to two operated rigs, while the remainder of the activity will be in our exploration plays, including on our Powder River Basin acreage. 
+Please refer to Overview of Liquidity and Capital Resources for additional discussion regarding how we intend to fund our 2013 capital program. 
+Financial Results of Operations and Additional Comparative Data 
+The table below provides information regarding selected production and financial information for the quarter ended December 31, 2012 , and the immediately preceding three quarters. Additional details of per MCFE costs are presented later in this section. 
+For the Three Months Ended 
+December 31, 
+September 30, 
+June 30, 
+March 31, 
+2012 
+2012 
+2012 
+2012 
+(in millions, except for production data) 
+Production (BCFE) 
+60.7 
+57.0 
+50.6 
+50.7 
+Oil, gas, and NGL production revenue 
+$ 
+424.7 
+$ 
+373.9 
+$ 
+312.6 
+$ 
+362.6 
+Realized hedge gain 
+$ 
+1.5 
+$ 
+0.5 
+$ 
+0.2 
+$ 
+1.7 
+Gain (loss) on divestiture activity 
+$ 
+4.2 
+$ 
+(8.5 
+) 
+$ 
+(24.2 
+) 
+$ 
+1.5 
+Lease operating expense 
+$ 
+48.0 
+$ 
+46.5 
+$ 
+46.1 
+$ 
+39.4 
+Transportation costs 
+$ 
+43.0 
+$ 
+37.0 
+$ 
+30.3 
+$ 
+28.6 
+Production taxes 
+$ 
+20.2 
+$ 
+18.9 
+$ 
+14.7 
+$ 
+19.1 
+DD&A 
+$ 
+204.3 
+$ 
+192.4 
+$ 
+161.6 
+$ 
+169.6 
+Exploration 
+$ 
+24.2 
+$ 
+25.4 
+$ 
+22.0 
+$ 
+18.6 
+Impairment of proved properties 
+$ 
+170.4 
+$ 
+— 
+$ 
+38.5 
+$ 
+— 
+Abandonment and impairment of unproved properties 
+$ 
+5.0 
+$ 
+0.4 
+$ 
+10.7 
+$ 
+0.1 
+General and administrative 
+$ 
+28.4 
+$ 
+32.2 
+$ 
+31.1 
+$ 
+28.1 
+Change in Net Profits Plan liability 
+$ 
+(11.6 
+) 
+$ 
+0.8 
+$ 
+(22.1 
+) 
+$ 
+3.9 
+Unrealized and realized derivative (gain) loss 
+$ 
+(15.6 
+) 
+$ 
+55.9 
+$ 
+(98.1 
+) 
+$ 
+2.2 
+Net income (loss) 
+$ 
+(67.1 
+) 
+$ 
+(38.3 
+) 
+$ 
+24.9 
+$ 
+26.3 
+63 
+Table of Contents 
+Selected Performance Metrics: 
+For the Three Months Ended 
+December 31, 
+September 30, 
+June 30, 
+March 31, 
+2012 
+2012 
+2012 
+2012 
+Average net daily production equivalent (MMCFE per day) 
+659.6 
+619.6 
+555.7 
+557.0 
+Lease operating expense (per MCFE) 
+$ 
+0.79 
+$ 
+0.82 
+$ 
+0.91 
+$ 
+0.78 
+Transportation costs (per MCFE) 
+$ 
+0.71 
+$ 
+0.65 
+$ 
+0.60 
+$ 
+0.56 
+Production taxes as a percent of oil, gas, and NGL production revenue 
+4.8 
+% 
+5.1 
+% 
+4.7 
+% 
+5.3 
+% 
+Depletion, depreciation and amortization and asset retirement obligation liability accretion (per MCFE) 
+$ 
+3.37 
+$ 
+3.38 
+$ 
+3.20 
+$ 
+3.35 
+General and administrative (per MCFE) 
+$ 
+0.47 
+$ 
+0.56 
+$ 
+0.62 
+$ 
+0.56 
+64 
+Table of Contents 
+A year-to-year overview of selected production and financial information, including trends: 
+As of and for the Years Ended December 31, 
+Amount Change Between 
+Percent Change Between 
+2012 
+2011 
+2010 
+2012/2011 
+2011/2010 
+2012/2011 
+2011/2010 
+Net production volumes (1) 
+Oil (MMBbl) 
+10.4 
+8.1 
+6.4 
+2.3 
+1.7 
+28 
+% 
+27 
+% 
+Gas (Bcf) 
+120.0 
+100.3 
+71.9 
+19.7 
+28.5 
+20 
+% 
+40 
+% 
+NGLs (MMBbl) 
+6.1 
+3.5 
+— 
+2.6 
+3.5 
+75 
+% 
+N/A 
+BCFE 
+218.9 
+169.7 
+110.0 
+49.2 
+59.7 
+29 
+% 
+54 
+% 
+Average net daily production (1) 
+Oil (MBbl per day) 
+28.3 
+22.1 
+17.4 
+6.2 
+4.7 
+28 
+% 
+27 
+% 
+Gas (MMcf per day) 
+328.0 
+274.8 
+196.9 
+53.1 
+78.0 
+19 
+% 
+40 
+% 
+NGLs (MBbl per day) 
+16.7 
+9.6 
+— 
+7.1 
+9.6 
+75 
+% 
+N/A 
+Equivalent (MMCFE per day) 
+598.2 
+465.0 
+301.4 
+133.2 
+163.6 
+29 
+% 
+54 
+% 
+Oil, gas, and NGL production revenues (in millions) 
+Oil production revenue 
+$ 
+886.2 
+$ 
+712.8 
+$ 
+461.9 
+$ 
+173.4 
+$ 
+250.9 
+24 
+% 
+54 
+% 
+Gas production revenue 
+$ 
+357.7 
+$ 
+433.4 
+$ 
+374.4 
+$ 
+(75.7 
+) 
+$ 
+59.0 
+(17 
+)% 
+16 
+% 
+NGL production revenue 
+$ 
+230.0 
+$ 
+186.2 
+$ 
+— 
+$ 
+43.8 
+$ 
+186.2 
+24 
+% 
+N/A 
+Total 
+$ 
+1,473.9 
+$ 
+1,332.4 
+$ 
+836.3 
+$ 
+141.5 
+$ 
+496.1 
+11 
+% 
+59 
+% 
+Oil, gas, and NGL production expense (in millions) 
+Lease operating expenses 
+$ 
+180.1 
+$ 
+149.8 
+$ 
+121.5 
+$ 
+30.3 
+$ 
+28.3 
+20 
+% 
+23 
+% 
+Transportation costs 
+$ 
+138.9 
+$ 
+86.4 
+$ 
+21.2 
+$ 
+52.5 
+$ 
+65.2 
+61 
+% 
+308 
+% 
+Production taxes 
+$ 
+72.9 
+$ 
+53.9 
+$ 
+52.4 
+$ 
+19.0 
+$ 
+1.5 
+35 
+% 
+3 
+% 
+Total 
+$ 
+391.9 
+$ 
+290.1 
+$ 
+195.1 
+$ 
+101.8 
+$ 
+95.0 
+35 
+% 
+49 
+% 
+Realized price 
+Oil (per Bbl) 
+$ 
+85.45 
+$ 
+88.23 
+$ 
+72.65 
+$ 
+(2.78 
+) 
+$ 
+15.58 
+(3 
+)% 
+21 
+% 
+Gas (per Mcf) 
+$ 
+2.98 
+$ 
+4.32 
+$ 
+5.21 
+$ 
+(1.34 
+) 
+$ 
+(0.89 
+) 
+(31 
+)% 
+(17 
+)% 
+NGLs (per Bbl) 
+$ 
+37.61 
+$ 
+53.32 
+$ 
+— 
+$ 
+(15.71 
+) 
+$ 
+53.32 
+(29 
+)% 
+N/A 
+Per MCFE 
+$ 
+6.73 
+$ 
+7.85 
+$ 
+7.60 
+$ 
+(1.12 
+) 
+$ 
+0.25 
+(14 
+)% 
+3 
+% 
+Per MCFE data 
+Production costs: 
+Lease operating expense 
+$ 
+0.82 
+$ 
+0.88 
+$ 
+1.10 
+$ 
+(0.06 
+) 
+$ 
+(0.22 
+) 
+(7 
+)% 
+(20 
+)% 
+Transportation costs 
+$ 
+0.63 
+$ 
+0.51 
+$ 
+0.19 
+$ 
+0.12 
+$ 
+0.32 
+24 
+% 
+168 
+% 
+Production taxes 
+$ 
+0.33 
+$ 
+0.32 
+$ 
+0.48 
+$ 
+0.01 
+$ 
+(0.16 
+) 
+3 
+% 
+(33 
+)% 
+General and administrative 
+$ 
+0.55 
+$ 
+0.70 
+$ 
+0.97 
+$ 
+(0.15 
+) 
+$ 
+(0.27 
+) 
+(21 
+)% 
+(28 
+)% 
+Depletion, depreciation and amortization and asset retirement obligation liability accretion 
+$ 
+3.32 
+$ 
+3.01 
+$ 
+3.06 
+$ 
+0.31 
+$ 
+(0.05 
+) 
+10 
+% 
+(2 
+)% 
+Derivative cash settlement (gain) loss (2) 
+$ 
+(0.22 
+) 
+$ 
+0.27 
+$ 
+(0.22 
+) 
+$ 
+(0.49 
+) 
+$ 
+0.49 
+(181 
+)% 
+(223 
+)% 
+Earnings per share information 
+Basic net income (loss) per common share 
+$ 
+(0.83 
+) 
+$ 
+3.38 
+$ 
+3.13 
+$ 
+(4.21 
+) 
+$ 
+0.25 
+(125 
+)% 
+8 
+% 
+Diluted net income (loss) per common share 
+$ 
+(0.83 
+) 
+$ 
+3.19 
+$ 
+3.04 
+$ 
+(4.02 
+) 
+$ 
+0.15 
+(126 
+)% 
+5 
+% 
+Basic weighted-average common shares outstanding (in thousands) 
+65,138 
+63,755 
+62,969 
+1,383 
+786 
+2 
+% 
+1 
+% 
+Diluted weighted-average common shares outstanding (in thousands) 
+65,138 
+67,564 
+64,689 
+(2,426 
+) 
+2,875 
+(4 
+)% 
+4 
+% 
+65 
+Table of Contents 
+(1) Amount and percentage changes may not recalculate due to rounding. 
+(2) Derivative cash settlements are included within the realized hedge gain (loss) and unrealized and realized derivative (gain) loss line items in the accompanying statements of operations. 
+Note: 2010 NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of the volumes. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices above. 
+We present per MCFE information because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require analysis. Average daily production for the year ended December 31, 2012 , increased 29 percent compared to the same period in 2011 , driven by the development of our Eagle Ford shale program and a substantial increase in production from our Bakken/Three Forks program. 
+Changes in production volumes, revenues, and costs reflect the highly volatile nature of our industry. Our realized price on a per MCFE basis for the year ended December 31, 2012 , decreased 14 percent compared with the same period in 2011 . The decrease in realized price is due to an overall decline in commodity prices, most significantly gas and NGL prices, during 2012. 
+LOE on a per MCFE basis for the year ended December 31, 2012 , decreased seven percent compared with the same period in 2011 . Absolute dollars for LOE in all regions increased in 2012, however production increased at a faster rate thereby reducing LOE on a per MCFE basis. Additionally, the 2011 divestiture of certain of our non-strategic Mid-Continent region properties, which had meaningfully higher per unit operating costs, reduced our LOE on a per MCFE basis for the year ended December 31, 2012 . LOE in our South Texas & Gulf Coast region decreased in the second half of 2012 due to cost saving initiatives in the region. Based upon the current level of industry activity, we believe that LOE on a per MCFE basis will remain stable throughout 2013. 
+Transportation costs on a per MCFE basis for the year ended December 31, 2012 , increased 24 percent compared to the same period in 2011 . This is a result of increased production in our Eagle Ford shale program, where our transportation arrangements have higher per unit costs compared with our other regions. We anticipate transportation costs will continue to increase on a per MCFE basis as our Eagle Ford shale program becomes a larger portion of our total production. 
+Production taxes on a per MCFE basis for the year ended December 31, 2012 , increased three percent compared with the same period in 2011 . In the second quarter of 2011, we were notified that we qualified for severance tax incentive rebate programs for wells meeting specific criteria in certain areas of Texas. A sizable incentive tax rebate was recorded in the second quarter of 2011, significantly decreasing the per MCFE rate for the year ended December 31, 2011 . We expect our future operated wells drilled in these areas to qualify for incentive tax rebate programs. We generally expect production taxes to trend with oil, gas, and NGL revenues. 
+General and administrative expense on a per MCFE basis for the year ended December 31, 2012 , decreased 21 percent compared with the same period in 2011 , as production increased at a faster rate than our general and administrative expense. A portion of our general and administrative expense is linked to our profitability and cash flow, which are driven in large part by the realized commodity prices we receive for our production. The Net Profits Plan and a portion of our short-term incentive compensation program correlate with net cash flows and therefore are subject to variability. 
+DD&A expense, for the year ended December 31, 2012 , increased 10 percent , on a per MCFE basis, compared with the same period in 2011 . Our DD&A rate increased as a result of the transfer of a portion of our non-operated working interest to Mitsui, which reduced our reserve base but had no impact on the carrying value of our assets. As we utilize our carry with Mitsui, we expect our DD&A rate to improve as we add reserves without incurring capital costs. Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement in Part II, Item 8 of this report for additional discussion on the Mitsui transaction. Our DD&A rate can 
+66 
+Table of Contents 
+fluctuate as a result of impairments, divestitures, and changes in the mix of our production and the underlying proved reserve volumes. Additionally, the accounting treatment for assets that are classified as held for sale can also impact our DD&A rate since these properties are no longer depleted. 
+Please refer to Comparison of Financial Results and Trends between 2012 and 2011 for additional discussion on oil, gas, and NGL production expense, DD&A, and general and administrative expense. 
+Please refer to the section Earnings per Share in Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of this report for additional discussion on the types of shares included in our basic and diluted net income (loss) per common share calculations. During the second quarter of 2012, all of our outstanding 3.50% Senior Convertible Notes were redeemed or net share settled following conversion. The shares issued upon conversion are reflected in our basic weighted-average common shares outstanding calculations for the year ended December 31, 2012 . We recorded a net loss for the year ended December 31, 2012 . Consequently, our in-the-money stock options, unvested RSUs, and contingent PSUs were anti-dilutive for the year resulting in a decrease in the diluted weighted-average common shares outstanding when compared with the year ended December 31, 2011 . Please refer to Note 5 - Long-term Debt in Part II, Item 8 of this report for additional discussion on our 3.50% Senior Convertible Notes. 
+Comparison of Financial Results and Trends between 2012 and 2011 
+Oil, gas, and NGL production revenue. The following table presents the regional changes in our production and oil, gas, and NGL revenues and costs between the years ended December 31, 2012 , and 2011 : 
+Average Net Daily Production Added (Lost) 
+Oil, Gas & NGL Revenue Added (Lost) 
+Production Costs Increase 
+(MMCFE/d) 
+(in millions) 
+(in millions) 
+South Texas & Gulf Coast 
+116.8 
+$ 
+137.0 
+$ 
+68.9 
+Rocky Mountain 
+27.7 
+113.1 
+26.1 
+Mid-Continent 
+(10.6 
+) 
+(92.1 
+) 
+2.3 
+Permian 
+(0.7 
+) 
+(16.5 
+) 
+4.5 
+Total 
+133.2 
+$ 
+141.5 
+$ 
+101.8 
+The largest regional production increase occurred in the South Texas & Gulf Coast region as a result of drilling activity in our Eagle Ford shale program. Production in our Eagle Ford shale program continues to increase and we expect it to do so for the next several years. We also saw an increase in production in our Rocky Mountain region as a result of strong production performance from wells drilled in our Bakken/Three Forks program in late 2011 and throughout 2012. 
+The following table summarizes the realized prices we received in 2012 and 2011 , before the effects of derivative cash settlements: 
+For the Years Ended December 31, 
+2012 
+2011 
+Realized oil price ($/Bbl) 
+$ 
+85.45 
+$ 
+88.23 
+Realized gas price ($/Mcf) 
+$ 
+2.98 
+$ 
+4.32 
+Realized NGL price ($/Bbl) 
+$ 
+37.61 
+$ 
+53.32 
+Realized equivalent price ($/MCFE) 
+$ 
+6.73 
+$ 
+7.85 
+67 
+Table of Contents 
+A 29 percent increase in production on an equivalent basis combined with a 14 percent decrease in realized price per MCFE resulted in an 11 percent increase in revenue between the two periods. Based on current levels of activity, we expect production volumes to increase annually for the next several years. We also expect our realized prices to trend with commodity prices. 
+Realized hedge gain (loss). We recorded a net realized hedge gain of $3.9 million for the year ended December 31, 2012 , compared with a net realized hedge loss of $20.7 million for the same period in 2011 . These amounts are comprised of realized cash settlements on commodity derivative contracts that were designated as cash flow hedges and were previously recorded in accumulated other comprehensive income (loss) (“AOCIL”). Our realized oil, gas, and NGL hedge gains and losses are a function of commodity prices at the time of settlement compared with the respective derivative contract prices. 
+Gain (loss) on divestiture activity. We recorded a net loss on divestiture activity of $27.0 million for the year ended December 31, 2012 , compared with a net gain of $220.7 million for the comparable period of 2011 . The net loss on divestiture activity for the year ended December 31, 2012 , is due to a loss on unsuccessful property sale efforts and the write-down of certain assets held for sale to their fair value. This loss was offset partially by a net gain on completed divestitures. The net gain for the year ended December 31, 2011 , relates to the divestitures of oil and gas properties located in our South Texas & Gulf Coast, Rocky Mountain, and Mid-Continent regions. We will continue to evaluate our portfolio to determine whether there are non-strategic properties we could divest. Please refer to Divestiture Activity and Unsuccessful Sale of Properties above and Note 3 - Assets Held for Sale in Part II, Item 8 of this report for additional discussion. 
+Marketed gas system revenue and expense. Marketed gas system revenue decreased to $52.8 million for the year ended December 31, 2012 , compared with $69.9 million for the comparable period of 2011 , as a result of lower production in the Mid-Continent region and declining gas prices. Concurrent with the decrease in marketed gas system revenue, marketed gas system expense decreased to $47.6 million for the year ended December 31, 2012 , from $64.2 million for the comparable period of 2011 . There was no significant change in our net margin. We expect that marketed gas system revenue and expense will continue to correlate with increases and decreases in production and our realized gas price. 
+Oil, gas, and NGL production expense. Total production costs increased $101.8 million , or 35 percent , to $391.9 million for the year ended December 31, 2012 , compared with $290.1 million in 2011 , primarily due to a 29 percent increase in net production volumes on an equivalent basis. Please refer to our caption A year-to-year overview of selected production and financial information, including trends above for discussion of production costs on a per MCFE basis. 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A expense increased 42 percent to $727.9 million in 2012 compared with $511.1 million in 2011 due to an increase in our depreciable asset base as a result of continued development of our Eagle Ford and Bakken/Three Forks assets and the associated growth of our production. Please refer to our caption A year-to-year overview of selected production and financial information, including trends above for discussion of DD&A expense on a per MCFE basis. 
+68 
+Table of Contents 
+Exploration. The components of exploration expense are summarized as follows: 
+For the Years Ended December 31, 
+2012 
+2011 
+Summary of Exploration Expense 
+(in millions) 
+Geological and geophysical expenses 
+$ 
+13.6 
+$ 
+7.3 
+Exploratory dry hole 
+20.9 
+0.3 
+Overhead and other expenses 
+55.7 
+45.9 
+Total 
+$ 
+90.2 
+$ 
+53.5 
+Exploration expense for 2012 increased 69 percent compared with the same period in 2011 as a result of wells categorized as exploratory being classified as dry during the year, as well as an increase in exploration overhead and geological and geophysical expenses (“G&G”) due to an increase in our exploration efforts. An exploratory project resulting in non-commercial quantities of oil, gas, or NGLs is deemed an exploratory dry hole and impacts the amount of exploration expense we record. 
+Impairment of proved properties. We recorded impairment of proved properties expense of $208.9 million for the year ended December 31, 2012 . The impairments were a result of write-downs of our Wolfberry assets in our Permian region due to downward engineering revisions, as well as write-downs of our Haynesville shale assets due to low natural gas prices. We recorded impairment of proved properties expense of $219.0 million for the comparable period in 2011 related to legacy assets located in our Mid-Continent region as a result of depressed natural gas prices. 
+Abandonment and impairment of unproved properties. We recorded abandonment and impairment of unproved properties expense of $16.3 million for the year ended December 31, 2012 , the majority of which related to acreage we no longer intend to develop in our Rocky Mountain and Mid-Continent regions. We recorded $7.4 million of abandonment and impairment of unproved properties expense for the comparable period in 2011 , primarily associated with lease expirations in our Mid-Continent region. We expect abandonment and impairment of unproved properties to more likely occur in periods of low commodity prices, which negatively impact operating cash flows available for exploration and development, as well as anticipated economic performance. 
+General and administrative. General and administrative expense increased slightly to $119.8 million for the year ended December 31, 2012 , compared with $118.5 million for the same period in 2011 . The change is due to an increase in employee headcount in 2012 , which resulted in an increase to base compensation, benefits, and general corporate office expenses incurred. These were mostly offset by an increase in COPAS overhead reimbursement as a result of an increase in operated well count, as well as an overall decrease in accruals for cash bonus that reflect less success at reaching performance metrics when compared with the prior year. Please refer to our caption A year-to-year overview of selected production and financial information, including trends above for discussion of general and administrative costs on a per MCFE basis. 
+Change in Net Profits Plan liability. This non-cash expense generally relates to the change in the estimated value of the associated liability between the reporting periods. For 2012 , we recorded a non-cash benefit of $28.9 million compared to a non-cash benefit of $25.5 million in 2011 . The change in our liability is subject to estimation and may change dramatically from period to period based on assumptions used for production rates, reserve quantities, commodity pricing, discount rates, and production costs. Payments made to participants as a result of divestitures and ongoing operations will also impact our liability. Please refer to Note 11 - Fair Value Measurements in Part II, Item 8 of this report for the impact a direct payment made to cash-out several pools had on our change in Net Profits Plan liability in 2011 . 
+69 
+Table of Contents 
+Unrealized and realized derivative (gain) loss. We recognized an unrealized and realized derivative gain of $55.6 million in 2012 compared to a gain of $37.1 million for the same period in 2011 . Declining commodity prices in both periods resulted in favorable derivative positions and settlements. These amounts include the change in fair value of commodity derivative contracts and realized cash settlement gains or losses on derivatives for which unrealized changes in fair value were not previously recorded in AOCIL. Please refer to Note 10 - Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion. 
+Other operating expense. Other operating expense was $7.0 million in 2012 compared with $17.6 million in 2011 . The decrease is a result of commissions and legal costs incurred in 2011 associated with our Acquisition and Development Agreement with Mitsui, as well as legal costs incurred related to the arbitration proceedings involving Anadarko E&P Company, LP during the second half of 2011. Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement, in Part II, Item 8 of this report for additional discussion of our Acquisition and Development Agreement. 
+Income tax benefit (expense). We recorded an income tax benefit of $29.3 million for 2012 compared to an expense of $123.6 million for 2011 , resulting in effective tax rates of 35.0 percent and 36.5 percent , respectively. The net decrease in the rate reflects differing effects between years of the individual components of our tax rate. Comparable valuation allowance amounts recorded on state net operating losses and charitable contributions in each of the two years had the effect of increasing the 2011 rate of expense while decreasing the 2012 benefit rate. The impacts from these two items were mostly offset by the effect from recognized research and development credit benefits. Other 2012 net decreases in the effective rate resulted from changes in the mix of the highest marginal state tax rates, the differing effects from percentage depletion and other permanent differences. The current income tax expense in 2012 was $370,000 compared with the income tax benefit of $204,000 in 2011 which included a federal carryback amount. 
+In January 2013 federal legislation was passed extending the R&D credit to our 2012 and 2013 tax years. Since the legislation was not passed as of December 31, 2012 , our 2012 income tax benefit does not reflect an impact for 2012 credit amounts. As of the filing date of this report we have not prepared a study for 2012 while we await the outcome of an on-going audit for R&D credits claimed for our 2007 through 2010 tax years. We are uncertain of when we may complete a study or the impact calculated 2012 and 2013 R&D tax credits would have on our income tax expense and tax rates for 2013. Even with a R&D credit, we expect our tax rate to be higher in 2013. 
+Comparison of Financial Results between 2011 and 2010 
+Oil, gas and NGL production revenue. Average daily production for the year ended December 31, 2011 , increased 54 percent to 465.0 MMCFE, compared with 301.4 MMCFE for the same period in 2010 . The following table presents the regional changes in our production and oil, gas, and NGL revenues and costs between the two years. Effective January 1, 2012, we combined our ArkLaTex region into our Mid-Continent region, based in Tulsa, Oklahoma, for operational and reporting purposes. Prior period presentation has been conformed to reflect this change. 
+Average Net Daily Production Added (Lost) 
+Oil and Gas Revenue Added (Lost) 
+Production Costs Increase (Decrease) 
+(MMCFE/d) 
+(in millions) 
+(in millions) 
+South Texas & Gulf Coast 
+129.0 
+$ 
+348.9 
+$ 
+79.0 
+Rocky Mountain 
+4.9 
+96.1 
+12.2 
+Mid-Continent 
+38.4 
+63.3 
+4.1 
+Permian 
+(8.7 
+) 
+(12.2 
+) 
+(0.3 
+) 
+Total 
+163.6 
+$ 
+496.1 
+$ 
+95.0 
+70 
+Table of Contents 
+The largest regional production increase occurred in the South Texas & Gulf Coast region as a result of production from drilling activity in our Eagle Ford shale program. We also saw an increase in production in our Mid-Continent region as a result of strong production performance from wells drilled in our Haynesville shale program in late 2010 and early 2011. 
+The following table summarizes the average realized prices we received in 2011 and 2010 , before the effects of derivative cash settlements: 
+For the Years Ended December 31, 
+2011 
+2010 
+Realized oil price ($/Bbl) 
+$ 
+88.23 
+$ 
+72.65 
+Realized gas price ($/Mcf) 
+$ 
+4.32 
+$ 
+5.21 
+Realized NGL price ($/Bbl) 
+$ 
+53.32 
+$ 
+— 
+Realized equivalent price ($/MCFE) 
+$ 
+7.85 
+$ 
+7.60 
+Note: Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head. Beginning in the first quarter of 2011, we changed our reporting for natural gas volumes to separately show natural gas and NGL production volumes, revenues, and pricing consistent with title transfer for each product. 
+The three percent increase in average realized prices per MCFE coupled with a 54 percent increase in production volumes between periods resulted in a meaningful increase in revenue. 
+Realized hedge gain (loss). We recorded a net realized hedge loss of $20.7 million for the year ended December 31, 2011 , compared with a net realized hedge gain of $23.5 million for the same period in 2010 . The realized net loss in 2011 is comprised of realized cash settlements on commodity contracts that were previously recorded in AOCL, whereas the realized net gain in 2010 is comprised of realized cash settlements on all commodity derivative contracts. 
+Gain (loss) on divestiture activity. We recorded a gain on divestiture activity of $220.7 million , which was net of the $27.5 million write-down related to our Marcellus shale assets, for the year ended December 31, 2011 , compared with a gain of $155.3 million for the comparable period of 2010 . The 2011 gain related to the divestitures of oil and gas properties located in our South Texas & Gulf Coast, Rocky Mountain, and Mid-Continent regions. The 2010 gain related to the divestitures of oil and gas properties located in our Rocky Mountain and Permian regions. 
+Marketed gas system revenue and expense. Marketed gas system revenue was $69.9 million for the year ended December 31, 2011 , which was relatively flat compared to $70.1 million for the year ended December 31, 2010 . Concurrent with the decrease in marketed gas system revenue, marketed gas system expense decreased to $64.2 million for the year ended December 31, 2011 , from $66.7 million for the comparable period of 2010 . 
+Oil and gas production expense. Total production costs increased $95.0 million , or 49 percent , to $290.1 million for the year ended December 31, 2011 , compared with $195.1 million in 2010 due primarily to a 54 percent increase in equivalent production volumes in 2011 . Total oil, gas, and NGL production costs per MCFE decreased $0.06 to $1.71 for the year ended December 31, 2011 , compared with $1.77 in 2010 , due to a decrease in recurring LOE resulting from the sale of non-strategic properties with higher per unit LOE costs, as well as a decrease in production taxes per MCFE due to severance tax incentives in our South Texas & Gulf Coast and Mid-Continent regions. These decreases were offset slightly by an increase in transportation costs per MCFE, which was primarily a result of increased production in our Eagle Ford shale program where our transportation agreements have higher per unit transportation costs due to the lack of infrastructure in the emerging play. 
+71 
+Table of Contents 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A expense increased 52 percent to $511.1 million for the year ended December 31, 2011 , compared with $336.1 million in 2010 . The increase in overall DD&A expense was due to increased production. DD&A expense per MCFE decreased two percent to $3.01 for the year ended December 31, 2011 , compared to $3.06 in 2010 due to an increase in our reserve base and production volumes, while our property balances remained relatively constant between the two periods. 
+Exploration. The components of exploration expense are summarized as follows: 
+For the Years Ended December 31, 
+2011 
+2010 
+Summary of Exploration Expense 
+(in millions) 
+Geological and geophysical expenses 
+$ 
+7.3 
+$ 
+21.5 
+Exploratory dry hole 
+0.3 
+0.3 
+Overhead and other expenses 
+45.9 
+42.1 
+Total 
+$ 
+53.5 
+$ 
+63.9 
+Exploration expense in 2011 decreased 16 percent compared to the same period in 2010 due to a reduction in geological and geophysical expense, as a result of a decrease in our exploration efforts in 2011. The increase in exploration overhead costs related to equity incentive compensation expense as discussed under General and administrative below. 
+Impairment of proved properties. We recorded $219.0 million of impairment of proved properties expense in 2011 , compared to $6.1 million in 2010 . The impairment in 2011 related to assets located in our Mid-Continent region that were impacted by significantly lower natural gas prices in the second half of 2011. 
+Abandonment and impairment of unproved properties. We recorded abandonment and impairment of unproved properties expense of $7.4 million for the year ended December 31, 2011, associated with lease expirations in our Mid-Continent region. We recorded $2.0 million of abandonment and impairment of unproved properties expense for the comparable period in 2010, associated with lease expirations in our Rocky Mountain and Mid-Continent regions. 
+General and administrative. General and administrative expense increased 11 percent to $118.5 million for the year ended December 31, 2011 , compared with $106.7 million for the same period in 2010 . The change was due to an increase in base and equity incentive compensation and accruals for cash bonuses, as well as an increase in corporate office expenses as a result of an increase in employee headcount between the two periods. General and administrative expense per MCFE decreased $0.27 to $0.70 per MCFE for the year ended December 31, 2011 , compared to $0.97 in 2010 , mostly due to our production increasing at a faster rate than our general and administrative expense. 
+Change in Net Profits Plan liability. For 2011 , the change in the Net Profits Plan liability, a non-cash item, was a $25.5 million benefit compared to a $34.4 million benefit in 2010 . This non-cash charge or benefit is directly related to the change in the estimated value of the associated liability between the reporting periods. Please refer to Note 11 - Fair Value Measurements in Part II, Item 8 of this report for the impact a direct payment made to cash-out several pools had on our change in Net Profits Plan liability in 2011 . 
+Unrealized and realized derivative (gain) loss. We recognized an unrealized and realized derivative gain of $37.1 million in 2011 compared to a loss of $8.9 million for the same period in 2010 . The 2011 amount includes gains resulting from unrealized changes in fair value on commodity derivative contracts of $62.8 million and realized cash settlement losses on derivatives for which unrealized changes in fair value were not previously recorded in other comprehensive loss of $25.7 million . The 2010 activity is comprised solely of the ineffective portion of derivatives designated as cash flow hedges. 
+72 
+Table of Contents 
+Other operating expense. Other operating expense was $17.6 million in 2011 compared with $3.0 million in 2010 . The increase was a result of commission and legal costs associated with our Acquisition and Development Agreement with Mitsui, as well as legal costs related to the arbitration proceedings against Anadarko E&P Company, LP during the second half of 2011. 
+Income tax benefit (expense). Income tax expense totaled $123.6 million for 2011 compared to tax expense of $118.1 million for 2010 , resulting in effective tax rates of 36.5 percent and 37.5 percent , respectively. The effective rate change from 2010 primarily reflected changes in the mix of the highest marginal state tax rates, a multi-year research and experimentation credit claim, an adjustment for anticipated utilization of charitable contributions carryovers, and differing effects of other permanent differences including percentage depletion. The current income tax benefit in 2011 was $204,000 compared with current income tax expense of $3.5 million in 2010. These amounts were three percent of the total income tax expense for 2010 and were not material for 2011. 
+Overview of Liquidity and Capital Resources 
+We believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future. We continue to manage the duration and level of our drilling and completion services commitments in order to provide us with some flexibility to reduce activity and capital expenditures in periods of prolonged commodity price decline. 
+Sources of cash 
+We currently expect our 2013 capital program to be partially funded by cash flows from operations, with an anticipated shortfall to be funded by borrowings under our credit facility. Although we anticipate that cash flow from operations and borrowing capacity under our credit facility will be sufficient to fund our expected 2013 capital program, we may also elect to access the capital markets, depending on prevailing market conditions. The divestiture of certain oil and gas properties is also a potential source of funding and we will continue to evaluate our portfolio to identify potential divestiture candidates. 
+Our primary sources of liquidity are the cash flows provided by our operating activities, borrowings under our credit facility, proceeds received from divestitures of properties, and other financing alternatives, including accessing capital markets. From time to time, we may enter into carrying cost funding and sharing arrangements with third parties for particular exploration and/or development programs. All of our sources of liquidity can be impacted by the general condition of the broader economy and by fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and our industry. We have no control over the market prices for oil, gas, or NGLs, although we are able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. The borrowing base under our credit facility could be reduced as a result of lower commodity prices, divestitures of producing properties, or newly issued debt. See “ Credit Facility ” below for a discussion of our most recent borrowing base redetermination. Historically, decreases in commodity prices have limited our industry’s access to capital markets. 
+In the second quarter of 2012, we issued $400.0 million in aggregate principal amount of 6.50% Senior Notes due 2023. Additionally, some of the proceeds from our 2021 Notes issued in the fourth quarter of 2011 were available for use in 2012. In late 2011, we consummated our Acquisition and Development Agreement with Mitsui pursuant to which Mitsui funds, or carries, 90 percent of certain drilling and completion costs attributable to our remaining interest in our non-operated Eagle Ford shale acreage until $680.0 million has been expended on our behalf. Of the original $680.0 million carry amount, $277.5 million had been spent as of December 31, 2012 . The remaining carry is expected to be realized over approximately the next two years. Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement in Part II, Item 8 of this report for additional discussion. 
+73 
+Table of Contents 
+Proposals to fund the federal government budget continue to include eliminating or reducing current tax deductions for intangible drilling costs, the domestic production activities deduction, and percentage depletion. Legislation modifying or eliminating these deductions would have the immediate effect of reducing operating cash flows thereby reducing funding available for our exploration and development capital programs and those of our peers in the industry. If enacted, these funding reductions could have a significant adverse effect on drilling in the United States for a number of years. 
+Credit facility 
+In May 2011, we entered into our Fourth Amended and Restated Credit Agreement, providing a $2.5 billion senior secured revolving credit facility with a scheduled maturity date of May 27, 2016. In the third quarter of 2012, our borrowing base under the credit facility was increased to $1.55 billion from $1.4 billion . Our borrowing base is subject to regular semi-annual redeterminations by our lenders and the next scheduled re-determination date is April 1, 2013. As of the filing date of this report, our lenders have committed to a current aggregate commitment amount of $1.0 billion under the credit agreement. We believe the current commitment amount is sufficient to meet our anticipated liquidity and operating needs. Through the filing date of this report, we have experienced no issues utilizing our credit facility. No individual bank participating in our credit facility represents more than 10 percent of the lending commitments under the credit facility. 
+The following table presents the outstanding balance, total amount of letters of credit, and available borrowing capacity under our credit facility as of February 14, 2013 , December 31, 2012 , and December 31, 2011 . 
+As of February 14, 2013 
+As of December 31, 2012 
+As of December 31, 2011 
+(in millions) 
+Credit facility balance 
+$ 
+407.5 
+$ 
+340.0 
+$ 
+— 
+Letters of credit (1) 
+$ 
+0.8 
+$ 
+0.8 
+$ 
+0.6 
+Available borrowing capacity 
+$ 
+591.7 
+$ 
+659.2 
+$ 
+999.4 
+(1) Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis. 
+Our daily weighted-average credit facility debt balance was approximately $171.8 million and $10.7 million for the years ended December 31, 2012 , and 2011 , respectively. Borrowings under our credit facility are secured by mortgages on substantially all of our proved oil and gas properties. 
+Weighted-average interest rates 
+O ur weighted-average interest rates in the current and prior year include accrued interest payments, cash fees paid on the unused portion of the credit facility’s aggregate commitment amount, letter of credit fees, amortization of the debt discount related to our 3.50% Senior Convertible Notes through April 2, 2012 , and amortization of deferred financing costs. Our weighted-average borrowing rate is calculated using only our accrued interest and fee payments. 
+The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the years ended December 31, 2012 , 2011 , and 2010 . 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+Weighted-average interest rate 
+6.4 
+% 
+8.5 
+% 
+8.3 
+% 
+Weighted-average borrowing rate 
+5.5 
+% 
+5.2 
+% 
+2.8 
+% 
+74 
+Table of Contents 
+The decrease in our weighted-average interest rate from 2011 is a result of our Senior Notes being outstanding for all or a part of the year ended December 31, 2012 , with rates below the 2011 average interest rate, as well as a higher average balance on our revolving credit facility, which provides a lower interest rate than all our fixed debt instruments and which reduces the fee paid on the unused portion of our aggregate commitment. 
+Our weighted-average borrowing rate for the year ended December 31, 2012 , was impacted by the three tranches of high yield unsecured debt we have issued since February 2011, as well as the redemption and settlement of our 3.50% Senior Convertible Notes that occurred in the second quarter of 2012. Each tranche of high yield unsecured debt has a coupon rate that is higher than the coupon rate on the 3.50% Senior Convertible Notes, and is also higher than the average borrowing rate on the credit facility incurred during 2011. This had the effect of increasing our average borrowing rate since high yield unsecured debt replaced lower cost secured bank debt and our 3.50% Senior Convertible Notes. 
+We are subject to customary covenants under our credit facility, including limitations on dividend payments and requirements to maintain certain financial ratios, which include debt to EBITDAX, as defined under the caption Non-GAAP Financial Measures below, of less than 4.0 to 1.0 and an adjusted current ratio, as defined by our credit agreement, of no less than 1.0. As of December 31, 2012 , our debt to EBITDAX ratio and adjusted current ratio, as defined by our credit agreement, were 1.40 and 1.81 , respectively. As of the filing date of this report, we are in compliance with all financial and non-financial covenants under our credit facility. 
+Uses of cash 
+We use cash for the acquisition, exploration, and development of oil and gas properties and for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the exploration and development of oil and gas properties are the primary use of our capital resources. During 2012 , we spent $1.5 billion for exploration and development capital expenditures, and leasehold acquisition. These amounts differ from the cost incurred amounts, which are accrual-based and include asset retirement obligation, G&G, and exploration overhead amounts. 
+The amount and allocation of future capital expenditures will depend upon a number of factors, including the number and size of available acquisition and drilling opportunities, our cash flow from operating, investing, and financing activities, and our ability to assimilate acquisitions and execute our drilling program. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, and the timing and results of our operated and non-operated development and exploratory activities may lead to changes in funding requirements for future development. We regularly review our capital expenditure budget to assess changes in current and projected cash flows, potential acquisition and divestiture activities, debt requirements, and other factors. 
+We may from time to time repurchase certain amounts of our outstanding debt securities for cash and/or through exchanges for other securities. Such repurchases or exchanges may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or exchanges will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. 
+As of the filing date of this report, subject to the approval of our Board of Directors, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program. Shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility and the indentures governing our Senior Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors reviews this program as part of the allocation of our capital. During 2012, we did not repurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares. 
+75 
+Table of Contents 
+During 2012 , we paid $6.5 million in dividends to our stockholders, which constitutes a dividend of $0.10 per share. Our intention is to continue to make dividend payments for the foreseeable future, subject to our future earnings, our financial condition, credit facility and other covenants, and other factors which could arise. Payment of future dividends remains at the discretion of our Board of Directors. Additionally, during the second quarter of 2012 we paid $287.5 million to settle our 3.50% Senior Convertible Notes. 
+The following table presents changes in cash flows between the years ended December 31, 2012 , 2011 , and 2010 , for our operating, investing, and financing activities. The analysis following the table should be read in conjunction with our statements of cash flows in Part II, Item 8 of this report. 
+For the Years Ended 
+December 31, 
+Amount of Changes Between 
+Percent of Change Between 
+2012 
+2011 
+2010 
+2012/2011 
+2011/2010 
+2012/2011 
+2011/2010 
+(in millions) 
+Net cash provided by operating activities 
+$ 
+922.0 
+$ 
+760.5 
+$ 
+497.1 
+$ 
+161.5 
+$ 
+263.4 
+21 
+% 
+53 
+% 
+Net cash (used in) investing activities 
+$ 
+(1,457.3 
+) 
+$ 
+(1,264.9 
+) 
+$ 
+(361.6 
+) 
+$ 
+(192.4 
+) 
+$ 
+(903.3 
+) 
+15 
+% 
+250 
+% 
+Net cash provided by (used in) financing activities 
+$ 
+422.1 
+$ 
+618.5 
+$ 
+(141.1 
+) 
+$ 
+(196.4 
+) 
+$ 
+759.6 
+(32 
+)% 
+(538 
+)% 
+Analysis of cash flow changes between 2012 and 2011 
+Operating activities. Cash received from oil, gas, and NGL production revenues, including derivative cash settlements, increased $256.5 million, or 21 percent, to $1.5 billion for the year ended December 31, 2012 , compared with the same period in 2011. This increase was due to an increase in production volumes and favorable derivative settlements resulting from declining commodity prices throughout the year. Cash paid for lease operating expenses in 2012 increased $28.4 million compared with 2011 due to increased production and higher service costs caused by increased demand for those services. Cash paid for interest during 2012 increased $29.2 million compared with the same period in 2011 due to interest payments on our Senior Notes, as well as an increase in interest payments under our credit facility arising from an increase in our weighted-average borrowings for the year. 
+Investing activities. Capital expenditures in 2012 decreased $125.3 million , or eight percent , compared with the same period in 2011 . This decrease was a result of being carried for substantially all of our drilling and completion costs in our outside operated Eagle Ford program. Net proceeds from the sale of oil and gas properties decreased $309.1 million between the two periods due to a decrease in divestiture activity in 2012. 
+Financing activities. During 2012, we paid $287.5 million to settle our 3.50% Senior Convertible Notes. We received $392.1 million of net proceeds from the issuance of our 2023 Notes in 2012, compared with $684.2 million of proceeds from the issuance of our 2019 Notes and 2021 Notes in 2011. We had net borrowings under our credit facility of $340.0 million during 2012, compared with net repayments of $48.0 million made during 2011. 
+Analysis of cash flow changes between 2011 and 2010 
+Operating activities. Cash received from oil, gas, and NGL production revenues, including derivative cash settlements, increased $409.4 million to $1.2 billion for the year ended December 31, 2011 . The increase was due to an increase in production volumes. Cash paid for lease operating expenses in 2011 increased $26.5 million compared with 2010 . We received $4.0 million in income tax refunds in 2011 compared to $25.6 million received during 2010 . 
+76 
+Table of Contents 
+Investing activities. Cash used for investing activities was $1.3 billion for the year ended December 31, 2011 , compared with $361.6 million for the same period in 2010 . Cash spent on capital expenditures increased $964.8 million , or 144 percent , to $1.6 billion . This increase in capital and exploration activities was financed mainly by higher cash flows available from operating activities, divestiture proceeds, and proceeds from the issuance of our 2019 Notes and 2021 Notes. Proceeds received from divestitures increased $53.0 million to $364.5 million for the year ended December 31, 2011 , due to an increase in the size of the divestiture packages. 
+Financing activities. Net repayments to our credit facility decreased $92.0 million for the year ended December 31, 2011 , compared to 2010 as our strong cash position throughout 2011 resulted in decreased borrowings. After deducting aggregate fees of $15.8 million , we received aggregate net proceeds of $684.2 million due to the issuance of our 2019 Notes and 2021 Notes during 2011 . We spent $8.7 million on debt issuance costs for our amended credit facility during the year ended December 31, 2011 . 
+Interest Rate Risk 
+We are exposed to market risk due to the floating interest rate on our revolving credit facility. Our credit agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes affect the credit facility’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of the credit facility that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Notes, but can impact fair market values. As of December 31, 2012 , our fixed-rate debt outstanding totaled $1.1 billion . As of December 31, 2012 , we had $340.0 million of floating-rate debt outstanding. The carrying amount of our floating-rate debt at December 31, 2012 , approximates its fair value. Assuming a constant floating-rate debt level of $340.0 million , the before-tax cash flow impact resulting from a 100 basis point change in our interest rate would be $3.4 million over a 12-month time period. 
+Commodity Price Risk 
+The prices we receive for our oil, gas, and NGL production heavily impacts our revenue, overall profitability, access to capital and future rate of growth. Oil, gas, and NGLs are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, gas, and NGLs have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Based on our 2012 production, a 10 percent decrease in our average realized price received for oil, gas, and NGLs would have reduced our oil, gas, and NGL production revenues by $88.6 million, $35.8 million, and $23.0 million, respectively. 
+The fair values of our commodity derivative contracts are largely determined by estimates of the forward curves of the relevant price indices. At December 31, 2012 , a 10 percent increase and 10 percent decrease in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by the following amounts: 
+10% Increase 
+10% Decrease 
+(in thousands) 
+Gain/(loss): 
+Gas derivatives 
+$ 
+(66.9 
+) 
+$ 
+61.9 
+Oil derivatives 
+$ 
+(29.0 
+) 
+$ 
+29.0 
+NGL derivatives 
+$ 
+(5.4 
+) 
+$ 
+5.4 
+77 
+Table of Contents 
+We enter into commodity derivative contracts in order to reduce the impact of fluctuations in commodity prices. Please refer to Note 10 – Derivative Financial Instruments of Part II, Item 8 of this report for additional information about our oil, gas, and NGL derivative contracts, and additional information below under the caption Summary of Oil, Gas, and NGL Derivative Contracts in Place. 
+Summary of Oil, Gas, and NGL Derivative Contracts in Place 
+Our oil, gas, and NGL derivative contracts include costless swaps and costless collar arrangements. All contracts are entered into for other-than-trading purposes. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional information regarding accounting for our derivative transactions. 
+As of December 31, 2012 , our commodity derivative contracts through the third quarter of 2015 totaled 10.1 million Bbls of oil, 80.7 million MMBtu of gas, and 1.2 million Bbls of NGLs. As of February 14, 2013 , the Company had commodity derivative contracts in place through the fourth quarter of 2015 for a total of 14.5 million Bbls of oil, 114.8 million MMBtu of gas, and 2.0 million Bbls of NGLs. 
+In a typical commodity swap agreement, if the agreed-upon published third-party index price is lower than the swap fixed price, we receive the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, we pay the difference. For collar agreements, we receive the difference between an agreed upon index and the floor price if the index price is below the floor price. We pay the difference between the agreed upon contracted ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the contracted floor and ceiling prices. 
+The following tables summarize the approximate volumes, average contract prices, and fair value of contracts we had in place as of December 31, 2012 : 
+Oil contracts 
+Oil Swaps: 
+Contract Period 
+NYMEX WTI Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair Value at 
+December 31, 2012 
+(Liability) 
+(Bbls) 
+(per Bbl) 
+(in millions) 
+First quarter 2013 
+514,000 
+$ 
+89.87 
+$ 
+(1.3 
+) 
+Second quarter 2013 
+534,000 
+$ 
+88.99 
+(2.4 
+) 
+Third quarter 2013 
+300,000 
+$ 
+91.47 
+(0.7 
+) 
+Fourth quarter 2013 
+265,000 
+$ 
+91.22 
+(0.5 
+) 
+2014 
+1,256,000 
+$ 
+90.92 
+(1.7 
+) 
+2015 
+355,000 
+$ 
+88.40 
+(0.7 
+) 
+All oil swaps 
+3,224,000 
+$ 
+(7.3 
+) 
+78 
+Table of Contents 
+Oil Collars: 
+Contract Period 
+NYMEX WTI 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+Fair Value at 
+December 31, 2012 
+Asset (Liability) 
+(Bbls) 
+(per Bbl) 
+(per Bbl) 
+(in millions) 
+First quarter 2013 
+755,000 
+$ 
+79.87 
+$ 
+107.36 
+$ 
+0.1 
+Second quarter 2013 
+620,000 
+$ 
+76.65 
+$ 
+109.08 
+0.2 
+Third quarter 2013 
+765,000 
+$ 
+74.89 
+$ 
+107.98 
+(0.3 
+) 
+Fourth quarter 2013 
+727,000 
+$ 
+81.02 
+$ 
+116.09 
+1.8 
+2014 
+2,174,000 
+$ 
+83.71 
+$ 
+107.93 
+5.2 
+2015 
+1,814,000 
+$ 
+85.00 
+$ 
+95.51 
+(0.1 
+) 
+All oil collars 
+6,855,000 
+$ 
+6.9 
+Natural Gas Contracts 
+Natural Gas Swaps: 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair Value at 
+December 31, 2012 
+Asset (Liability) 
+(MMBtu) 
+(per MMBtu) 
+(in millions) 
+First quarter 2013 
+8,611,000 
+$ 
+4.34 
+$ 
+9.2 
+Second quarter 2013 
+7,205,000 
+$ 
+3.99 
+4.5 
+Third quarter 2013 
+6,114,000 
+$ 
+4.19 
+4.2 
+Fourth quarter 2013 
+5,593,000 
+$ 
+4.38 
+3.9 
+2014 
+23,309,000 
+$ 
+4.14 
+4.4 
+2015 
+17,469,000 
+$ 
+4.02 
+(1.2 
+) 
+All natural gas swaps* 
+68,301,000 
+$ 
+25.0 
+*Natural gas swaps are comprised of IF El Paso Permian (2%), IF HSC (56%), IF NGPL TXOK (4%), IF PEPL (16%), IF Reliant N/S (17%), and IF TETCO STX (5%). 
+Natural Gas Collars: 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+Fair Value at 
+December 31, 2012 
+Asset 
+(MMBtu) 
+(per MMBtu) 
+(per MMBtu) 
+(in millions) 
+First quarter 2013 
+1,330,000 
+$ 
+4.39 
+$ 
+5.46 
+$ 
+1.5 
+Second quarter 2013 
+1,910,000 
+$ 
+4.39 
+$ 
+5.32 
+2.0 
+Third quarter 2013 
+1,770,000 
+$ 
+4.39 
+$ 
+5.31 
+1.7 
+Fourth quarter 2013 
+1,640,000 
+$ 
+4.39 
+$ 
+5.31 
+1.4 
+2014 
+5,734,000 
+$ 
+4.38 
+$ 
+5.36 
+4.0 
+All natural gas collars* 
+12,384,000 
+$ 
+10.6 
+*Natural gas collars are comprised of IF HSC (18%), IF NGPL TXOK (18%), IF Reliant N/S (29%), and IF TETCO STX (35%). 
+79 
+Table of Contents 
+NGL Contracts 
+NGL Swaps: 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+Fair Value at 
+December 31, 2012 
+Asset 
+(Bbls) 
+(per Bbl) 
+(in millions) 
+First quarter 2013 
+436,000 
+$ 
+46.21 
+$ 
+1.3 
+Second quarter 2013 
+371,000 
+$ 
+42.74 
+1.3 
+Third quarter 2013 
+222,000 
+$ 
+50.45 
+0.5 
+Fourth quarter 2013 
+206,000 
+$ 
+50.27 
+0.4 
+All NGL swaps* 
+1,235,000 
+$ 
+3.5 
+*NGL swaps are comprised of OPIS Mont. Belvieu Purity Ethane (37%), OPIS Mont. Belvieu LDH Propane (25%), OPIS Mont. Belvieu NON-LDH Isobutane (2%), OPIS Mont. Belvieu NON-LDH Normal Butane (16%), and OPIS Mont. Belvieu NON-LDH Natural Gasoline (20%). 
+Commodity Derivative Contracts Entered into After December 31, 2012 
+The following tables summarize all commodity derivative contracts entered between January 1, 2013 , and February 14, 2013 : 
+Oil contracts 
+Oil Swaps: 
+Contract Period 
+NYMEX WTI Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+(Bbls) 
+(per Bbl) 
+First quarter 2013 
+220,000 
+$ 
+98.25 
+Second quarter 2013 
+559,000 
+$ 
+98.25 
+Third quarter 2013 
+458,000 
+$ 
+97.50 
+Fourth quarter 2013 
+392,000 
+$ 
+95.85 
+2014 
+344,000 
+$ 
+95.85 
+All oil swaps 
+1,973,000 
+Oil Collars: 
+Contract Period 
+NYMEX WTI 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+(Bbls) 
+(per Bbl) 
+(per Bbl) 
+2014 
+847,000 
+$ 
+85.00 
+$ 
+99.10 
+2015 
+1,552,000 
+$ 
+85.00 
+$ 
+92.79 
+All oil collars 
+2,399,000 
+80 
+Table of Contents 
+Natural Gas Contracts 
+Natural Gas Swaps: 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+(MMBtu) 
+(per MMBtu) 
+Third quarter 2013 
+3,542,000 
+$ 
+3.57 
+Fourth quarter 2013 
+2,925,000 
+$ 
+3.57 
+2014 
+13,208,000 
+$ 
+3.90 
+All natural gas swaps* 
+19,675,000 
+*Natural gas swaps are comprised of IF El Paso Permian (4%), IF HSC (77%), IF NGPL TXOK (3%), IF NNG Ventura (6%), IF PEPL (10%). 
+Natural Gas Collars: 
+Contract Period 
+NYMEX WTI 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+(MMBtu) 
+(per MMBtu) 
+(per MMBtu) 
+2015 
+14,480,000 
+$ 
+3.96 
+$ 
+4.30 
+All natural gas collars* 
+14,480,000 
+*Natural gas collars are comprised of IF El Paso Permian (4%), IF HSC (72%), IF NNG Ventura (7%), IF PEPL (10%), IF Reliant N/S (7%). 
+NGL Contracts 
+NGL Swaps: 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+(Bbls) 
+(per Bbl) 
+First quarter 2013 
+60,000 
+$ 
+75.37 
+Second quarter 2013 
+181,000 
+$ 
+74.36 
+Third quarter 2013 
+153,000 
+$ 
+74.25 
+Fourth quarter 2013 
+136,000 
+$ 
+74.20 
+2014 
+208,000 
+$ 
+75.87 
+All NGL swaps* 
+738,000 
+*NGL swaps are comprised of OPIS Mont. Belvieu NON-LDH Isobutane (38%), OPIS Mont. Belvieu NON-LDH Natural Gasoline (34%), and OPIS Mont. Belvieu NON-LDH Normal Butane (28%). 
+81 
+Table of Contents 
+Schedule of Contractual Obligations 
+The following table summarizes our contractual obligations at December 31, 2012 , for the periods specified (in millions): 
+Contractual Obligations 
+Total 
+Less than 1 year 
+1-3 years 
+3-5 years 
+More than 5 years 
+Long-term debt (1) 
+$ 
+1,440.0 
+$ 
+— 
+$ 
+— 
+$ 
+340.0 
+$ 
+1,100.0 
+Interest payments (2) 
+624.3 
+77.9 
+155.8 
+146.3 
+244.3 
+Delivery commitments (3) 
+858.7 
+53.2 
+170.7 
+193.0 
+441.8 
+Operating leases and contracts (3) 
+153.9 
+74.6 
+40.8 
+11.0 
+27.5 
+Derivative liability (4) 
+15.8 
+9.0 
+6.8 
+— 
+— 
+Net Profits Plan (5) 
+77.5 
+16.6 
+28.9 
+22.5 
+9.5 
+Asset retirement obligations (6) 
+120.5 
+35.8 
+7.1 
+4.7 
+72.9 
+Other (7) 
+23.2 
+2.3 
+20.5 
+0.1 
+0.3 
+Total 
+$ 
+3,313.9 
+$ 
+269.4 
+$ 
+430.6 
+$ 
+717.6 
+$ 
+1,896.3 
+(1) Long-term debt consists of our Senior Notes and the outstanding balance under our long-term revolving credit facility, and assumes no principal repayment until the due dates of the instruments. The actual payments under our revolving credit facility may vary significantly. 
+(2) Interest payments on our Senior Notes are estimated assuming no principal repayment until the due dates of the instruments. Interest payments on our credit facility have been estimated using a rate of 1.75 percent and assume no principal repayment until the May 27, 2016, due date. 
+(3) Please refer to Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional discussion regarding our operating leases, contracts, and gathering, processing, and transportation through-put commitments. 
+(4) Amount shown represents only the liability portion of the marked-to-market value of our commodity derivatives based on future market prices at December 31, 2012 , and excludes estimated oil, gas, and NGL commodity derivative receipts. This amount varies from the liability amounts presented on the accompanying balance sheets, as those amounts are presented at fair value, which considers time value, volatility, and the risk of non-performance for us and for our counterparties. The ultimate settlement amounts under our derivative contracts are unknown, however, as they are subject to continuing market risk and commodity price volatility. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion regarding our derivative contracts. 
+(5) Amount shown represents undiscounted forecasted payments for the Net Profits Plan for the next six years. Payments are expected to gradually decrease for the years beyond what are shown in this table and are not included due to these payments being highly variable, as outlined below. The amount recorded on the accompanying balance sheets reflects all future Net Profits Plan payments and the impact of discounting, and therefore differs from the amounts disclosed in this table. The variability in the amount of payments will be a direct reflection of commodity prices, production rates, capital expenditures, and operating costs in future periods. Predicting the timing and amounts of payments associated with this liability is contingent upon estimates of appropriate discount factors, adjusting for risk and time value, and upon a number of factors we cannot control. Please refer to Note 7 – Compensation Plans and Note 11 - Fair Value Measurements in Part II, Item 8 of this report for additional discussion regarding our Net Profits Plan liability. 
+82 
+Table of Contents 
+(6) 
+Amount shown represents estimated future discounted abandonment costs. These obligations are recorded as liabilities on our December 31, 2012 , accompanying balance sheets. The ultimate settlement of these obligations is unknown and can be impacted by federal and state regulations, as well as economic factors and therefore the actual timing of abandonment costs may vary significantly. Please refer to Note 9 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion regarding our asset retirement obligations. 
+(7) The majority of the amount shown represents the remaining funded portion of our estimated pension liability of $20.0 million , although we recognize that we cannot accurately determine the timing of future payments, as well as insignificant amounts related to uncertain tax positions and our cash settlement balancing payable. We are expected to make contributions to the Pension Plan in 2013 of $373,000 . We made contributions of $5.4 million and $5.3 million in 2012 and 2011 , respectively, toward our pension liability. 
+In addition to the amounts in the above table, we entered into a three-year capital project commencing in 2011 for the development of infrastructure in our non-operated Eagle Ford shale play. Pursuant to the terms of the agreement for the construction, ownership and operation of the assets, we are required to pay our portion of the costs. Based on current estimates, we do not expect costs to exceed approximately $67 million over the remaining term of the agreement. 
+Off-balance Sheet Arrangements 
+As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of December 31, 2012 , we have not been involved in any unconsolidated special purpose entity transactions. 
+We evaluate our transactions to determine if any variable interest entities exist. If it is determined that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. 
+Critical Accounting Policies and Estimates 
+Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our assumptions and estimates on historical experience and various other sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we calculate due to changes in circumstances, global economics and politics, and general business conditions. A summary of our significant accounting policies is detailed in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report. We have outlined below those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment. 
+Oil and gas reserve quantities. Our estimated reserve quantities and future net cash flows are critical to the understanding of the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our financial statements, including the calculations of depletion and impairment of proved oil and gas properties and the estimate of our Net Profits Plan liability. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure calculations require a 10 percent discount rate to 
+83 
+Table of Contents 
+be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves, including using independent reserve engineering consultants. We expect that periodic reserve estimates will change in the future as additional information becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves at June 30 and December 31 of each year. For purposes of depletion and impairment, reserve quantities are adjusted in accordance with GAAP for the impact of additions and dispositions. Changes in depletion or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period the reserve estimates change. Please refer to Supplemental Oil and Gas Information in Part II, Item 8 of this report. 
+The following table presents information about reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves. 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+BCFE 
+BCFE 
+BCFE 
+Change 
+Change 
+Change 
+Revisions resulting from price changes 
+(72.7 
+) 
+(25.3 
+) 
+42.6 
+Revisions resulting from performance (1) 
+(92.0 
+) 
+36.8 
+(17.9 
+) 
+Total 
+(164.7 
+) 
+11.5 
+24.7 
+(1) Performance revisions include the removal of proved undeveloped reserves that are no longer in our development plan within five years. 2011 includes the impact of our conversion to three stream production reporting. 
+As previously noted, commodity prices are volatile, and estimates of reserves are inherently imprecise. Consequently, we expect to continue experiencing these types of changes. Please refer to additional reserves discussion under Overview of the Company. 
+The following table reflects the estimated BCFE change and percentage change to our total reported reserve volumes from the described hypothetical changes: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+BCFE 
+Percentage 
+BCFE 
+Percentage 
+BCFE 
+Percentage 
+Change 
+Change 
+Change 
+Change 
+Change 
+Change 
+A 10% decrease in SEC pricing 
+(67.4 
+) 
+(4 
+)% 
+(22.2 
+) 
+(2 
+)% 
+(13.9 
+) 
+(1 
+)% 
+A 10% decrease in proved undeveloped reserves 
+(76.1 
+) 
+(4 
+)% 
+(41.5 
+) 
+(3 
+)% 
+(29.7 
+) 
+(3 
+)% 
+The table above solely reflects the impact of a 10 percent change in SEC pricing or decrease in proved undeveloped reserves and does not include additional impacts to our proved reserves that may result from our internal intent to drill hurdles. Additional reserve information can be found in the reserve table and discussion included in Items 1 and 2 of Part I of this report, and in Supplemental Oil and Gas Disclosures of Part II, Item 8 of this report. 
+Successful efforts method of accounting. GAAP provides for two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method. Both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial 
+84 
+Table of Contents 
+statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more detailed description is included in Note 1 - Summary of Significant Accounting Policies of Part II, Item 8 of this report. 
+Revenue recognition. Our revenue recognition policy is significant because revenue is a key component of our results of operations and our forward-looking statements contained in our analysis of liquidity and capital resources. We derive our revenue primarily from the sale of produced oil, gas, and NGLs. We report revenue as the gross amounts we receive before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded in the month our production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a purchaser. At the end of each month, we make estimates of the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our properties, their historical performance, NYMEX and local spot market prices, and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are recorded in the month payment is received. A 10 percent change in our year end revenue accrual would have impacted net income before tax by approximately $16 million in 2012 . 
+Change in Net Profits Plan Liability. We record the estimated liability of future payments for our Net Profits Plan. The estimated liability is calculated based on a number of assumptions, including estimates of proved reserves, estimated future capital, present value discount factors, pricing assumptions, and overall market conditions. Please refer to Note 11 - Fair Value Measurements in Part II, Item 8 of this report for additional discussion . 
+Asset retirement obligations. We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells projected into the future based on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates, and determine what credit-adjusted risk-free discount rate to use. The impact to the accompanying statements of operations from these estimates is reflected in our depreciation, depletion, and amortization calculations and occurs over the remaining life of our respective oil and gas properties. Please refer to Note 9 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion. 
+Impairment of oil and gas properties. Our proved oil and gas properties are recorded at cost. We evaluate our proved properties for impairment when events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates. 
+Unproved oil and gas properties are assessed periodically for impairment on a lease-by-lease basis based on the remaining lease terms, drilling results, commodity price outlook, and future capital allocations. An impairment allowance is provided on unproven property when we determine that the property will not be developed or the carrying value will not be realized. Please refer to Impairment of Proved and Unproved Properties in Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of this report for impairment results. 
+Derivatives and Hedging. We periodically enter into commodity derivative contracts to manage our exposure to oil, gas and NGL price volatility. The accounting treatment for the change in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is designated as a cash flow hedge. Effective January 1, 2011, we elected to de-designate all of our commodity derivatives that had previously been designated as cash flow hedges as of December 31, 2010, and have elected to discontinue hedge accounting prospectively. 
+85 
+Table of Contents 
+Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in accumulated other comprehensive loss until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the statement of income because changes in fair value of the derivative offsets changes in the fair value of the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value and any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings. The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, whether or not the forecasted hedged transaction will occur, option pricing models, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. 
+Income taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not. Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations. A one percent increase and decrease in our effective tax rate would have changed our calculated income tax benefit by approximately $832,000 and $839,000 , respectively, for the year ended December 31, 2012 . 
+Accounting Matters 
+Please refer to the section entitled Recently Issued Accounting Standards under Note 1 – Summary of Significant Accounting Policies for additional information on the recent adoption of new authoritative accounting guidance in Part II, Item 8 of this report. 
+Environmental 
+We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes, and we are unable to predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital expenditures, liquidity, and results of operations. 
+Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. For additional information about hydraulic fracturing and related environmental matters, see Risk Factors – Risks Related to Our Business – Proposed federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. 
+86 
+Table of Contents 
+Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other ‘‘greenhouse gases’’ present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011. 
+In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. 
+The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. 
+In terms of opportunities, the regulation of greenhouse gas emissions and the introduction of alternative incentives, such as enhanced oil recovery, carbon sequestration and low carbon fuel standards, could benefit us in a variety of ways. For example, although climate change legislation could reduce the overall demand for the oil and natural gas that we produce, the relative demand for natural gas may increase because the burning of natural gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources, such as wind or solar power become more prevalent, natural gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel standards, natural gas may become a more attractive transportation fuel. Approximately 55 and 59 percent of our production on an MCFE basis in 2012 and 2011 , respectively, was natural gas. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and natural gas reservoirs, could also benefit us through the potential to obtain greenhouse gas emission allowances or offsets from or government incentives for the sequestration of carbon dioxide. 
+Non-GAAP Financial Measures 
+EBITDAX represents income (loss) before interest expense, interest income, income taxes, depreciation, depletion, amortization and accretion, exploration expense, property impairments, non-cash stock compensation expense, unrealized derivative gains and losses, change in the Net Profits Plan liability, and gains and losses on divestitures. EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally one-time or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that is presented because we believe that it provides useful additional 
+87 
+Table of Contents 
+information to investors, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to a financial covenant under our credit facility based on our debt to EBITDAX ratio. In addition, EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by (used in) operating activities, profitability, or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies. The following table provides reconciliations of our net income (loss) and net cash provided by operating activities to EBITDAX for the periods presented: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Net income (loss) (GAAP) 
+$ 
+(54,249 
+) 
+$ 
+215,416 
+$ 
+196,837 
+Interest expense 
+63,720 
+45,849 
+24,196 
+Interest income 
+(220 
+) 
+(466 
+) 
+(321 
+) 
+Income tax (benefit) expense 
+(29,268 
+) 
+123,585 
+118,059 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion 
+727,877 
+511,103 
+336,141 
+Exploration 
+81,809 
+46,776 
+56,184 
+Impairment of proved properties 
+208,923 
+219,037 
+6,127 
+Abandonment and impairment of unproved properties 
+16,342 
+7,367 
+1,986 
+Stock-based compensation expense 
+30,185 
+26,824 
+26,743 
+Unrealized derivative (gain) loss 
+(11,366 
+) 
+(62,757 
+) 
+8,899 
+Change in Net Profits Plan liability 
+(28,904 
+) 
+(25,477 
+) 
+(34,441 
+) 
+(Gain) loss on divestiture activity 
+27,018 
+(220,676 
+) 
+(155,277 
+) 
+EBITDAX (Non-GAAP) 
+1,031,867 
+886,581 
+585,133 
+Interest expense 
+(63,720 
+) 
+(45,849 
+) 
+(24,196 
+) 
+Interest income 
+220 
+466 
+321 
+Income tax benefit (expense) 
+29,268 
+(123,585 
+) 
+(118,059 
+) 
+Exploration 
+(81,809 
+) 
+(46,776 
+) 
+(56,184 
+) 
+Exploratory dry hole expense 
+20,861 
+277 
+289 
+Amortization of debt discount and deferred financing costs 
+6,769 
+18,299 
+13,464 
+Deferred income taxes 
+(29,638 
+) 
+123,789 
+114,517 
+Plugging and abandonment 
+(2,856 
+) 
+(5,849 
+) 
+(8,314 
+) 
+Other 
+527 
+(6,027 
+) 
+(3,993 
+) 
+Changes in current assets and liabilities 
+10,480 
+(40,794 
+) 
+(5,881 
+) 
+Net cash provided by operating activities (GAAP) 
+$ 
+921,969 
+$ 
+760,532 
+$ 
+497,097 
+Note: Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration. 
+ITEM 7A. 
+QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+The information required by this item is provided under the captions Commodity Price Risk and Interest Rate Risk and Summary of Oil, Gas, and NGL Derivative Contracts in Place in Item 7 above and is incorporated herein by reference. 
+88 
+Table of Contents 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Board of Directors and Stockholders of 
+SM Energy Company and Subsidiaries 
+Denver, Colorado 
+We have audited the accompanying consolidated balance sheets of SM Energy Company and subsidiaries (the “Company”) as of December 31, 2012 and 2011 , and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012 . These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits. 
+We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. 
+In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of SM Energy Company and subsidiaries as of December 31, 2012 and 2011 , and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 , in conformity with accounting principles generally accepted in the United States of America. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012 , based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 21, 2013 , expressed an unqualified opinion on the Company’s internal control over financial reporting. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 21, 2013 
+89 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED BALANCE SHEETS 
+(in thousands, except share amounts) 
+December 31, 
+2012 
+2011 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+5,926 
+$ 
+119,194 
+Accounts receivable (note 2) 
+254,805 
+210,368 
+Refundable income taxes 
+3,364 
+5,581 
+Prepaid expenses and other 
+30,017 
+68,026 
+Derivative asset 
+37,873 
+55,813 
+Deferred income taxes 
+8,579 
+4,222 
+Total current assets 
+340,564 
+463,204 
+Property and equipment (successful efforts method), at cost: 
+Land 
+1,845 
+1,548 
+Proved oil and gas properties 
+5,401,684 
+4,378,987 
+Less - accumulated depletion, depreciation, and amortization 
+(2,376,170 
+) 
+(1,766,445 
+) 
+Unproved oil and gas properties 
+175,287 
+120,966 
+Wells in progress 
+273,928 
+273,428 
+Materials inventory, at lower of cost or market 
+13,444 
+16,537 
+Oil and gas properties held for sale net of accumulated depletion, depreciation and amortization of $20,676 in 2012 and $10,714 in 2011 
+33,620 
+246 
+Other property and equipment, net of accumulated depreciation of $22,442 in 2012 and $23,985 in 2011 
+153,559 
+71,369 
+Total property and equipment, net 
+3,677,197 
+3,096,636 
+Other noncurrent assets: 
+Derivative asset 
+16,466 
+31,062 
+Restricted cash 
+86,773 
+124,703 
+Other noncurrent assets 
+78,529 
+83,375 
+Total other noncurrent assets 
+181,768 
+239,140 
+Total Assets 
+$ 
+4,199,529 
+$ 
+3,798,980 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued expenses (note 2) 
+$ 
+525,627 
+$ 
+456,999 
+Derivative liability 
+8,999 
+42,806 
+Other current liabilities 
+6,920 
+6,000 
+Total current liabilities 
+541,546 
+505,805 
+Noncurrent liabilities: 
+Long-term credit facility 
+340,000 
+— 
+3.50% Senior Convertible Notes, net of unamortized discount of $2,431 in 2011 
+— 
+285,069 
+6.625% Senior Notes due 2019 
+350,000 
+350,000 
+6.50% Senior Notes due 2021 
+350,000 
+350,000 
+6.50% Senior Notes due 2023 
+400,000 
+— 
+Asset retirement obligation 
+112,912 
+87,167 
+Asset retirement obligation associated with oil and gas properties held for sale 
+1,393 
+1,277 
+Net Profits Plan liability 
+78,827 
+107,731 
+Deferred income taxes 
+537,383 
+568,263 
+Derivative liability 
+6,645 
+12,875 
+Other noncurrent liabilities 
+66,357 
+67,853 
+Total noncurrent liabilities 
+2,243,517 
+1,830,235 
+Commitments and contingencies (note 6) 
+Stockholders' equity: 
+Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 66,245,816 shares in 2012 and 64,145,482 shares in 2011; outstanding, net of treasury shares: 66,195,235 shares in 2012 and 64,064,415 shares in 2011 
+662 
+641 
+Additional paid-in capital 
+233,642 
+216,966 
+Treasury stock, at cost: 50,581 shares in 2012 and 81,067 shares in 2011 
+(1,221 
+) 
+(1,544 
+) 
+Retained earnings 
+1,190,397 
+1,251,157 
+Accumulated other comprehensive loss 
+(9,014 
+) 
+(4,280 
+) 
+Total stockholders' equity 
+1,414,466 
+1,462,940 
+Total Liabilities and Stockholders' Equity 
+$ 
+4,199,529 
+$ 
+3,798,980 
+The accompanying notes are an integral part of these consolidated financial statements. 
+90 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+(in thousands, except per share amounts) 
+For the Years 
+Ended December 31, 
+2012 
+2011 
+2010 
+Operating revenues and other income: 
+Oil, gas, and NGL production revenue 
+$ 
+1,473,868 
+$ 
+1,332,392 
+$ 
+836,288 
+Realized hedge gain (loss) 
+3,866 
+(20,707 
+) 
+23,465 
+Gain (loss) on divestiture activity 
+(27,018 
+) 
+220,676 
+155,277 
+Marketed gas system revenue 
+52,808 
+69,898 
+70,110 
+Other operating revenue 
+1,578 
+1,059 
+7,694 
+Total operating revenues and other income 
+1,505,102 
+1,603,318 
+1,092,834 
+Operating expenses: 
+Oil, gas, and NGL production expense 
+391,872 
+290,111 
+195,075 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion 
+727,877 
+511,103 
+336,141 
+Exploration 
+90,248 
+53,537 
+63,860 
+Impairment of proved properties 
+208,923 
+219,037 
+6,127 
+Abandonment and impairment of unproved properties 
+16,342 
+7,367 
+1,986 
+General and administrative 
+119,815 
+118,526 
+106,663 
+Change in Net Profits Plan liability 
+(28,904 
+) 
+(25,477 
+) 
+(34,441 
+) 
+Unrealized and realized derivative (gain) loss 
+(55,630 
+) 
+(37,086 
+) 
+8,899 
+Marketed gas system expense 
+47,583 
+64,249 
+66,726 
+Other operating expense 
+6,993 
+17,567 
+3,027 
+Total operating expenses 
+1,525,119 
+1,218,934 
+754,063 
+Income (loss) from operations 
+(20,017 
+) 
+384,384 
+338,771 
+Nonoperating income (expense): 
+Interest income 
+220 
+466 
+321 
+Interest expense 
+(63,720 
+) 
+(45,849 
+) 
+(24,196 
+) 
+Income (loss) before income taxes 
+(83,517 
+) 
+339,001 
+314,896 
+Income tax benefit (expense) 
+29,268 
+(123,585 
+) 
+(118,059 
+) 
+Net income (loss) 
+$ 
+(54,249 
+) 
+$ 
+215,416 
+$ 
+196,837 
+Basic weighted-average common shares outstanding 
+65,138 
+63,755 
+62,969 
+Diluted weighted-average common shares outstanding 
+65,138 
+67,564 
+64,689 
+Basic net income (loss) per common share 
+$ 
+(0.83 
+) 
+$ 
+3.38 
+$ 
+3.13 
+Diluted net income (loss) per common share 
+$ 
+(0.83 
+) 
+$ 
+3.19 
+$ 
+3.04 
+The accompanying notes are an integral part of these consolidated financial statements. 
+91 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) 
+(in thousands) 
+For the Years 
+Ended December 31, 
+2012 
+2011 
+2010 
+Net income (loss) 
+$ 
+(54,249 
+) 
+$ 
+215,416 
+$ 
+196,837 
+Other comprehensive income (loss), net of tax: 
+Change in derivative instrument fair value 
+— 
+— 
+16,811 
+Reclassification to earnings 
+(2,264 
+) 
+12,997 
+6,641 
+Pension liability adjustment 
+(2,470 
+) 
+(1,795 
+) 
+(980 
+) 
+Total other comprehensive income (loss), net of tax 
+(4,734 
+) 
+11,202 
+22,472 
+Total comprehensive income (loss) 
+$ 
+(58,983 
+) 
+$ 
+226,618 
+$ 
+219,309 
+The accompanying notes are an integral part of these consolidated financial statements. 
+92 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 
+(in thousands, except share amounts) 
+Additional Paid-in Capital 
+Accumulated Other Comprehensive Loss 
+Total Stockholders’ Equity 
+Common Stock 
+Treasury Stock 
+Retained Earnings 
+Shares 
+Amount 
+Shares 
+Amount 
+Balances, January 1, 2010 
+62,899,122 
+$ 
+629 
+$ 
+160,516 
+(126,893 
+) 
+$ 
+(1,204 
+) 
+$ 
+851,583 
+$ 
+(37,954 
+) 
+$ 
+973,570 
+Net income 
+— 
+— 
+— 
+— 
+— 
+196,837 
+— 
+196,837 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+— 
+— 
+22,472 
+22,472 
+Cash dividends, $ 0.10 per share 
+— 
+— 
+— 
+— 
+— 
+(6,297 
+) 
+— 
+(6,297 
+) 
+Issuance of common stock under Employee Stock Purchase Plan 
+52,948 
+1 
+1,669 
+— 
+— 
+— 
+— 
+1,670 
+Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings, including income tax cost of RSUs 
+113,103 
+1 
+(2,094 
+) 
+— 
+— 
+— 
+— 
+(2,093 
+) 
+Issuance of common stock upon stock option exercises, including income tax benefit 
+346,377 
+3 
+5,621 
+— 
+— 
+— 
+— 
+5,624 
+Stock-based compensation expense 
+1,250 
+— 
+25,962 
+24,258 
+781 
+— 
+— 
+26,743 
+Balances, December 31, 2010 
+63,412,800 
+$ 
+634 
+$ 
+191,674 
+(102,635 
+) 
+$ 
+(423 
+) 
+$ 
+1,042,123 
+$ 
+(15,482 
+) 
+$ 
+1,218,526 
+Net income 
+— 
+— 
+— 
+— 
+— 
+215,416 
+— 
+215,416 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+— 
+— 
+11,202 
+11,202 
+Cash dividends, $ 0.10 per share 
+— 
+— 
+— 
+— 
+— 
+(6,382 
+) 
+— 
+(6,382 
+) 
+Issuance of common stock under Employee Stock Purchase Plan 
+41,358 
+— 
+2,300 
+— 
+— 
+— 
+— 
+2,300 
+Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings 
+278,773 
+3 
+(9,976 
+) 
+— 
+— 
+— 
+— 
+(9,973 
+) 
+Issuance of common stock upon stock option exercises 
+412,551 
+4 
+5,023 
+— 
+— 
+— 
+— 
+5,027 
+Stock-based compensation expense 
+— 
+— 
+27,945 
+21,568 
+(1,121 
+) 
+— 
+— 
+26,824 
+Balances, December 31, 2011 
+64,145,482 
+$ 
+641 
+$ 
+216,966 
+(81,067 
+) 
+$ 
+(1,544 
+) 
+$ 
+1,251,157 
+$ 
+(4,280 
+) 
+$ 
+1,462,940 
+Net loss 
+— 
+— 
+— 
+— 
+— 
+(54,249 
+) 
+— 
+(54,249 
+) 
+Other comprehensive loss 
+— 
+— 
+— 
+— 
+— 
+— 
+(4,734 
+) 
+(4,734 
+) 
+Cash dividends, $ 0.10 per share 
+— 
+— 
+— 
+— 
+— 
+(6,511 
+) 
+— 
+(6,511 
+) 
+Issuance of common stock under Employee Stock Purchase Plan 
+66,485 
+1 
+2,775 
+— 
+— 
+— 
+— 
+2,776 
+Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings 
+929,375 
+9 
+(21,631 
+) 
+— 
+— 
+— 
+— 
+(21,622 
+) 
+Issuance of common stock upon stock option exercises 
+240,368 
+2 
+3,038 
+— 
+— 
+— 
+— 
+3,040 
+Conversion of 3.50% Senior Convertible Notes to common stock, including income tax benefit of conversion 
+864,106 
+9 
+2,632 
+— 
+— 
+— 
+— 
+2,641 
+Stock-based compensation expense 
+— 
+— 
+29,862 
+30,486 
+323 
+— 
+— 
+30,185 
+Balances, December 31, 2012 
+66,245,816 
+$ 
+662 
+$ 
+233,642 
+(50,581 
+) 
+$ 
+(1,221 
+) 
+$ 
+1,190,397 
+$ 
+(9,014 
+) 
+$ 
+1,414,466 
+The accompanying notes are an integral part of these consolidated financial statements. 
+93 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+(in thousands) 
+For the Years Ended 
+December 31, 
+2012 
+2011 
+2010 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+(54,249 
+) 
+$ 
+215,416 
+$ 
+196,837 
+Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
+(Gain) loss on divestiture activity 
+27,018 
+(220,676 
+) 
+(155,277 
+) 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion 
+727,877 
+511,103 
+336,141 
+Exploratory dry hole expense 
+20,861 
+277 
+289 
+Impairment of proved properties 
+208,923 
+219,037 
+6,127 
+Abandonment and impairment of unproved properties 
+16,342 
+7,367 
+1,986 
+Stock-based compensation expense 
+30,185 
+26,824 
+26,743 
+Change in Net Profits Plan liability 
+(28,904 
+) 
+(25,477 
+) 
+(34,441 
+) 
+Unrealized derivative (gain) loss 
+(11,366 
+) 
+(62,757 
+) 
+8,899 
+Amortization of debt discount and deferred financing costs 
+6,769 
+18,299 
+13,464 
+Deferred income taxes 
+(29,638 
+) 
+123,789 
+114,517 
+Plugging and abandonment 
+(2,856 
+) 
+(5,849 
+) 
+(8,314 
+) 
+Other 
+527 
+(6,027 
+) 
+(3,993 
+) 
+Changes in current assets and liabilities: 
+Accounts receivable 
+(21,389 
+) 
+(41,998 
+) 
+(47,153 
+) 
+Refundable income taxes 
+2,217 
+2,901 
+24,291 
+Prepaid expenses and other 
+(1,484 
+) 
+16,376 
+(35,363 
+) 
+Accounts payable and accrued expenses 
+31,136 
+(18,073 
+) 
+53,198 
+Excess income tax benefit from the exercise of stock awards 
+— 
+— 
+(854 
+) 
+Net cash provided by operating activities 
+921,969 
+760,532 
+497,097 
+Cash flows from investing activities: 
+Net proceeds from sale of oil and gas properties 
+55,375 
+364,522 
+311,504 
+Capital expenditures 
+(1,507,828 
+) 
+(1,633,093 
+) 
+(668,288 
+) 
+Acquisition of oil and gas properties 
+(5,773 
+) 
+— 
+(664 
+) 
+Other 
+893 
+3,661 
+(4,125 
+) 
+Net cash used in investing activities 
+(1,457,333 
+) 
+(1,264,910 
+) 
+(361,573 
+) 
+Cash flows from financing activities: 
+Proceeds from credit facility 
+1,609,000 
+322,000 
+571,559 
+Repayment of credit facility 
+(1,269,000 
+) 
+(370,000 
+) 
+(711,559 
+) 
+Debt issuance costs related to credit facility 
+— 
+(8,719 
+) 
+— 
+Net proceeds from 6.625% Senior Notes due 2019 
+— 
+341,122 
+— 
+Net proceeds from 6.50% Senior Notes due 2021 
+— 
+343,120 
+— 
+Net proceeds from 6.50% Senior Notes due 2023 
+392,138 
+— 
+— 
+Repayment of 3.50% Senior Convertible Notes 
+(287,500 
+) 
+— 
+— 
+Proceeds from sale of common stock 
+5,816 
+7,327 
+6,440 
+Dividends paid 
+(6,511 
+) 
+(6,382 
+) 
+(6,297 
+) 
+Net share settlement from issuance of stock awards 
+(21,622 
+) 
+(9,973 
+) 
+(2,093 
+) 
+Excess income tax benefit from the exercise of stock awards 
+— 
+— 
+854 
+Other 
+(225 
+) 
+— 
+— 
+Net cash provided by (used in) financing activities 
+422,096 
+618,495 
+(141,096 
+) 
+Net change in cash and cash equivalents 
+(113,268 
+) 
+114,117 
+(5,572 
+) 
+Cash and cash equivalents at beginning of period 
+119,194 
+5,077 
+10,649 
+Cash and cash equivalents at end of period 
+$ 
+5,926 
+$ 
+119,194 
+$ 
+5,077 
+The accompanying notes are an integral part of these consolidated financial statements. 
+94 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) 
+Supplemental schedule of additional cash flow information and non-cash investing and financing activities: 
+For the Years Ended 
+December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Cash paid for interest, net of capitalized interest 
+$ 
+(51,328 
+) 
+$ 
+(22,133 
+) 
+$ 
+(13,340 
+) 
+Net cash refunded for income taxes 
+$ 
+1,389 
+$ 
+4,046 
+$ 
+25,578 
+At December 31, 2012 , 2011 , and 2010 , $262.8 million , $214.8 million , and $238.5 million , respectively, are included as additions to oil and gas properties and accounts payable and accrued expenses. These oil and gas property additions are reflected in cash used in investing activities in the periods that the payables are settled. 
+95 
+Table of Contents 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+Note 1 – Summary of Significant Accounting Policies 
+Description of Operations 
+SM Energy is an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America, with a current focus on oil and liquids-rich resource plays. 
+Basis of Presentation 
+The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and have been prepared in accordance with GAAP and the instructions to Form 10-K and regulation S-X. Subsidiaries that the Company does not control are accounted for using the equity or cost methods as appropriate. Equity method investments are included in other noncurrent assets in the accompanying consolidated balance sheets (“accompanying balance sheets”). Intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2012 , through the filing date of this report. 
+Use of Estimates in the Preparation of Financial Statements 
+The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization (“DD&A”), impairment of proved properties, asset retirement obligations, and the Net Profits Interest Bonus Plan (“Net Profits Plan”) liability, each of which represents a significant component of the accompanying consolidated financial statements. 
+Cash and Cash Equivalents 
+The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. 
+Restricted Cash 
+The Company’s restricted cash balance represents cash payments received from Mitsui that are contractually restricted to be used solely for development operations pursuant to the Company’s Acquisition and Development Agreement with Mitsui and accordingly are classified as non-current assets. Please refer to Note 12- Acquisition and Development Agreement and Carry and Earning Agreement for additional information. 
+Accounts Receivable 
+The Company’s accounts receivables consist mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months, and the Company has had minimal bad debts. 
+96 
+Table of Contents 
+Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. As of December 31, 2012 , and 2011 , the Company had no allowance for doubtful accounts recorded. 
+Concentration of Credit Risk and Major Customers 
+The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to continuous review. During 2012 , we had two major customers, Regency Gas Services LLC and Plains Marketing LP , which accounted for approximately 21 percent and 13 percent , respectively, of our total production revenue. During 2011 and 2010 , we had one major customer, Regency Gas Services LLC , individually account for approximately 18 percent and 11 percent , respectively, of our total production revenue. 
+The Company currently uses 10 separate counterparties for its oil, gas, and NGL commodity derivatives, all of which are participating lenders in the Company’s credit facility. Two of our counterparties were downgraded during 2012, but all maintain investment grade ratings. Nine counterparties carry corporate credit ratings at or exceeding A- and Baa2 by Standard & Poor’s and Moody’s, respectively. The remaining counterparty fell to BBB- and Baa2, respectively. In response, the Company requires cash collateral to be posted when its portfolio of trades with that counterparty is in an overall asset position. 
+The Company has accounts in the following locations with a national bank: Denver, Colorado; Shreveport, Louisiana; Houston, Texas; Midland, Texas; and Billings, Montana. The Company has accounts with a local bank in Tulsa, Oklahoma. The Company’s policy is to invest in highly-rated instruments and to limit the amount of credit exposure at each individual institution. 
+Oil and Gas Producing Activities 
+The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in cash flows from investing activities as part of capital expenditures within the accompanying consolidated statements of cash flows (“accompanying statements of cash flows”). The costs of development wells are capitalized whether those wells are successful or unsuccessful. 
+DD&A of capitalized costs related to proved oil and gas properties is calculated on a pool-by-pool basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. As of December 31, 2012 , and 2011 , the Company’s estimated salvage value was $64.4 million and $64.1 million , respectively. 
+Materials Inventory 
+The Company’s materials inventory is primarily comprised of tubular goods to be used in future drilling operations. Materials inventory is valued at the lower of cost or market and totaled $13.4 million and $16.5 million at December 31, 2012 , and 2011 , respectively. There were no materials inventory write-downs for the years ended December 31, 2012 , 2011 , or 2010 . 
+97 
+Table of Contents 
+Assets Held for Sale 
+Any properties held for sale as of the balance sheet date have been classified as assets held for sale and are separately presented on the accompanying balance sheets at the lower of net book value or fair value less the cost to sell. The asset retirement obligation liabilities related to such properties have been reclassified to asset retirement obligations associated with oil and gas properties held for sale in the accompanying balance sheets. For additional discussion on assets held for sale, please refer to Note 3 – Divestitures and Assets Held for Sale . 
+Other Property and Equipment 
+Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from three to thirty years , or the unit of output method where appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts. 
+Intangible Assets 
+As of December 31, 2012 , and 2011 , the Company had $10.8 million and $7.1 million , respectively, of intangible assets consisting of acquired water rights, which are included as other noncurrent assets in the accompanying balance sheets. All indefinite lived intangible assets are evaluated for impairment if such indicators arise and at least annually. 
+Cash Settlement Balancing 
+The Company uses the sales method of accounting for gas revenue whereby sales revenue is recognized on all gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. An asset or liability is recognized to the extent that there is an imbalance in excess of the remaining gas reserves on the underlying properties. As of December 31, 2012 , and 2011 , the Company has recorded a receivable of $1.7 million and $1.9 million , respectively, and a liability of $1.3 million and $1.1 million , respectively, which is included as other noncurrent assets and other noncurrent liabilities in the accompanying balance sheets. 
+Derivative Financial Instruments 
+The Company seeks to manage or reduce commodity price risk on production by entering into derivative contracts. The Company seeks to minimize its basis risk and indexes its oil derivative contracts to NYMEX prices, its NGL derivative contracts to OPIS prices, and the majority of its gas derivative contracts to various regional index prices associated with pipelines in proximity to the Company’s areas of gas production. For additional discussion on derivatives, please see Note 10 – Derivative Financial Instruments . 
+Net Profits Plan 
+The Company records the estimated fair value of expected future payments made under the Net Profits Plan as a noncurrent liability in the accompanying balance sheets. The underlying assumptions used in the calculation of the estimated liability include estimates of production, proved reserves, recurring and workover lease operating expense, transportation, production and ad valorem tax rates, present value discount factors, pricing assumptions, and overall market conditions. The estimates used in calculating the long-term liability are adjusted from period-to-period based on the most current information attributable to the underlying assumptions. Changes in the estimated liability of future payments associated with the Net Profits Plan are recorded as increases or decreases to expense in the current period as a separate line item in the accompanying consolidated statements of operations (“accompanying statements of operations”), as these changes are considered changes in estimates. 
+98 
+Table of Contents 
+The distribution amounts due to participants and payable in each period under the Net Profits Plan as cash compensation related to periodic operations are recognized as compensation expense and are included within general and administrative expense and exploration expense in the accompanying statements of operations. The corresponding current liability is included in accounts payable and accrued expenses in the accompanying balance sheets. This treatment provides for a consistent matching of cash expense with net cash flows from the oil and gas properties in each respective pool of the Net Profits Plan. For additional discussion, please refer to the heading Net Profits Plan in Note 7 – Compensation Plans and Note 11 – Fair Value Measurements . 
+Asset Retirement Obligations 
+The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. For additional discussion, please refer to Note 9 – Asset Retirement Obligations . 
+Revenue Recognition 
+The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported separately as expenses and are included in oil, gas, and NGL production expense in the accompanying statements of operations. Revenue is recorded in the month the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses its knowledge of its properties, their historical performance, NYMEX, OPIS, and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates. 
+Impairment of Proved and Unproved Properties 
+Proved oil and gas property costs are evaluated for impairment and reduced to fair value, which is based on expected future discounted cash flows, when there is an indication that the carrying costs may not be recoverable. Expected future cash flows are calculated on all developed proved reserves and risk adjusted proved undeveloped, probable, and possible reserves using a discount rate and price forecasts selected by the Company’s management. The discount rate is a rate that management believes is representative of current market conditions. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. An impairment is recorded on unproved property when the Company determines that either the property will not be developed or the carrying value is not realizable. 
+The Company recorded $208.9 million , $219.0 million , and $6.1 million , of proved property impairments for the years ended December 31, 2012 , 2011 , and 2010 , respectively. The impairments in 2012 were a result of the Company’s write-down of Wolfberry assets in its Permian region due to negative engineering revisions and the Company’s Haynesville shale assets as a result of low natural gas prices. The impairments in 2011 were related to the Company’s James Lime, Cotton Valley, and Haynesville shale assets as a result of significantly lower natural gas prices at the end of 2011. 
+99 
+Table of Contents 
+For the years ended December 31, 2012 , 2011 , and 2010 , the Company recorded expense related to the abandonment and impairment of unproved properties of $16.3 million , $7.4 million , and $2.0 million , respectively. The Company’s abandonment and impairment of unproved properties in 2012 related to acreage that the Company no longer intends to develop in the Rocky Mountain region. 
+Sales of Proved and Unproved Properties 
+The partial sale of proved properties within an existing field is accounted for as normal retirement and no gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. 
+The partial sale of unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to the ultimate recovery of the cost applicable to the interest retained. A gain on divestiture activity is recognized to the extent that the sales price exceeds the carrying amount of the unproved property. A gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of unproved property. For additional discussion, please refer to Note 3 – Divestitures and Assets Held for Sale . 
+Stock-Based Compensation 
+At December 31, 2012 , the Company had stock-based employee compensation plans that included RSUs, PSUs, restricted stock awards, and stock options issued to employees and non-employee directors, as more fully described in Note 7 - Compensation Plans. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant. 
+Income Taxes 
+The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. 
+Earnings per Share 
+Basic net income (loss) per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company. 
+Diluted net income or loss per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of in-the-money outstanding stock options, unvested RSUs, contingent PSUs, and shares into which the 3.50% Senior Convertible Notes were convertible. When there is a loss from continuing operations, as was the case for the year ended December 31, 2012, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of earnings per share. 
+PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that 
+100 
+Table of Contents 
+date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 – Compensation Plans under the heading Performance Share Units Under the Equity Incentive Compensation Plan . 
+The Company called for redemption of its 3.50% Senior Convertible Notes on April 2, 2012, after which the majority of the holders of the outstanding 3.50% Senior Convertible Notes elected to convert their notes. The Company issued 864,106 common shares upon conversion, and these shares were included in the calculation of basic weighted-average common shares outstanding for the year ended December 31, 2012 . Please refer to Note 5 - Long-term Debt for additional discussion. Prior to calling the 3.50% Senior Convertible Notes for redemption, the Company’s notes had a net-share settlement right giving the Company the option to irrevocably elect, by notice to the trustee under the indenture for the notes, to settle the Company’s obligation, in the event that holders of the notes elected to convert all or a portion of their notes, by delivering cash in an amount equal to each $1,000 principal amount of notes surrendered for conversion and, if applicable, at the Company’s option, shares of common stock or cash, or any combination of common stock and cash, for the amount of conversion value in excess of the principal amount. Prior to the settlement of the Company’s 3.50% Senior Convertible Notes, potentially dilutive shares associated with the conversion feature were accounted for using the treasury stock method when shares of the Company’s common stock traded at an average closing price that exceeded the $54.42 conversion price. Shares of the Company’s common stock traded at an average closing price exceeding the conversion price and were included on an adjusted weighted basis for the portion of the year ended December 31, 2012 , for which they were outstanding. Shares of the Company’s common stock traded at an average closing price exceeding the $54.42 conversion price for the twelve-month period ended December 31, 2011, making the 3.50% Senior Convertible Notes dilutive for that period. Shares of the Company's common stock did not trade at an average closing price exceeding the $54.42 conversion price for the year ended December 31, 2010. Therefore, the 3.50% Senior Convertible Notes were not dilutive and did not impact the diluted earnings per share calculation for the year ended December 31, 2010. 
+The treasury stock method is used to measure the dilutive impact of in-the-money stock options, unvested RSUs, contingent PSUs, and 3.50% Senior Convertible Notes. 
+The following table details the weighted-average dilutive and anti-dilutive securities related to stock options, RSUs, PSUs, and the 3.50% Senior Convertible Notes for the years presented: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Dilutive 
+— 
+3,809 
+1,720 
+Anti-dilutive 
+2,102 
+— 
+— 
+101 
+Table of Contents 
+The following table sets forth the calculations of basic and diluted earnings per share: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands, except per share amounts) 
+Net income (loss) 
+$ 
+(54,249 
+) 
+$ 
+215,416 
+$ 
+196,837 
+Basic weighted-average common shares outstanding 
+65,138 
+63,755 
+62,969 
+Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs 
+— 
+2,592 
+1,720 
+Add: dilutive effect of 3.50% Senior Convertible Notes 
+— 
+1,217 
+— 
+Diluted weighted-average common shares outstanding 
+65,138 
+67,564 
+64,689 
+Basic net income (loss) per common share 
+$ 
+(0.83 
+) 
+$ 
+3.38 
+$ 
+3.13 
+Diluted net income (loss) per common share 
+$ 
+(0.83 
+) 
+$ 
+3.19 
+$ 
+3.04 
+Comprehensive Income (Loss) 
+Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss). 
+102 
+Table of Contents 
+The changes in the balances of components comprising other comprehensive income (loss) are presented in the following table: 
+Change in Derivative Instrument Fair Value 
+Derivative Reclassification to Earnings 
+Pension Liability Adjustments 
+(in thousands) 
+For the year ended December 31, 2010 
+Before tax income (loss) 
+$ 
+26,904 
+$ 
+10,608 
+$ 
+(1,570 
+) 
+Tax benefit (expense) 
+(10,093 
+) 
+(3,967 
+) 
+590 
+Income (loss), net of tax 
+$ 
+16,811 
+$ 
+6,641 
+$ 
+(980 
+) 
+For the year ended December 31, 2011 
+Before tax income (loss) 
+$ 
+— 
+$ 
+20,707 
+$ 
+(2,779 
+) 
+Tax benefit (expense) 
+— 
+(7,710 
+) 
+984 
+Income (loss), net of tax 
+$ 
+— 
+$ 
+12,997 
+$ 
+(1,795 
+) 
+For the year ended December 31, 2012 
+Before tax (loss) 
+$ 
+— 
+$ 
+(3,865 
+) 
+$ 
+(3,909 
+) 
+Tax benefit 
+— 
+1,601 
+1,439 
+(Loss), net of tax 
+$ 
+— 
+$ 
+(2,264 
+) 
+$ 
+(2,470 
+) 
+Fair Value of Financial Instruments 
+The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had $340.0 million of outstanding loans under its credit facility as of December 31, 2012 . The Company had no borrowings outstanding under its credit facility as of December 31, 2011 . The Company’s 3.50% Senior Convertible Notes, 2019 Notes, 2021 Notes, and 2023 Notes, are recorded at cost, and the fair values are disclosed in Note 11 - Fair Value Measurements. The Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. 
+Industry Segment and Geographic Information 
+The Company operates exclusively in the exploration and production segment of the oil and gas industry and all of the Company’s operations are conducted entirely in the United States. The Company reports as a single industry segment. The Company’s gas marketing function provides mostly internal services and acts as the first purchaser of natural gas and natural gas liquids produced by the Company in certain cases. The Company considers its marketing function as ancillary to its oil and gas producing activities. The amount of income these operations generate from marketing gas produced by third parties is not material to the Company’s results of operations, and segmentation of such activity would not provide a better understanding of the Company’s performance. However, gross revenue and expense related to marketing activities for gas produced by third parties are presented in the marketed gas system revenue and marketed gas system expense line items in the accompanying statements of operations. 
+103 
+Table of Contents 
+Off-Balance Sheet Arrangements 
+The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. The Company has not been involved in any unconsolidated SPE transactions. 
+The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that SM Energy is the primary beneficiary of a variable interest entity, that entity is consolidated into SM Energy. 
+Recently Issued Accounting Standards 
+On January 1, 2012, the Company adopted new fair value measurement authoritative accounting guidance issued by the FASB, that clarifies the application of fair value measurement and disclosure requirements and changes particular principles and requirements for measuring fair value. For each class of assets and liabilities not measured at fair value in the Company’s financial statements but for which fair value is disclosed, this guidance requires the Company to disclose the nature, characteristics, and risks of the asset or liability and the level of the fair value hierarchy within which the fair value measurement is categorized. Please refer to Note 11 - Fair Value Measurements in which the changes to the Company’s financial statements resulting from the new authoritative guidance are presented. 
+On January 1, 2012, the Company adopted new authoritative accounting guidance issued by the FASB stating an entity that reports items of other comprehensive income has the option to present the components of comprehensive income in either one continuous financial statement or two consecutive financial statements, including reclassification adjustments. The adoption of this statement did not have a material impact on the Company. The Company has elected to present a separate statement of comprehensive income, including the individual components, titled Consolidated Statements of Comprehensive Income (Loss), as part of these financial statements. Additionally, the Company has elected to present the reclassification adjustments under the heading Comprehensive Income (Loss), above. 
+On September 30, 2012, the Company elected to early adopt new authoritative accounting guidance issued by the FASB, which provided that an entity that tests indefinite-lived intangible assets for impairment has the option to assess qualitative factors to determine whether it is more likely than not that an asset is impaired as a basis for determining whether a quantitative test is necessary. The adoption of this statement did not have a material impact on the Company’s financial statements. 
+There are no new significant accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of December 31, 2012 . 
+104 
+Table of Contents 
+Note 2 – Accounts Receivable and Accounts Payable and Accrued Expenses 
+Accounts receivable are comprised of the following: 
+As of December 31, 
+2012 
+2011 
+(in thousands) 
+Accrued oil, gas, and NGL production revenue 
+$ 
+160,568 
+$ 
+149,384 
+Amounts due from joint interest owners 
+42,740 
+30,784 
+Receivable due from Mitsui 
+19,931 
+— 
+State severance tax refunds 
+17,237 
+14,979 
+Other 
+14,329 
+15,221 
+Total accounts receivable 
+$ 
+254,805 
+$ 
+210,368 
+Accounts payable and accrued expenses are comprised of the following: 
+As of December 31, 
+2012 
+2011 
+(in thousands) 
+Accrued drilling costs 
+$ 
+243,611 
+$ 
+189,749 
+Revenue and severance tax payable 
+65,494 
+61,613 
+Accrued lease operating expense 
+28,037 
+25,197 
+Accrued property taxes 
+9,478 
+6,994 
+Joint owner advances 
+69,639 
+79,138 
+Accrued compensation 
+35,607 
+43,056 
+Accrued interest 
+25,027 
+14,646 
+Other 
+48,734 
+36,606 
+Total accounts payable and accrued expenses 
+$ 
+525,627 
+$ 
+456,999 
+Note 3 – Divestitures and Assets Held for Sale 
+During 2012, the Company divested of various non-strategic properties located in its Rocky Mountain and Mid-Continent regions for a total of $57.4 million in total divestiture proceeds, before marketing costs, Net Profits Plan payments, and legal fees (referred throughout this report as “divestiture proceeds”). The estimated net gain on these divestitures is $6.9 million . The final sales prices related to these divestitures are subject to normal post-closing adjustments and are expected to be finalized during the first half of 2013. See discussion below regarding the loss on unsuccessful sale of properties, which is included in gain (loss) on divestiture activity in the accompanying statements of operations. 
+2011 Divestiture Activity 
+• 
+Eagle Ford Shale Divestiture. In August 2011, the Company divested of certain operated Eagle Ford shale assets located in its South Texas & Gulf Coast region. This divestiture was comprised of the Company’s entire operated acreage in LaSalle County, Texas, as well as an immaterial adjacent block of its operated acreage in Dimmit County, Texas. Total divestiture proceeds were $230.7 million . The final gain on this divestiture was $193.8 million . Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement for information on additional Eagle Ford activity in 2011. 
+• 
+Mid-Continent Divestiture. In June 2011, the Company divested of certain non-strategic assets located in its Mid-Continent region. Total divestiture proceeds were $35.8 million . The final gain on this divestiture was $28.5 million . 
+105 
+Table of Contents 
+• 
+Rocky Mountain Divestiture. In January 2011, the Company divested of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were $45.5 million . The final gain on this divestiture was $27.2 million . 
+2010 Divestiture Activity 
+• 
+Permian Divestiture. In December 2010 , the Company completed the divestiture of certain non-strategic assets located in its Permian region. Total divestiture proceeds were $54.7 million . The final gain on this divestiture was $18.4 million . 
+• 
+Sequel Divestiture. In March 2010 , the Company completed the divestiture of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were $129.1 million . The final gain on this divestiture was $53.1 million . A portion of the transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”). 
+• 
+Legacy Divestiture. In February 2010 , the Company completed the divestiture of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were $125.3 million . The final gain on this divestiture was $66.7 million . A portion of the transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code. 
+Assets Held for Sale 
+Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less costs to sell. Subsequent changes to the estimated fair value less the cost to sell will impact the measurement of assets held for sale for which fair value less costs to sell is determined to be less than the carrying value of the assets. 
+A s of December 31, 2012 , the accompanying balance sheets present $33.6 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense. A corresponding asset retirement obligation liability of $1.4 million is separately presented. The assets held for sale include the Company’s Marcellus shale assets located in Pennsylvania and certain assets located in the Company’s Rocky Mountain region, all of which are recorded at the lesser of their carrying values or their respective fair value less estimated costs to sell. Write-downs to fair value less estimated costs to sell are reflected in the gain (loss) on divestiture activity line item in the accompanying statements of operations. 
+During 2012, the Company reclassified a portion of the assets previously held for sale to assets held and used, as the assets were no longer being actively marketed. The assets were measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any DD&A that would have been recognized had the assets been continuously held and used, or the fair value of the assets at the date they no longer met the criteria as held for sale. As a result of this measurement, the Company recognized $1.7 million of DD&A expense and a $33.9 million loss on unsuccessful sale of properties, which is included in gain (loss) on divestiture activity in the accompanying statements of operations. 
+Subsequent to December 31, 2012 , the Company divested of a portion of its properties located in its Rocky Mountain region that were classified as held for sale at year end. Total divestiture proceeds were $9.2 million . The estimated gain on this divestiture is $2.5 million and is expected to be finalized during the first half of 2013. 
+The Company determined that neither these planned nor executed asset sales qualify for discontinued operations accounting under financial statement presentation authoritative guidance. 
+106 
+Table of Contents 
+Note 4 – Income Taxes 
+The provision for income taxes consists of the following: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Current portion of income tax benefit (expense) 
+Federal 
+$ 
+— 
+$ 
+1,757 
+$ 
+(2,903 
+) 
+State 
+(370 
+) 
+(1,553 
+) 
+(639 
+) 
+Deferred portion of income tax benefit (expense) 
+29,638 
+(123,789 
+) 
+(114,517 
+) 
+Total income tax benefit (expense) 
+$ 
+29,268 
+$ 
+(123,585 
+) 
+$ 
+(118,059 
+) 
+Effective tax rate 
+35.0 
+% 
+36.5 
+% 
+37.5 
+% 
+The Company reduces its income tax payable to reflect employee stock option exercises. In 2010 , the excess income tax benefit to the Company associated with stock awards was $854,000 . There was no excess income tax benefit associated with stock awards in 2012 or 2011 . 
+The components of the net deferred income tax liabilities are as follows: 
+As of December 31, 
+2012 
+2011 
+(in thousands) 
+Deferred tax liabilities: 
+Oil and gas properties 
+$ 
+678,624 
+$ 
+639,485 
+Unrealized derivative asset 
+15,942 
+13,274 
+Other 
+6,443 
+4,129 
+Total deferred tax liabilities 
+701,009 
+656,888 
+Deferred tax assets: 
+Federal and state tax net operating loss carryovers 
+113,522 
+23,651 
+Net Profits Plan liability 
+29,233 
+40,148 
+Stock compensation 
+18,026 
+17,728 
+Pension liability 
+6,849 
+5,902 
+Federal and state tax credit carryovers 
+5,271 
+4,301 
+Other long-term liabilities 
+4,619 
+4,908 
+Total deferred tax assets 
+177,520 
+96,638 
+Valuation allowance 
+(5,315 
+) 
+(3,791 
+) 
+Net deferred tax assets 
+172,205 
+92,847 
+Total net deferred tax liabilities 
+528,804 
+564,041 
+Less: current deferred income tax liabilities 
+(5,442 
+) 
+(3,307 
+) 
+Add: current deferred income tax assets 
+14,021 
+7,529 
+Non-current net deferred tax liabilities 
+$ 
+537,383 
+$ 
+568,263 
+Current federal income tax refundable 
+$ 
+2,511 
+$ 
+5,581 
+Current state income tax refundable 
+$ 
+853 
+$ 
+— 
+Current state income tax payable 
+$ 
+— 
+$ 
+774 
+At December 31, 2012 , the Company estimated its federal net operating loss carryforward at $376.6 million , which includes unrecognized excess income tax benefits associated with stock awards of $93.4 million . The federal net operating loss carryforward begins to expire in 2031 . The Company has estimated state net 
+107 
+Table of Contents 
+operating loss carryforwards of $361.2 million that expire between 2013 and 2032 . The Company has claimed federal research and development (“R&D”) credit carryforwards of $5.0 million that expire between 2028 and 2031 and other state tax credits of $252,000 that expire between 2013 and 2022 . The Company’s valuation allowance relates to charitable contribution carryfowards, state net operating loss carryforwards, state tax credits, and state and federal income tax benefit amounts, which the Company anticipates will expire before they can be utilized. Permanent items included in the calculation of income tax for certain states are anticipated to impact the Company’s ability to deduct operating losses and realize federal income tax deduction benefits in those states, and the Company adjusts its valuation allowances accordingly. The change in the valuation allowance from 2011 to 2012 , indicated below, primarily reflects a change in the Company’s position regarding anticipated utilization of charitable contribution carryforward amounts and cumulative net operating losses attributed to Oklahoma. 
+Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, R&D credits, percentage depletion, changes in valuation allowances, and other permanent differences, as follows: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Federal statutory tax benefit (expense) 
+$ 
+29,231 
+$ 
+(118,652 
+) 
+$ 
+(110,214 
+) 
+(Increase) decrease in tax resulting from: 
+State tax benefit (expense) (net of federal benefit) 
+992 
+(6,458 
+) 
+(7,750 
+) 
+Research and development credit 
+970 
+4,516 
+— 
+Change in valuation allowance 
+(1,524 
+) 
+(1,627 
+) 
+1,039 
+Statutory depletion 
+210 
+341 
+266 
+Other 
+(611 
+) 
+(1,705 
+) 
+(1,400 
+) 
+Income tax benefit (expense) 
+$ 
+29,268 
+$ 
+(123,585 
+) 
+$ 
+(118,059 
+) 
+Acquisitions, divestitures, drilling activity, and basis differentials impacting the prices received for oil, gas, and NGLs affect apportionment of taxable income to the states where the Company owns oil and gas properties. As its apportionment factors change, the Company’s blended state income tax rate changes. This change, when applied to the Company’s total temporary differences, impacts the total income tax reported in the current year and is reflected in state taxes in the table above. Items affecting state apportionment factors are evaluated at the beginning of each year, after completion of the prior year income tax return, and when significant acquisition, divestiture or changes in drilling activity occurs during the year. 
+The Company and its subsidiaries file income tax returns in the United States federal jurisdiction and in various states. With certain exceptions, the Company is no longer subject to United States federal or state income tax examinations by these tax authorities for years before 2008 . In the third quarter of 2011 , the Company completed a multi-year R&D credit study and filed amended federal returns to claim a credit for all open years. Federal tax law allowing for the calculation of an R&D credit for 2012 was not enacted until after December 31, therefore, no 2012 research activities are reflected in the table above. 
+In the first quarter of 2011, the Company received a $5.5 million refund from its 2006 tax year as a result of a net operating loss carryback claim from the 2008 tax year. In the fourth quarter of 2010, the Internal Revenue Service initiated an audit of the Company for the 2009 tax year. The audit was concluded in the second quarter of 2011 with a nominal decrease to the Company’s total 2005 refund claim of $25.0 million . A quick refund claim of $22.9 million from 2005 was received in the third quarter of 2010. The balance was received in the fourth quarter of 2011. The Internal Revenue Service initiated an audit in the first quarter of 2012 for the 2007 and 2010 tax years. This audit was still ongoing at year-end. 
+108 
+Table of Contents 
+The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. Interest expense in the accompanying statements of operations includes a negligible amount associated with income taxes. In 2011, the Company also recorded a negligible amount of penalty expense associated with income taxes as a general and administrative expense. There were no penalties for 2012 and 2010 . 
+The total amount recorded for unrecognized tax benefits is presented below: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Beginning balance 
+$ 
+1,961 
+$ 
+807 
+$ 
+884 
+Additions based on tax positions related to current year 
+— 
+1,172 
+— 
+Additions for tax positions of prior years 
+317 
+183 
+244 
+Reductions for lapse of statute of limitations 
+— 
+(201 
+) 
+(321 
+) 
+Ending balance 
+$ 
+2,278 
+$ 
+1,961 
+$ 
+807 
+Note 5 – Long-term Debt 
+Revolving Credit Facility 
+The Company executed a Fourth Amended and Restated Credit Agreement on May 27, 2011 . This amended revolving credit facility replaced the Company’s previous facility. The Company incurred $8.7 million of deferred financing costs in association with the amended credit facility. Borrowings under the facility are secured by substantially all of the Company’s proved oil and gas properties. The credit facility has a maximum loan amount of $2.5 billion , current aggregate lender commitments of $1.0 billion , and a maturity date of May 27, 2016 . The borrowing base is subject to regular semi-annual redeterminations by the Company’s lenders. The borrowing base redetermination process considers the value of the Company’s oil and gas properties. On August 31, 2012 , the lending group redetermined the Company's reserve-backed borrowing base under the credit facility at an amount of $1.55 billion , an increase from $1.4 billion . The next scheduled re-determination date is April 1, 2013. 
+The Company must comply with certain financial and non-financial covenants under the terms of its credit facility agreement, including the limitation of the Company’s dividends to no more than $50.0 million per year. The Company was in compliance with all financial covenants under the credit facility as of December 31, 2012 , and through the filing date of this report. 
+Interest and commitment fees are accrued based on the borrowing base utilization grid below. Eurodollar loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table below, and Alternate Base Rate (“ABR”) and swingline loans accrue interest at Prime plus the applicable margin from the utilization table below. Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the accompanying statements of operations. 
+Borrowing Base Utilization Grid 
+Borrowing Base Utilization Percentage 
+<25% 
+≥25% <50% 
+≥50% <75% 
+≥75% <90% 
+≥90% 
+Eurodollar Loans 
+1.500 
+% 
+1.750 
+% 
+2.000 
+% 
+2.250 
+% 
+2.500 
+% 
+ABR Loans or Swingline Loans 
+0.500 
+% 
+0.750 
+% 
+1.000 
+% 
+1.250 
+% 
+1.500 
+% 
+Commitment Fee Rate 
+0.375 
+% 
+0.375 
+% 
+0.500 
+% 
+0.500 
+% 
+0.500 
+% 
+109 
+Table of Contents 
+The following table presents the outstanding balance, total amount of letters of credit, and available borrowing capacity under our credit facility as of February 14, 2013 , December 31, 2012 , and December 31, 2011 . 
+As of February 14, 2013 
+As of December 31, 2012 
+As of December 31, 2011 
+(in millions) 
+Credit facility balance 
+$ 
+407.5 
+$ 
+340.0 
+$ 
+— 
+Letters of credit (1) 
+$ 
+0.8 
+$ 
+0.8 
+$ 
+0.6 
+Available borrowing capacity 
+$ 
+591.7 
+$ 
+659.2 
+$ 
+999.4 
+(1) Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis. 
+3.50% Senior Convertible Notes Due 2027 
+On April 2, 2012 , the Company called for redemption all of its outstanding 3.50% Senior Convertible Notes due 2027 (the “3.50% Senior Convertible Notes”). The call for redemption resulted in holders of $281.3 million aggregate principal amount electing to convert their notes. The Company settled the principal amount of all converted 3.50% Senior Convertible Notes in cash and settled the excess conversion value by issuing 864,106 shares of its common stock. The Company redeemed the remaining $6.2 million of aggregate principal amount of notes that were not converted on the redemption date at par plus accrued interest in cash. The Company used funds borrowed under its credit facility to pay the cash portion of the settlement. 
+2023 Notes 
+On June 29, 2012 , the Company issued $400.0 million in aggregate principal amount of 6.50% Senior Notes due 2023. The 2023 Notes were issued at par and mature on January 1, 2023 . The Company received net proceeds of $392.1 million after deducting fees of $7.9 million , which are being amortized as deferred financing costs over the life of the 2023 Notes. The net proceeds were used to reduce the Company’s outstanding credit facility balance. 
+Prior to July 1, 2015 , the Company may redeem, on one or more occasions, up to 35 percent of the aggregate principal amount of the 2023 Notes with the net cash proceeds of certain equity offerings at a redemption price of 106.5% of the principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 2023 Notes, in whole or in part, at any time prior to July 1, 2017 , at a redemption price equal to 100 percent of the principal amount of the 2023 Notes to be redeemed, plus a specified make-whole premium and accrued and unpaid interest to the applicable redemption date. 
+On or after July 1, 2017 , the Company may also redeem all or, from time to time, a portion of the 2023 Notes at the redemption prices set forth below, during the twelve-month period beginning on July 1 of each applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest: 
+2017 
+103.250 
+% 
+2018 
+102.167 
+% 
+2019 
+101.083 
+% 
+2020 and thereafter 
+100.000 
+% 
+The 2023 Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt, and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the 2023 Notes. The Company is subject to certain covenants under the indenture governing the 2023 Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends. However, the first $6.5 million of dividends paid each year are not restricted by this covenant. The Company was in compliance with all covenants under its 2023 Notes as of December 31, 2012 , and through the filing date of this report. 
+110 
+Table of Contents 
+Additionally, on June 29, 2012 , the Company entered into a registration rights agreement that provides holders of the 2023 Notes certain registration rights under the Securities Act of 1933, as amended (the “Securities Act”). The Company satisfied its obligations to exchange its outstanding $400.0 million 2023 Notes for notes registered under the Securities Act on October 30, 2012 . 
+2021 Notes 
+On November 8, 2011 , the Company issued $350.0 million in aggregate principal amount of 6.50% Senior Notes due 2021. The 2021 Notes were issued at par and mature on November 15, 2021 . The Company received net proceeds of $343.1 million after deducting fees of $6.9 million , which are being amortized as deferred financing costs over the life of the 2021 Notes. The net proceeds were used for general corporate purposes and to reduce the Company’s outstanding credit facility balance. 
+Prior to November 15, 2014 , the Company may redeem up to 35 percent of the aggregate principal amount of the 2021 Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.5% of the principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 2021 Notes, in whole or in part, at any time prior to November 15, 2016 , at a redemption price equal to 100% of the principal amount, plus a specified make-whole premium and accrued and unpaid interest . 
+The Company may also redeem all or, from time to time, a portion of the 2021 Notes on or after November 15, 2016 , at the prices set forth below, during the twelve-month period beginning on November 15 of the applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest: 
+2016 
+103.250 
+% 
+2017 
+102.167 
+% 
+2018 
+101.083 
+% 
+2019 and thereafter 
+100.000 
+% 
+The 2021 Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the 2021 Notes. The Company is subject to certain covenants under the indenture governing the 2021 Notes that limit incurring additional indebtedness, issuing preferred stock, and making restricted payments, including dividends. The first $6.5 million of dividends paid each year are not restricted by this covenant. The Company was in compliance with all covenants under its 2021 Notes as of December 31, 2012 and through the filing date of this report. 
+Additionally, on November 8, 2011 , the Company entered into a registration rights agreement that provides holders of the 2021 Notes certain registration rights for the 2021 Notes under the Securities Act. The Company satisfied its obligations to exchange its outstanding $350.0 million of its 2021 Notes for notes registered under the Securities Act on March 7, 2012 . 
+2019 Notes 
+On February 7, 2011 , the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2019. The 2019 Notes were issued at par and mature on February 15, 2019 . The Company received net proceeds of $341.1 million after deducting fees of $8.9 million , which are being amortized as deferred financing costs over the life of the 2019 Notes. The net proceeds were used to repay borrowings under the Company’s previous credit facility, to fund the Company’s ongoing capital expenditure program, and for general corporate purposes. 
+111 
+Table of Contents 
+Prior to February 15, 2014 , the Company may redeem up to 35 percent of the aggregate principal amount of the 2019 Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.625% of the principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 2019 Notes, in whole or in part, at any time prior to February 15, 2015 , at a redemption price equal to 100% of the principal amount, plus a specified make-whole premium and accrued and unpaid interest . 
+The Company may also redeem all or, from time to time, a portion of the 2019 Notes on or after February 15, 2015 , at the prices set forth below, during the twelve-month period beginning on February 15 of the applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest: 
+2015 
+103.313 
+% 
+2016 
+101.656 
+% 
+2017 and thereafter 
+100.000 
+% 
+The 2019 Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the 2019 Notes. The Company is subject to certain covenants under the indenture governing the 2019 Notes that limit incurring additional indebtedness, issuing preferred stock, and making restricted payments, including dividends. The first $6.5 million of dividends paid each year are not restricted by this covenant. The Company was in compliance with all covenants under its 2019 Notes as of December 31, 2012 and through the filing date of this report. 
+Additionally, on February 7, 2011 , the Company entered into a registration rights agreement that provides holders of the 2019 Notes certain registration rights for the 2019 Notes under the Securities Act. The Company satisfied its obligations to exchange its outstanding $350.0 million of its 2019 Notes for notes registered under the Securities Act on January 11, 2012 . 
+Capitalized Interest 
+Capitalized interest costs for the Company for the years ended December 31, 2012 , 2011 , and 2010 , were $12.1 million , $10.8 million , and $4.3 million , respectively. 
+Note 6 – Commitments and Contingencies 
+Commitments 
+The Company has entered into various agreements, which include drilling rig contracts of $91.4 million , gathering, transportation, and processing through-put commitments of $858.7 million , office leases, including maintenance, of $55.3 million , and other miscellaneous contracts and leases of $7.2 million . The annual minimum payments for the next five years and total minimum lease payments thereafter are presented below: 
+Years Ending December 31, 
+(in thousands) 
+2013 
+$ 
+127,753 
+2014 
+111,674 
+2015 
+99,854 
+2016 
+102,540 
+2017 
+101,456 
+Thereafter 
+469,348 
+Total 
+$ 
+1,012,625 
+112 
+Table of Contents 
+The Company has gathering, processing, and transportation through-put commitments with various parties that require delivery of a fixed determinable quantity of product. The aggregate minimum commitment to deliver is 1,515 Bcf of natural gas and 36 MMBbls of oil. These contracts expire at various dates through 2023 , and the total amount of the commitment is approximately $858.7 million . The Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. As of the filing date of this report, the Company does not expect to incur any material shortfalls. 
+The Company leases office space under various operating leases with terms extending as far as May 31, 2024 . Rent expense for 2012 , 2011 , and 2010 was $5.4 million , $3.7 million , and $2.7 million , respectively. The Company also leases office equipment under various operating leases. 
+In addition to the amounts in the above table, the Company entered into a capital project commencing in 2011 for the development of midstream infrastructure in the Company’s non-operated Eagle Ford shale play. Pursuant to the terms of the agreement for the construction, ownership and operation of these assets, the Company is required to pay its portion of the costs for the next two years. Based on current estimates, the Company does not expect its costs to exceed $67 million during this time. 
+Contingencies 
+The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such pending litigation and claims will not have a material effect on the results of operations, the financial position, or the cash flows of the Company. 
+The Company was a defendant in litigation wherein the plaintiffs claimed an aggregate overriding royalty interest of 7.46875 percent in production from approximately 22,000 of the Company’s net acres in the Eagle Ford shale play in South Texas. The plaintiffs sought to quiet title to their claimed overriding royalty interest and to recover unpaid overriding royalty interest proceeds allegedly due. The Company believes that the claimed overriding royalty interest has been terminated under the governing agreements and the applicable law, and has contested the plaintiffs’ claims. Both parties filed motions for summary judgment, and on February 8, 2011, the District Court in Webb County, Texas, issued an order granting plaintiffs’ motion for summary judgment and denying the Company’s motion for summary judgment. On September 30, 2011, the District Court entered final judgment for the plaintiffs and awarded then current damages of approximately $5.1 million , which included prejudgment interest. The District Court also awarded attorneys’ fees and costs to the plaintiffs. The Company appealed the District Court’s judgment and obtained a stay pending appeal that prevented the plaintiffs from executing on the judgment. 
+On May 23, 2012, the Fourth Court of Appeals for the State of Texas delivered its opinion in this case, which reversed the summary judgment granted to the plaintiffs by the District Court and rendered judgment that the plaintiffs take nothing. Accordingly, based on the judgment of the Fourth Court of Appeals, the plaintiffs are not entitled to their claimed aggregate 7.46875 percent overriding royalty interest, nor are they entitled to the claimed damages related to the overriding royalty interest, attorneys fees or costs. The plaintiffs filed a petition with the Supreme Court of Texas requesting a review of the Fourth Court of Appeals judgment. The Supreme Court of Texas denied this petition for review on February 15, 2013. As a result, the decision of the Fourth Court of Appeals is dispositive and its dismissal of the plaintiffs’ claims is final. 
+113 
+Table of Contents 
+On January 27, 2011, Chieftain filed a Class Action Petition against the Company in the District Court of Beaver County, Oklahoma, claiming damages related to royalty valuation on all of the Company's Oklahoma wells. These claims include breach of contract, breach of fiduciary duty, fraud, unjust enrichment, tortious breach of contract, conspiracy, and conversion, based generally on asserted improper deduction of post-production costs. The Company removed this lawsuit to the United States District Court for the Western District of Oklahoma on February 22, 2011. The Company has responded to the petition and denied the allegations. The court has not yet ruled on Chieftain's motion to certify the putative class, and has stayed any such ruling until the United States Court of Appeals for the Tenth Circuit issues its ruling on class certification in two similar royalty class action lawsuits, where the defendants have appealed such certification. The opinion from the Tenth Circuit is expected during the summer of 2013. 
+This case involves complex legal issues and uncertainties; a potentially large class of plaintiffs, and a large number of related producing properties, lease agreements and wells; and an alleged class period commencing in 1988 and spanning the entire producing life of the wells. Because the proceedings are in the early stages, with substantive discovery yet to be conducted, the Company is unable to estimate what impact, if any, the action will have on its financial condition, results of operations or cash flows. The Company is still evaluating the claims, but believes that it has properly valued and paid royalty under Oklahoma law and has and will continue to vigorously defend this case. 
+Note 7 – Compensation Plans 
+Cash Bonus Plan 
+The Company has a cash bonus plan based on a performance measurement framework whereby selected eligible employee participants may be awarded an annual cash bonus. The plan document provides that no participant may receive an annual bonus under the plan of more than 200 percent of his or her base salary. As the plan is currently administered, any awards under the plan are based on Company and regional performance and are then further refined by individual performance. The Company accrues cash bonus expense based upon the Company’s current year performance. Included in general and administrative and exploration expense in the accompanying statements of operations are $16.3 million , $23.9 million , and $21.6 million of cash bonus expense related to the specific performance years ended December 31, 2012 , 2011 , and 2010 , respectively. 
+Equity Plan 
+There are several components to the Company's Equity Plan that are described in this section. Various types of equity awards have been granted by the Company in different periods. 
+As of December 31, 2012 , 1.4 million shares of common stock remained available for grant under the Equity Plan. The issuance of a direct share benefit such as a share of common stock, a restricted share, a RSU, or a PSU counts as 1.43 shares against the number of shares available to be granted under the Equity Plan. Each PSU has the potential to count as 2.86 shares against the number of shares available to be granted under the Equity Plan based on the final performance multiplier. Stock option grants count as one share for each instrument granted against the number of shares available to be granted under the Equity Plan. Stock options were issued out of the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan, both predecessors to the Equity Plan. 
+114 
+Table of Contents 
+Performance Share Units Under the Equity Incentive Compensation Plan 
+The Company grants PSUs to eligible employees as a part of its equity incentive compensation program. The PSU factor is based on the Company’s performance after completion of a three-year performance period. The performance criteria for the PSUs are based on a combination of the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative measure of the Company’s TSR compared with the annualized TSR of an index comprised of certain peer companies for the performance period. PSUs are recognized as general and administrative and exploration expense over the vesting period of the award. 
+The fair value of PSUs was measured at the grant date with a stochastic process method using the Geometric Brownian Motion Model (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three-year performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, dividend yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a three year vesting period, as well as the volatilities and dividend yields for each of the Company’s peers. 
+Total expense recorded for PSUs was $18.2 million , $19.7 million , and $17.7 million for the years ended December 31, 2012 , 2011 , and 2010 , respectively. As of December 31, 2012 , there was $19.6 million of total unrecognized expense related to PSUs, which is being amortized through 2015 . 
+A summary of the status and activity of PSUs is presented in the following table: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+PSUs 
+Weighted-Average Grant-Date Fair Value 
+PSUs 
+Weighted-Average Grant-Date Fair Value 
+PSUs 
+Weighted-Average Grant-Date Fair Value 
+Non-vested at beginning of year (1) 
+885,894 
+$ 
+57.52 
+1,110,666 
+$ 
+39.48 
+1,069,090 
+$ 
+32.52 
+Granted (1) 
+314,853 
+$ 
+51.98 
+266,282 
+$ 
+91.45 
+387,651 
+$ 
+52.35 
+Vested (1) 
+(493,679 
+) 
+$ 
+44.72 
+(364,172 
+) 
+$ 
+35.74 
+(210,801 
+) 
+$ 
+31.18 
+Forfeited (1) 
+(37,760 
+) 
+$ 
+65.35 
+(126,882 
+) 
+$ 
+33.32 
+(135,274 
+) 
+$ 
+34.28 
+Non-vested at end of year (1) 
+669,308 
+$ 
+63.91 
+885,894 
+$ 
+57.52 
+1,110,666 
+$ 
+39.48 
+(1) 
+The number of awards assumes a one multiplier. The final number of shares of common stock issued may vary depending on the ending three -year performance multiplier, which ranges from zero to two . 
+The fair value of the PSUs granted in 2012 , 2011 , and 2010 was $16.4 million , $24.3 million , and $20.3 million for the 2012 , 2011 , and 2010 grants, respectively. The PSUs granted in 2012 will vest 1/3 on each of the first three anniversary dates of their issuance. PSUs granted prior to 2012 vest 1/7 th , 2/7 ths , and 4/7 ths on the first three anniversary dates of their issuances. 
+The total fair value of PSUs that vested during the years ended December 31, 2012 , 2011 , and 2010 was $22.1 million , $13.0 million , and $6.6 million , respectively. 
+115 
+Table of Contents 
+During the year ended December 31, 2012 , the Company settled 609,714 PSUs that were granted in 2009, and which had earned a two -times multiplier, by issuing a net 812,562 shares of the Company’s common stock in accordance with the terms of the PSU awards. The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, the remaining 406,866 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs for 2012 . 
+During the year ended December 31, 2011 , the Company settled PSUs that were granted in 2008, which earned a 0.8 times multiplier, by issuing a net 206,468 shares of the Company’s common stock in accordance with the terms of the PSU awards. The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, 98,955 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs for 2011 . 
+Restricted Stock Units Under the Equity Incentive Compensation Plan 
+The Company grants RSUs to eligible employees as a part of its equity incentive compensation program. Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each RSU represents a right for one share of the Company’s common stock to be delivered upon settlement of the award at the end of a specified period. RSUs are recognized as general and administrative and exploration expense over the vesting period of the award. 
+The total expense associated with RSUs for the years ended December 31, 2012 , 2011 , and 2010 , was $9.8 million , $5.3 million , and $7.7 million , respectively. As of December 31, 2012 , there was $14.4 million of total unrecognized expense related to unvested RSU awards, which is being amortized through 2015 . The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the day of grant. 
+A summary of the status and activity of non-vested RSUs is presented below: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+Non-vested at beginning of year 
+308,877 
+$ 
+44.33 
+333,359 
+$ 
+31.16 
+407,123 
+$ 
+34.67 
+Granted 
+379,332 
+$ 
+49.47 
+98,952 
+$ 
+72.69 
+128,865 
+$ 
+40.31 
+Vested 
+(166,672 
+) 
+$ 
+32.72 
+(105,820 
+) 
+$ 
+30.61 
+(160,398 
+) 
+$ 
+46.30 
+Forfeited 
+(25,293 
+) 
+$ 
+51.06 
+(17,614 
+) 
+$ 
+36.80 
+(42,231 
+) 
+$ 
+35.43 
+Non-vested at end of year 
+496,244 
+$ 
+51.81 
+308,877 
+$ 
+44.33 
+333,359 
+$ 
+31.16 
+The fair value of RSUs granted in 2012 , 2011 , and 2010 was $18.8 million , $7.2 million , and $5.2 million , respectively. The RSUs granted in 2012 will vest 1/3 on each of the first three anniversary dates of the award. RSUs granted prior to 2012 vest 1/7 th , 2/7 ths , and 4/7 ths on the first three anniversary dates of their issuances. 
+The total fair value of RSUs that vested during the years ended December 31, 2012 , 2011 , and 2010 , was $5.4 million , $3.2 million , and $7.4 million , respectively. 
+116 
+Table of Contents 
+During the years ended December 31, 2012 , 2011 , and 2010 , the Company settled 166,670 , 105,820 , and 160,381 RSUs, respectively. The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, the Company issued net shares of common stock of 116,813 , 72,305 , and 113,103 for 2012 , 2011 , and 2010 , respectively. The remaining 49,857 , 33,515 , and 47,278 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon the delivery of the shares underlying those RSUs for 2012 , 2011 , and 2010 , respectively. 
+Stock Option Grants Under the Equity Incentive Compensation Plan 
+The Company has previously granted stock options under the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan. The last issuance of stock options occurred on December 31, 2004. Stock options to purchase shares of the Company’s common stock had been granted to eligible employees and members of the Board of Directors. All options granted under the option plans were granted at exercise prices equal to the respective closing market price of the Company’s underlying common stock on the grant dates. All stock options granted under the option plans are exercisable for a period of up to ten years from the date of grant. As of December 31, 2012 , there was no unrecognized compensation expense related to stock option awards. 
+A summary of activity associated with the Company’s Stock Option Plans during the last three years is presented in the following table: 
+Weighted - 
+Average 
+Aggregate 
+Exercise 
+Intrinsic 
+Shares 
+Price 
+Value 
+For the year ended December 31, 2010 
+Outstanding, start of year 
+1,274,920 
+$ 
+13.31 
+Exercised 
+(346,377 
+) 
+$ 
+13.77 
+$ 
+11,281,865 
+Forfeited 
+(7,778 
+) 
+$ 
+16.66 
+Outstanding, end of year 
+920,765 
+$ 
+13.11 
+$ 
+42,192,057 
+Vested and exercisable at end of year 
+920,765 
+$ 
+13.11 
+$ 
+42,192,057 
+For the year ended December 31, 2011 
+Outstanding, start of year 
+920,765 
+$ 
+13.11 
+Exercised 
+(412,551 
+) 
+$ 
+12.19 
+$ 
+24,359,240 
+Forfeited 
+— 
+$ 
+— 
+Outstanding, end of year 
+508,214 
+$ 
+13.86 
+$ 
+30,109,110 
+Vested and exercisable at end of year 
+508,214 
+$ 
+13.86 
+$ 
+30,109,110 
+For the year ended December 31, 2012 
+Outstanding, start of year 
+508,214 
+$ 
+13.86 
+Exercised 
+(240,368 
+) 
+$ 
+12.65 
+$ 
+11,842,575 
+Forfeited 
+— 
+$ 
+— 
+Outstanding, end of year 
+267,846 
+$ 
+14.95 
+$ 
+9,983,177 
+Vested and exercisable at end of year 
+267,846 
+$ 
+14.95 
+$ 
+9,983,177 
+117 
+Table of Contents 
+A summary of additional information related to options outstanding as of December 31, 2012 , follows: 
+Options Outstanding and Exercisable 
+Number 
+Weighted- 
+Of Options 
+Average 
+Outstanding 
+Remaining 
+Exercise 
+and 
+Contractual 
+Price (1) 
+Exercisable 
+Life 
+$ 
+12.53 
+33,805 
+0.25 years 
+$ 
+12.66 
+28,053 
+0.75 years 
+$ 
+13.39 
+17,142 
+0.81 years 
+$ 
+13.65 
+35,893 
+0.50 years 
+$ 
+14.25 
+104,093 
+1 year 
+$ 
+20.87 
+48,860 
+2 years 
+Total 
+267,846 
+(1) Exercise price is equal to the weighted average exercise price. 
+The fair value of options was measured at the date of grant using the Black-Scholes-Merton option-pricing model. 
+Cash flows resulting from excess tax benefits are classified as part of cash flows from financing activities. Excess tax benefits are realized tax benefits from tax deductions for vested RSUs, settled PSUs, and exercised options in excess of the deferred tax asset attributable to stock compensation costs for such equity awards. The Company recorded $854,000 of excess tax benefits for the year ended December 31, 2010 , as cash inflows from financing activities. The Company recorded no excess tax benefits for the years ended December 31, 2012 , and December 31, 2011 . Cash received from exercises under all share-based payment arrangements for the years ended December 31, 2012 , 2011 , and 2010 , was $3.0 million , $5.0 million , and $4.8 million , respectively. 
+Director Shares 
+In 2012 , 2011 , and 2010 , the Company issued 30,486 , 21,568 , and 24,258 shares, respectively, of the Company’s common stock held as treasury shares to its non-employee directors pursuant to the Company’s Equity Plan. The Company recorded compensation expense related to these issuances of $1.3 million , $1.2 million , and $781,000 for the years ended December 31, 2012 , 2011 , and 2010 , respectively. 
+Employee Stock Purchase Plan 
+Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in fair market value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the purchase period. All shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of the IRC. The Company has 1.3 million shares available under the ESPP for issuance as of December 31, 2012 . Shares issued under the ESPP totaled 66,485 in 2012 , 41,358 in 2011 , and 52,948 in 2010 . Total proceeds to the Company for the issuance of these shares were $2.8 million in 2012 , $2.3 million in 2011 , and $1.7 million in 2010 , respectively. 
+The fair value of ESPP shares was measured at the date of grant using the Black-Scholes-Merton option-pricing model. Expected volatility was calculated based on the Company’s historical daily common stock price, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with a six month vesting period. 
+118 
+Table of Contents 
+The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+Risk free interest rate 
+0.1 
+% 
+0.2 
+% 
+0.2 
+% 
+Dividend yield 
+0.2 
+% 
+0.2 
+% 
+0.3 
+% 
+Volatility factor of the expected market 
+price of the Company’s common stock 
+47.8 
+% 
+36.3 
+% 
+46.3 
+% 
+Expected life (in years) 
+0.5 years 
+0.5 years 
+0.5 years 
+The Company expensed $948,000 , $682,000 , and $550,000 for the years ended December 31, 2012 , 2011 , and 2010 , respectively, based on the estimated fair value of grants. 
+401(k) Plan 
+The Company has a defined contribution pension plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute up to 60 percent of their base salaries up to the contribution limits established under the IRC. The Company matches each employee’s contribution up to six percent of the employee’s base salary and may make additional contributions at its discretion. The Company’s matching contributions to the 401(k) Plan were $3.5 million , $2.9 million , and $2.5 million for the years ended December 31, 2012 , 2011 , and 2010 , respectively. No discretionary contributions were made by the Company to the 401(k) Plan for any of these years. 
+Net Profits Plan 
+Under the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during a year were designated within a specific pool. Key employees recommended by senior management and designated as participants by the Compensation Committee of the Company’s Board of Directors and employed by the Company on the last day of that year became entitled to payments under the Net Profits Plan after the Company has received net cash flows returning 100 percent of all costs associated with that pool. Thereafter, 10 percent of future net cash flows generated by the pool are allocated among the participants and distributed at least annually. The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the Company has recovered 200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the 10 percent level. In December 2007, the Board of Directors discontinued the creation of new pools under the Net Profits Plan. As a result, the 2007 pool was the last Net Profits Plan pool established by the Company. 
+Cash payments made or accrued under the Net Profits Plan that have been recorded as either general and administrative expense or exploration expense are detailed in the table below: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+General and administrative expense 
+$ 
+15,565 
+$ 
+19,326 
+$ 
+19,798 
+Exploration expense 
+1,751 
+2,091 
+2,633 
+Total 
+$ 
+17,316 
+$ 
+21,417 
+$ 
+22,431 
+Additionally, the Company made or accrued cash payments under the Net Profits Plan of $2.3 million , $6.3 million , and $26.1 million for the years ended December 31, 2012 , 2011 , and 2010 , respectively, as a result of divestiture proceeds. The cash payments are accounted for as a reduction in the gain on divestiture activity in the accompanying statements of operations. 
+119 
+Table of Contents 
+The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate line item in the accompanying statements of operations. The change in the estimated liability is recorded as a non-cash expense or benefit in the current period. The amount recorded as an expense or benefit associated with the change in the estimated liability is not allocated to general and administrative expense or exploration expense because it is associated with the future net cash flows from oil and gas properties in the respective pools rather than results being realized through current period production. If the Company allocated the change in liability to these specific functional line items, based on the current allocation of actual distributions made by the Company, such expenses or benefits would predominately be allocated to general and administrative expense. The amount that would be allocated to exploration expense is minimal in comparison. Over time, less of the amount distributed relates to prospective exploration efforts as more of the amount distributed is to individuals that have terminated employment and do not provide ongoing exploration support to the Company. 
+Note 8 – Pension Benefits 
+The Company has a non-contributory defined benefit pension plan covering substantially all employees who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). 
+Obligations and Funded Status for Both Pension Plans 
+The Company recognizes the funded status (i.e., the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment to accumulated other comprehensive income, net of tax. The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31. 
+For the Years Ended December 31, 
+2012 
+2011 
+(in thousands) 
+Change in benefit obligation: 
+Projected benefit obligation at beginning of year 
+$ 
+29,480 
+$ 
+23,867 
+Service cost 
+4,934 
+3,800 
+Interest cost 
+1,374 
+1,184 
+Plan amendments 
+— 
+170 
+Actuarial loss 
+5,467 
+1,957 
+Benefits paid 
+(1,018 
+) 
+(1,498 
+) 
+Projected benefit obligation at end of year 
+40,237 
+29,480 
+Change in plan assets: 
+Fair value of plan assets at beginning of year 
+13,940 
+10,332 
+Actual return on plan assets 
+1,952 
+(176 
+) 
+Employer contribution 
+5,380 
+5,260 
+Benefits paid 
+(1,018 
+) 
+(1,476 
+) 
+Fair value of plan assets at end of year 
+20,254 
+13,940 
+Funded status at end of year 
+$ 
+(19,983 
+) 
+$ 
+(15,540 
+) 
+120 
+Table of Contents 
+The Company’s underfunded status for the Pension Plans for the years ended December 31, 2012 and 2011 , is $20.0 million and $15.5 million , respectively, and is recognized in the accompanying balance sheets as a portion of other noncurrent liabilities. No plan assets of the Qualified Pension Plan were returned to the Company during the fiscal year ended December 31, 2012 . There are no plan assets in the Nonqualified Pension Plan. The plan was amended in 2011 to increase the vesting percent to 40 percent after attaining two years of service and increasing by 20 percent per year until fully vested. The impact of this change in the vesting schedule is reflected in plan amendments in the table above. 
+Information for Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets for Both Plans 
+As of December 31, 
+2012 
+2011 
+(in thousands) 
+Projected benefit obligation 
+$ 
+40,237 
+$ 
+29,480 
+Accumulated benefit obligation 
+$ 
+29,437 
+$ 
+21,697 
+Less: Fair value of plan assets 
+(20,254 
+) 
+(13,940 
+) 
+Underfunded accumulated benefit obligation 
+$ 
+9,183 
+$ 
+7,757 
+Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the interest cost on those liabilities, less the expected return on plan assets. The expected long-term rate of return on plan assets is applied to a calculated value of plan assets that recognizes changes in fair value over a five-year period. This practice is intended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences between actual returns on assets and expected returns based on long-term rate of return assumptions. Amortization of unrecognized net gain or loss resulting from actual experience different from that assumed and from changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of net periodic benefit cost for a year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation and the market-related value of plan assets, then the amortization is the excess divided by the average remaining service period of participating employees expected to receive benefits under the plan. 
+Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated other comprehensive loss as of December 31, 2012 , and 2011 , consist of: 
+As of December 31, 
+2012 
+2011 
+(in thousands) 
+Unrecognized actuarial losses 
+$ 
+12,427 
+$ 
+8,501 
+Unrecognized prior service costs 
+153 
+170 
+Unrecognized transition obligation 
+— 
+— 
+Accumulated other comprehensive loss 
+$ 
+12,580 
+$ 
+8,671 
+The estimated net loss that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year is $876,000 . 
+121 
+Table of Contents 
+Pre-tax changes recognized in other comprehensive income (loss) during 2012 , 2011 , and 2010 , were as follows: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Net actuarial gain (loss) 
+$ 
+(4,680 
+) 
+$ 
+(3,014 
+) 
+$ 
+(1,937 
+) 
+Prior service cost 
+— 
+(170 
+) 
+— 
+Less: Amortization of: 
+Prior service cost 
+(17 
+) 
+— 
+— 
+Actuarial loss 
+(754 
+) 
+(405 
+) 
+(367 
+) 
+Total other comprehensive income (loss) 
+$ 
+(3,909 
+) 
+$ 
+(2,779 
+) 
+$ 
+(1,570 
+) 
+Components of Net Periodic Benefit Cost for Both Pension Plans 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Components of net periodic benefit cost 
+Service cost 
+$ 
+4,934 
+$ 
+3,800 
+$ 
+3,392 
+Interest cost 
+1,374 
+1,184 
+1,120 
+Expected return on plan assets that reduces periodic pension cost 
+(1,165 
+) 
+(880 
+) 
+(638 
+) 
+Amortization of prior service cost 
+17 
+— 
+— 
+Amortization of net actuarial loss 
+754 
+405 
+367 
+Net periodic benefit cost 
+$ 
+5,914 
+$ 
+4,509 
+$ 
+4,241 
+Gains and losses in excess of 10 percent of the greater of the benefit obligation and the market-related value of assets are amortized over the average remaining service period of active participants. 
+Pension Plan Assumptions 
+Weighted-average assumptions to measure the Company’s projected benefit obligation and net periodic benefit cost are as follows: 
+As of December 31, 
+2012 
+2011 
+2010 
+Projected benefit obligation 
+Discount rate 
+3.9% 
+4.7% 
+5.3% 
+Rate of compensation increase 
+6.2% 
+6.2% 
+6.2% 
+Net periodic benefit cost 
+Discount rate 
+4.7% 
+5.3% 
+6.1% 
+Expected return on plan assets 
+7.5% 
+7.5% 
+7.5% 
+Rate of compensation increase 
+6.2% 
+6.2% 
+6.2% 
+The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans. The policy does not permit the direct investment of plan assets in the Company’s securities. The Qualified Pension Plan's investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term 
+122 
+Table of Contents 
+perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of diversification, assessment of risk, and targeting the optimal expected returns for given levels of risk are applied. 
+The Qualified Pension Plan's investment portfolio contains a diversified blend of investments, which may reflect varying rates of return. The investments are further diversified within each asset classification. This portfolio diversification provides protection against a single security or class of securities having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a periodic basis to maintain the target allocations. The weighted-average asset allocation of the Qualified Pension Plan is as follows: 
+Target 
+As of December 31, 
+Asset Category 
+2013 
+2012 
+2011 
+Equity securities 
+44.0 
+% 
+42.7 
+% 
+61.8 
+% 
+Debt securities 
+33.0 
+% 
+32.8 
+% 
+37.7 
+% 
+Other 
+23.0 
+% 
+24.5 
+% 
+0.5 
+% 
+Total 
+100.0 
+% 
+100.0 
+% 
+100.0 
+% 
+There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in that plan. An expected return on plan assets of 7.5 percent was used to calculate the Company’s obligation under the Qualified Pension Plan for 2012 and 2011 . Factors considered in determining the expected rate of return include the long-term historical rate of return provided by the equity and debt securities markets and input from the investment consultants and trustees managing the plan assets. The difference in investment income using the projected rate of return compared to the actual rates of return for the past two years was not material and will not have a material effect on the accompanying statements of operations or cash flows from operating activities in future years. 
+Fair Value Assumptions 
+The fair value of the Company’s Qualified Pension Plan assets as of December 31, 2012 , utilizing the fair value hierarchy discussed in Note 11 – Fair Value Measurements is as follows: 
+123 
+Table of Contents 
+Fair Value Measurements Using: 
+Actual Asset Allocation 
+Total 
+Level 1 Inputs 
+Level 2 Inputs 
+Level 3 Inputs 
+(in thousands) 
+Cash and Money Market Funds 
+3.8 
+% 
+$ 
+778 
+$ 
+778 
+$ 
+— 
+$ 
+— 
+Equity Securities 
+Domestic (1) 
+29.2 
+% 
+5,920 
+5,920 
+— 
+— 
+International (2) 
+13.5 
+% 
+2,740 
+2,740 
+— 
+— 
+Total Equity Securities 
+42.7 
+% 
+8,660 
+8,660 
+— 
+— 
+Fixed Income Securities 
+High-Yield Bonds (3) 
+6.1 
+% 
+1,240 
+1,240 
+— 
+— 
+Core Fixed Income (4) 
+20.8 
+% 
+4,204 
+4,204 
+— 
+— 
+Floating Rate Corp Loans (5) 
+5.9 
+% 
+1,186 
+1,186 
+— 
+— 
+Total Fixed Income Securities 
+32.8 
+% 
+6,630 
+6,630 
+— 
+— 
+Other Securities: 
+Commodities (6) 
+3.3 
+% 
+669 
+669 
+— 
+— 
+Real Estate (7) 
+3.9 
+% 
+783 
+— 
+— 
+783 
+Hedge Fund (8) 
+13.5 
+% 
+2,734 
+1,133 
+— 
+1,601 
+Total Other Securities 
+20.7 
+% 
+4,186 
+1,802 
+— 
+2,384 
+Total Investments 
+100.0 
+% 
+$ 
+20,254 
+$ 
+17,870 
+$ 
+— 
+$ 
+2,384 
+(1) 
+Equity securities of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. 
+(2) 
+International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations. 
+(3) 
+High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis. 
+(4) 
+The objective is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay's Capital Aggregate Bond Index with a modest amount of variability in duration around the index. 
+(5) 
+Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. 
+(6) 
+Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities. 
+(7) 
+The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity. 
+(8) 
+The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies. 
+Included below is a summary of the changes in Level 3 plan assets (in thousands): 
+December 31, 2011 
+$ 
+— 
+Purchases 
+2,329 
+Investment Returns 
+55 
+December 31, 2012 
+$ 
+2,384 
+124 
+Table of Contents 
+The fair value of the Company’s pension plan assets as of December 31, 2011 , is as follows: 
+Fair Value Measurements Using: 
+Actual Asset Allocation 
+Total 
+Level 1 Inputs 
+Level 2 Inputs 
+Level 3 Inputs 
+(in thousands) 
+Cash and Money Market Funds 
+0.5 
+% 
+$ 
+66 
+$ 
+66 
+$ 
+— 
+$ 
+— 
+Equity Securities (1) 
+Domestic (2) 
+47.1 
+% 
+6,568 
+6,568 
+— 
+— 
+International (3) 
+14.7 
+% 
+2,048 
+2,048 
+— 
+— 
+Total Equity Securities 
+61.8 
+% 
+8,616 
+8,616 
+— 
+— 
+Fixed Income Securities 
+Intermediate Term Bond (4) 
+37.7 
+% 
+5,258 
+5,258 
+— 
+— 
+Total Investments 
+100.0 
+% 
+$ 
+13,940 
+$ 
+13,940 
+$ 
+— 
+$ 
+— 
+(1) 
+Certain amounts have been reclassified to conform to current-year presentation. 
+(2) 
+United States equities are invested in companies that trade on active exchanges within the United States and are well diversified by industry sector and equity style, such as growth and value strategies, and passive management strategies are employed. 
+(3) 
+International equities are invested in companies that trade on active exchanges outside the United States and are well diversified among more developed markets. Active and passive strategies are employed. 
+(4) 
+Intermediate term bonds seek total return. At least 80% of this fund is invested in a diversified portfolio of bonds, which include all types of securities. It invests primarily in bonds of corporate and governmental issues located in the United States and foreign countries, including emerging markets, all of which trade on active exchanges. 
+Contributions 
+The Company contributed $5.4 million , $5.3 million , and $1.7 million , to the Pension Plans in the years ended December 31, 2012 , 2011 , and 2010 , respectively. The Company is required to make a $373,000 contribution to the Pension Plans in 2013 . 
+Benefit Payments 
+The Pension Plans made actual benefit payments of $1.0 million , $1.5 million , and $1.7 million in the years ended December 31, 2012 , 2011 , and 2010 , respectively. Expected benefit payments over the next ten years are as follows (in thousands): 
+Years Ending December 31, 
+2013 
+$ 
+2,631 
+2014 
+$ 
+2,385 
+2015 
+$ 
+2,715 
+2016 
+$ 
+3,298 
+2017 
+$ 
+3,885 
+2018 through 2022 
+$ 
+29,884 
+125 
+Table of Contents 
+Note 9 – Asset Retirement Obligations 
+The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement obligations is included in the operating section of the Company’s accompanying statements of cash flows. 
+The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s abandonment liabilities range from 5.5 percent to 12 percent . Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives or if federal or state regulators enact new requirements regarding the abandonment of wells. 
+A reconciliation of the Company’s asset retirement obligation liability is as follows: 
+As of December 31, 
+2012 
+2011 
+(in thousands) 
+Beginning asset retirement obligation 
+$ 
+95,906 
+$ 
+82,849 
+Liabilities incurred 
+13,050 
+5,465 
+Liabilities settled 
+(8,101 
+) 
+(8,365 
+) 
+Accretion expense 
+4,679 
+5,948 
+Revision to estimated cash flows 
+14,984 
+10,009 
+Ending asset retirement obligation 
+$ 
+120,518 
+$ 
+95,906 
+As of December 31, 2012 , and 2011 , the Company had $1.4 million and $1.3 million , respectively, of asset retirement obligation associated with the oil and gas properties held for sale included in a separate line item on the Company’s accompanying balance sheets. Additionally, as of December 31, 2012 , and 2011 , accounts payable and accrued expenses contain $6.2 million and $7.5 million , respectively, related to the Company’s current asset retirement obligation liability for estimated plugging and abandonment costs associated with platforms that are being relinquished or retired. 
+Note 10 – Derivative Financial Instruments 
+The Company has entered into various commodity derivative contracts to mitigate a portion of the exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. The Company’s derivative contracts in place include swap and collar arrangements for oil, gas, and NGLs. As of December 31, 2012 , the Company has commodity derivative contracts outstanding through the third quarter of 2015 for a total of 10.1 million Bbls of oil production, 80.7 million MMBtu of gas production, and 1.2 million Bbls of NGL production. As of February 14, 2013 , the Company had commodity derivative contracts in place through the fourth quarter of 2015 for a total of 14.5 million Bbls of oil, 114.8 million MMBtu of gas, and 2.0 million Bbls of NGLs. 
+The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The fair value of the commodity derivative contracts was a net asset of $38.7 million and $31.2 million at December 31, 2012 , and 2011 , respectively. 
+126 
+Table of Contents 
+Discontinuance of Cash Flow Hedge Accounting 
+Prior to January 1, 2011, the Company designated its commodity derivative contracts as cash flow hedges, for which unrealized changes in fair value were recorded to AOCIL, to the extent the hedges were effective. As of January 1, 2011, the Company elected to de-designate all of its commodity derivative contracts that had been previously designated as cash flow hedges at December 31, 2010. As a result, subsequent to December 31, 2010, the Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in AOCIL. The Company had no derivatives designated as cash flow hedges for the years ended December 31, 2012 , and 2011 , and as such, no ineffectiveness was recognized in earnings for the respective periods. 
+As a result of discontinuing hedge accounting on January 1, 2011, such fair values at December 31, 2010, were frozen in AOCIL as of the de-designation date and are reclassified into earnings as the original derivative transactions settle. As of December 31, 2012 , AOCIL included $1.1 million of net unrealized losses, net of income tax, on commodity derivative contracts that had been previously designated as cash flow hedges, all of which will be reclassified to earnings from AOCIL during the next twelve months. Please refer to Note 11 – Fair Value Measurements for more information regarding the Company’s derivative instruments. 
+The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: 
+As of December 31, 2012 
+Derivative Assets 
+Derivative Liabilities 
+Balance Sheet 
+Classification 
+Fair Value 
+Balance Sheet 
+Classification 
+Fair Value 
+(in thousands) 
+Commodity Contracts 
+Current assets 
+$ 
+37,873 
+Current liabilities 
+$ 
+8,999 
+Commodity Contracts 
+Noncurrent assets 
+16,466 
+Noncurrent liabilities 
+6,645 
+Derivatives not designated as hedging instruments 
+$ 
+54,339 
+$ 
+15,644 
+As of December 31, 2011 
+Derivative Assets 
+Derivative Liabilities 
+Balance Sheet 
+Classification 
+Fair Value 
+Balance Sheet 
+Classification 
+Fair Value 
+(in thousands) 
+Commodity Contracts 
+Current assets 
+$ 
+55,813 
+Current liabilities 
+$ 
+42,806 
+Commodity Contracts 
+Noncurrent assets 
+31,062 
+Noncurrent liabilities 
+12,875 
+Derivatives not designated as hedging instruments 
+$ 
+86,875 
+$ 
+55,681 
+127 
+Table of Contents 
+The following table summarizes the components of unrealized and realized derivative (gain) loss presented in the accompanying statements of operations: 
+For the Years Ended December 31, 
+2012 
+2011 
+(in thousands) 
+Cash settlement (gain) loss: 
+Oil contracts 
+$ 
+11,893 
+$ 
+22,633 
+Gas contracts 
+(47,270 
+) 
+(10,711 
+) 
+NGL contracts 
+(8,887 
+) 
+13,749 
+Total cash settlement (gain) loss 
+(44,264 
+) 
+25,671 
+Unrealized (gain) loss on change in fair value: 
+Oil contracts 
+(31,981 
+) 
+(3,391 
+) 
+Gas contracts 
+31,777 
+(64,310 
+) 
+NGL contracts 
+(11,162 
+) 
+4,944 
+Total net unrealized (gain) on change in fair value 
+(11,366 
+) 
+(62,757 
+) 
+Total unrealized and realized derivative (gain) 
+$ 
+(55,630 
+) 
+$ 
+(37,086 
+) 
+The following table details the effect of derivative instruments on AOCIL and the accompanying statements of operations (net of income tax): 
+Location on 
+Accompanying 
+Statements of 
+Operations 
+For the Years Ended December 31, 
+Derivatives 
+2012 
+2011 
+2010 
+(in thousands) 
+Amount reclassified from AOCIL 
+Commodity Contracts 
+Realized hedge gain (loss) 
+$ 
+(2,264 
+) 
+$ 
+12,997 
+$ 
+6,641 
+The realized net hedge gain for the year ended December 31, 2012 , and net hedge loss for December 31, 2011 , are comprised of realized cash settlements on commodity derivative contracts that were previously designated as cash flow hedges, whereas the realized net hedge gain for the year ended December 31, 2010 , is comprised of realized cash settlements on all commodity derivative contracts. Realized hedge gains or losses from the settlement of commodity derivatives previously designated as cash flow hedges are reported in the total operating revenues and other income section of the accompanying statements of operations. The Company realized a pre-tax net gain of $3.9 million , a net loss of $20.7 million , and a net gain of $23.5 million from its commodity derivative contracts for the years ended December 31, 2012 , 2011 , and 2010 , respectively. 
+As noted above, effective January 1, 2011, the Company elected to de-designate all of its commodity derivative contracts that had been previously designated as cash flow hedges. No new gains or losses are deferred in AOCIL at December 31, 2012 , and 2011 , respectively. 
+128 
+Table of Contents 
+The Company had no derivatives designated as cash flow hedges at December 31, 2012 , and 2011 , respectively. The following table details the ineffective portion of derivative instruments classified as cash flow hedges on the accompanying statements of operations for the year ended December 31, 2010 . 
+Loss Recognized in 
+Earnings 
+(Ineffective Portion) 
+Location on Accompanying 
+Statements of Operations 
+Derivatives Qualifying as Cash Flow Hedges 
+For the Year Ended December 31, 2010 
+(in thousands) 
+Commodity Contracts 
+Unrealized and realized derivative (gain) loss 
+$ 
+8,899 
+Credit Related Contingent Features 
+As of December 31, 2012 , and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility syndicate. The Company’s obligations under its credit facility and derivative contracts are secured by liens on substantially all of the Company’s proved oil and gas properties. 
+Convertible Note Derivative Instrument 
+The contingent interest provision of the 3.50% Senior Convertible Notes was an embedded derivative instrument. The fair value of this derivative was determined to be immaterial as of December 31, 2011 . The 3.50% Senior Convertible Notes were settled during the second quarter of 2012. Please refer to Note 5 - Long-term Debt for additional discussion. 
+Note 11 – Fair Value Measurements 
+The Company follows fair value measurement authoritative accounting guidance for all assets and liabilities measured at fair value. That authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs: 
+• 
+Level 1 – quoted prices in active markets for identical assets or liabilities 
+• 
+Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable 
+• 
+Level 3 – significant inputs to the valuation model are unobservable 
+129 
+Table of Contents 
+The following table is a listing of the Company’s assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of December 31, 2012 : 
+Level 1 
+Level 2 
+Level 3 
+(in thousands) 
+Assets: 
+Derivatives (1) 
+$ 
+— 
+$ 
+54,339 
+$ 
+— 
+Proved oil and gas properties (2) 
+$ 
+— 
+$ 
+— 
+$ 
+209,959 
+Unproved oil and gas properties (2) 
+$ 
+— 
+$ 
+— 
+$ 
+42,765 
+Liabilities: 
+Derivatives (1) 
+$ 
+— 
+$ 
+15,644 
+$ 
+— 
+Net Profits Plan (1) 
+$ 
+— 
+$ 
+— 
+$ 
+78,827 
+(1) This represents a financial asset or liability that is measured at fair value on a recurring basis. 
+(2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. 
+The following table is a listing of the Company’s assets and liabilities that are measured at fair value and where they were classified within the hierarchy as of December 31, 2011 : 
+Level 1 
+Level 2 
+Level 3 
+(in thousands) 
+Assets: 
+Derivatives (1) 
+$ 
+— 
+$ 
+86,875 
+$ 
+— 
+Proved oil and gas properties (2) 
+$ 
+— 
+$ 
+— 
+$ 
+139,992 
+Unproved oil and gas properties (2) 
+$ 
+— 
+$ 
+— 
+$ 
+15,809 
+Liabilities: 
+Derivatives (1) 
+$ 
+— 
+$ 
+55,681 
+$ 
+— 
+Net Profits Plan (1) 
+$ 
+— 
+$ 
+— 
+$ 
+107,731 
+(1) This represents a financial asset or liability that is measured at fair value on a recurring basis. 
+(2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. 
+Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. 
+Derivatives 
+The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration the counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price. Management believes this approach provides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. 
+130 
+Table of Contents 
+Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may ask counterparties to post collateral if their ratings deteriorate. Currently, one counterparty posts collateral when requested by the Company. In some instances the Company will attempt to novate the trade to a more stable counterparty. 
+Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk and takes into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date. All of the Company’s derivative counterparties are members of the Company’s credit facility bank syndicate. 
+The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with accounting authoritative guidance and with other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date. 
+Refer to Note 10 - Derivative Financial Instruments for more information regarding the Company’s derivative instruments. 
+Net Profits Plan 
+The Net Profits Plan is a standalone liability for which there is no available market price, principal market, or market participants. Certain inputs for this instrument are unobservable and are therefore classified as Level 3 inputs. The Company employs the income approach, which converts expected future cash flow amounts to a single present value amount. This technique uses the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value. There is a direct correlation between realized oil, gas, and NGL commodity prices driving net cash flows and the Net Profits Plan liability. Generally, higher commodity prices result in a larger Net Profits Plan liability and lower commodity prices result in a smaller Net Profits Plan liability. 
+The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool. The calculation of this liability is a significant management estimate. For those pools currently in payout, a discount rate of 12 percent is used to calculate this liability. A discount rate of 15 percent is used to calculate the liability for pools that have not reached payout. 
+The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions, discount rates, and the overall market conditions, all of which are continually evaluated to consider the current market environment. The Net Profits Plan liability is determined using price assumptions of five one -year strip prices with the fifth year’s pricing then carried out indefinitely. The average price is adjusted for realized price differentials and to include the effects of the forecasted production covered by derivatives contracts in the relevant periods. The non-cash expense associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the crude oil, gas, and NGL commodity markets. 
+131 
+Table of Contents 
+If the commodity prices used in the calculation changed by five percent , the liability recorded at December 31, 2012 , would differ by approximately $7 million . A one percent increase in the discount rate would decrease the liability by approximately $3 million , whereas a one percent decrease in the discount rate would increase the liability by approximately $4 million . Actual cash payments to be made to participants in future periods are dependent on realized actual production, realized commodity prices, and actual costs associated with the properties in each individual pool of the Net Profits Plan. Consequently, actual cash payments are inherently different from the amounts estimated. 
+No published market quotes exist on which to base the Company’s estimate of fair value of its Net Profits Plan liability. Consequently, the recorded fair value is based entirely on management estimates that are described within this footnote. While some inputs to the Company’s calculation of fair value of the Net Profits Plan’s future payments are from published sources, others, such as the discount rate and the expected future cash flows, are derived from the Company’s own calculations and estimates. 
+The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Beginning balance 
+$ 
+107,731 
+$ 
+135,850 
+$ 
+170,291 
+Net increase (decrease) in liability (1) 
+(9,251 
+) 
+2,269 
+14,063 
+Net settlements (1) (2) (3) 
+(19,653 
+) 
+(30,388 
+) 
+(48,504 
+) 
+Transfers in (out) of Level 3 
+— 
+— 
+— 
+Ending balance 
+$ 
+78,827 
+$ 
+107,731 
+$ 
+135,850 
+(1) 
+Net changes in the Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations. 
+(2) 
+Settlements represent cash payments made or accrued under the Net Profits Plan. The amounts in the table include cash payments made or accrued under the Net Profits Plan of $2.3 million , $6.3 million , and $26.1 million relating to divestiture proceeds for the years ended December 31, 2012 , 2011 , and 2010 respectively. 
+(3) 
+During 2011, the Company elected to cash out several Net Profits Plan pools with a $2.6 million direct payment. As a result, the Company reduced its Net Profits Plan liability by that amount. There was no impact on the accompanying statements of operations for the period ended December 31, 2011 , related to these settlements. 
+Long-term Debt 
+The following table reflects the fair value of the 3.50% Senior Convertible Notes, 2019 Notes, 2021 Notes, and 2023 Notes measured at fair value using Level 1 inputs based on quoted secondary market trading prices: 
+As of December 31, 
+2012 
+2011 
+(in thousands) 
+3.50% Senior Convertible Notes (1) (2) 
+$ 
+— 
+$ 
+394,068 
+2019 Notes 
+$ 
+371,875 
+$ 
+359,408 
+2021 Notes 
+$ 
+371,070 
+$ 
+360,283 
+2023 Notes (3) 
+$ 
+424,200 
+$ 
+— 
+(1) The 3.50% Senior Convertible Notes were settled during the second quarter of 2012. Please refer to Note 5 - Long-term Debt for additional discussion. 
+(2) The estimated fair value of the embedded contingent interest derivative was immaterial as of December 31, 2011 . 
+(3) The 2023 Notes were issued on June 29, 2012 . 
+132 
+Table of Contents 
+There was no long-term debt measured at fair value on the accompanying balance sheets as of December 31, 2012 , or 2011; all long-term debt is presented at historical value. 
+Proved Oil and Gas Properties 
+Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future estimated cash flows to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the Company’s management. The calculation of the discount rate is based on the best information available and was estimated to be 12 percent as of December 31, 2012 , and 2011 . Management believes that the discount rate is representative of current market conditions and takes into account estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years. The prices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used for each commodity stream. Future operating costs are also adjusted as deemed appropriate for these estimates. 
+As a result of asset write-downs, the proved oil and gas properties measured at fair value within the accompanying balance sheets totaled $210.0 million and $140.0 million as of December 31, 2012 and 2011 , respectively. 
+Unproved Oil and Gas Properties 
+Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. The Company uses a market approach, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, and estimated reserve values to measure the fair value of unproved properties. 
+As a result of the asset write-downs, unproved oil and gas properties measured at fair value within the accompanying balance sheets totaled $42.8 million as of December 31, 2012 , and $15.8 million at December 31, 2011 . 
+Materials Inventory 
+Materials inventory is valued at the lower of cost or market. The Company uses Level 2 inputs to measure the fair value of materials inventory, which is primarily comprised of tubular goods. The Company uses third party market quotes and compares the quotes to the book value of the materials inventory. If the book value exceeds the quoted market price, the Company reduces the book value to the market price. The considered factors result in an estimated exit-price. Management believes this approach provides a reasonable and consistent methodology for valuing materials inventory. There were no materials inventory measured at fair value within the accompanying balance sheets at December 31, 2012 , and 2011 . 
+Asset Retirement Obligations 
+The income valuation technique is utilized by the Company to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, the time value of money, and the current economic state to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value within the accompanying balance sheets at December 31, 2012 and 2011 . 
+133 
+Table of Contents 
+Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement 
+Acquisition and Development Agreement 
+In June 2011, the Company entered into an Acquisition and Development Agreement with Mitsui (the “Acquisition and Development Agreement”). Pursuant to the Acquisition and Development Agreement, the Company agreed to transfer to Mitsui a 12.5 percent working interest in certain non-operated oil and gas assets representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick, and Webb Counties, Texas. As consideration for the oil and gas interests transferred, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs attributable to the Company’s remaining interest in these assets until Mitsui has expended an aggregate $680.0 million on behalf of the Company. Based on the Company’s forecast of the operator’s drilling plans, it will take approximately two more years to fully utilize the carry. The Acquisition and Development Agreement also provided for reimbursement of capital expenditures and other costs, net of revenues, paid by the Company that were attributable to the transferred interest during the period between the effective date and the closing date, which the parties agreed would be applied over the carry period to cover the Company’s remaining 10 percent of drilling and completion costs for the affected acreage. 
+A s of December 31, 2012 , the Company held $86.8 million in cash that is contractually restricted for use in the development of assets covered by our Acquisition and Development Agreement with Mitsui. This cash relates to the reimbursement of net costs for the period between the effective date and closing date, as discussed above, as well as an estimate of 90 percent of two months of activity of the Company’s proportionate share of estimated drilling and completion costs. This restricted cash is classified as a non-current asset in the accompanying balance sheets. The Company has recorded a corresponding liability equal to the restricted cash balance. The portion of the liability related to development operations expected to occur within the next year is recorded in accounts payable and accrued expenses within the accompanying balance sheets. The portion of the liability related to development operations expected to occur more than one year in the future is recorded in other noncurrent liabilities within the accompanying balance sheets. There was no net impact on the accompanying statements of cash flows as restricted cash was offset against the corresponding liability in investing activities. There is no direct impact to the accompanying statements of operations as a result of the Acquisition and Development Agreement, with the exception of legal and commission costs associated with the execution of the arrangement which were expensed in 2011 . Of the original $680.0 million carry amount, $277.5 million had been spent as of December 31, 2012 . 
+Carry and Earning Agreement 
+On April 29, 2010 , the Company entered into a Carry and Earning Agreement that provided for a third party to earn 95 percent of SM Energy’s interest in approximately 8,400 net acres in a portion of the Company’s east Texas Haynesville shale acreage, as well as an interest in several wells, and five percent of SM Energy’s interest in approximately 23,400 net acres in a separate portion of the Company’s Haynesville acreage in East Texas. In exchange for these interests, the third party invested $91.3 million to fund the drilling and completion costs of wells in the portion of the leases where the Company retained 95 percent of its interest. The parties now share all costs of operations within the area of joint ownership in accordance with their respective ownership interests. 
+134 
+Table of Contents 
+Note 13 - Suspended Well Costs 
+The following table reflects the net changes in capitalized exploratory well costs during 2012 , 2011 , and 2010 . The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Beginning balance on January 1, 
+$ 
+18,600 
+$ 
+35,862 
+$ 
+34,384 
+Additions to capitalized exploratory well costs pending the determination of proved reserves 
+9,100 
+15,618 
+35,862 
+Reclassifications to wells, facilities, and equipment based on the determination of proved reserves 
+(5,865 
+) 
+(32,880 
+) 
+(34,384 
+) 
+Capitalized exploratory well costs charged to expense 
+(12,735 
+) 
+— 
+— 
+Ending balance at December 31, 
+$ 
+9,100 
+$ 
+18,600 
+$ 
+35,862 
+The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: 
+As of December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Exploratory well costs capitalized for one year or less 
+$ 
+9,100 
+$ 
+15,618 
+$ 
+35,862 
+Exploratory well costs capitalized for more than one year 
+— 
+2,982 
+— 
+Ending balance at December 31, 
+$ 
+9,100 
+$ 
+18,600 
+$ 
+35,862 
+Number of projects with exploratory well costs that have been capitalized more than a year 
+— 
+2 
+— 
+I n the third quarter of 2012, the Company expensed $3.6 million of costs related to two exploratory wells that had been disclosed at December 31, 2011 , as suspended well costs being capitalized for more than one year. 
+135 
+Table of Contents 
+Supplemental Oil and Gas Information (unaudited) 
+Costs Incurred in Oil and Gas Producing Activities 
+Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Development costs (1) 
+$ 
+1,346,216 
+$ 
+1,320,627 
+$ 
+379,636 
+Exploration costs 
+220,921 
+177,465 
+443,888 
+Acquisitions 
+Proved properties 
+5,773 
+— 
+664 
+Unproved properties (2) 
+114,971 
+55,237 
+53,192 
+Total, including asset retirement obligation (3)(4) 
+$ 
+1,687,881 
+$ 
+1,553,329 
+$ 
+877,380 
+(1) 
+Includes facility costs of $62.2 million , $112.4 million , and $80.3 million for the years ended December 31, 2012 , 2011 , and 2010 , respectively. 
+(2) 
+Includes $3.4 million of unproved properties acquired for the year ended December 31, 2012 . The remaining balance relates to leasing activity. 
+(3) 
+Includes capitalized interest of $12.1 million , $10.8 million , and $4.3 million for the years ended December 31, 2012 , 2011 , and 2010 , respectively. 
+(4) 
+Includes amounts relating to estimated asset retirement obligations of $30.6 million , $19.3 million , and $5.8 million for the years ended December 31, 2012 , 2011 , and 2010 , respectively. 
+Oil and Gas Reserve Quantities 
+The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and gas producing activities and SEC rules for oil and gas reporting reserve estimation and disclosure. 
+Proved reserves are the estimated quantities of oil, gas, and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. All of the Company’s estimated proved reserves are located in the United States. 
+136 
+Table of Contents 
+The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period ended December 31, 2012 . The Company engaged Ryder Scott to audit internal engineering estimates for at least 80 percent of the PV-10 value of its estimated proved reserves in each year presented. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. 
+For the Years Ended December 31, 
+2012 (1) 
+2011 (2) 
+2010 (3) 
+Oil 
+Gas 
+NGLs 
+Oil 
+Gas 
+NGLs 
+Oil 
+Gas 
+NGLs 
+(MMBbl) 
+(Bcf) 
+(MMBbl) 
+(MMBbl) 
+(Bcf) 
+(MMBbl) 
+(MMBbl) 
+(Bcf) 
+(MMBbl) 
+Total proved reserves 
+Beginning of year 
+71.7 
+664.0 
+27.5 
+57.4 
+640.0 
+— 
+53.8 
+449.5 
+— 
+Revisions of previous estimate 
+(4.5 
+) 
+(123.3 
+) 
+(2.4 
+) 
+(0.9 
+) 
+(76.7 
+) 
+15.6 
+3.1 
+6.1 
+— 
+Discoveries and extensions 
+17.1 
+297.4 
+30.6 
+26.9 
+223.5 
+17.8 
+16.2 
+172.9 
+— 
+Infill reserves in an existing proved field 
+19.2 
+125.1 
+12.7 
+2.8 
+14.8 
+0.5 
+2.8 
+97.2 
+— 
+Sales of 
+reserves (4) 
+(1.0 
+) 
+(11.0 
+) 
+— 
+(6.4 
+) 
+(37.3 
+) 
+(2.9 
+) 
+(12.1 
+) 
+(14.0 
+) 
+— 
+Purchases of minerals in place 
+0.1 
+1.2 
+— 
+— 
+— 
+— 
+— 
+0.2 
+— 
+Production 
+(10.4 
+) 
+(120.0 
+) 
+(6.1 
+) 
+(8.1 
+) 
+(100.3 
+) 
+(3.5 
+) 
+(6.4 
+) 
+(71.9 
+) 
+— 
+End of year (5) 
+92.2 
+833.4 
+62.3 
+71.7 
+664.0 
+27.5 
+57.4 
+640.0 
+— 
+Proved developed reserves 
+Beginning of year 
+50.3 
+451.2 
+15.2 
+46.0 
+411.0 
+— 
+48.1 
+342.0 
+— 
+End of year 
+58.8 
+483.2 
+27.2 
+50.3 
+451.2 
+15.2 
+46.0 
+411.0 
+— 
+Proved undeveloped reserves 
+Beginning of year 
+21.4 
+212.8 
+12.3 
+11.4 
+229.0 
+— 
+5.7 
+107.5 
+— 
+End of year 
+33.5 
+350.2 
+35.1 
+21.4 
+212.8 
+12.3 
+11.4 
+229.0 
+— 
+(1) 
+Please refer to Part I, Items 1 and 2 and Part II, Item 7 for current year reserve discussion. 
+(2) 
+For the year ended December 31, 2011 , of the 11.5 BCFE upward revision of a previous estimate, (25.3) BCFE and 36.8 BCFE relate to price and performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2011 , were $96.19 per Bbl and $4.12 per MMBtu, for oil and natural gas respectively. These prices were 21 percent higher and six percent lower, respectively, than the prices used in 2010. The per Bbl price used to estimate proved NGL reserves as of December 31, 2011 was $59.37 . There is no 2010 comparative price as 2010 NGL production volumes, revenues, and prices have not been reclassified to conform with current presentation given the immateriality of NGL volumes in that period. Performance revisions in 2011 resulted in a net 36.8 BCFE increase in our estimate of proved reserves. This increase includes the impact of the Company's conversion to three stream production, which is partially offset by downward engineering revisions due primarily to the failure of Woodford shale wells in the Company's Mid-Continent region to satisfy internal economic hurdles. The Company added 526.1 BCFE from its drilling program, the majority of which related to activity in the Eagle Ford shale in South Texas. These additions are included in discoveries and extensions and infill reserves. 
+(3) 
+For the year ended December 31, 2010 , of the 24.7 BCFE upward revision of a previous estimate, 42.6 BCFE and (17.9) BCFE relate to price and performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2010 , were $79.43 per Bbl and $4.38 per MMBtu for oil and natural gas, respectively. These prices were 30 percent and 13 percent higher, respectively, than the prices used in 2009. 
+137 
+Table of Contents 
+Performance revisions in 2010 resulted in a net 11.2 BCFE decrease in the Company's estimate of proved reserves. While the Company recognized upward performance revisions in every region on proved developed properties, it had approximately 19.3 BCFE of downward performance revisions related to estimated proved undeveloped reserves in primarily dry gas assets, resulting from lower gas prices and higher well costs which negatively impacted the economics of these assets. The Company added 384.2 BCFE from its drilling program, the majority of which related to activity in the Eagle Ford shale in south Texas. These additions are included in discoveries and extensions and infill reserves. 
+(4) 
+The Company divested of certain non-core assets during 2012 , 2011 , and 2010 . Please refer to Note 3 - Divestitures and Assets Held for Sale for additional information. 
+(5) 
+For the years ended December 31, 2012 , 2011 , and 2010 , amounts included approximately 299 , 175 , and 356 MMcf respectively, representing the Company’s net underproduced gas balancing position. 
+Note: Prior to 2011, the Company reported its natural gas production as a single stream of rich gas measured at the well head. Beginning in the first quarter of 2011, the Company changed its reporting for natural gas volumes to separately show natural gas and NGL production volumes, revenues, and pricing consistent with title transfer for each product. Please refer to additional discussion above under the caption Oil, Gas, and NGL Prices . 
+Standardized Measure of Discounted Future Net Cash Flows 
+The Company computes a standardized measure of future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. Each property the Company operates is also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using the current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10 percent annual discount factor. 
+Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using year-end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by the central administrative office attributable to operating activities. 
+The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the standardized measure: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+Gas (per Mcf) 
+$ 
+3.08 
+$ 
+4.72 
+$ 
+5.54 
+Oil (per Bbl) 
+$ 
+86.80 
+$ 
+88.00 
+$ 
+70.60 
+NGLs (per Bbl) 
+$ 
+41.00 
+$ 
+51.95 
+$ 
+— 
+138 
+Table of Contents 
+The following summary sets forth the Company’s future net cash flows relating to proved oil, gas, and NGL reserves based on the standardized measure. 
+As of December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Future cash inflows 
+$ 
+13,129,243 
+$ 
+10,871,281 
+$ 
+7,598,159 
+Future production costs 
+(5,013,720 
+) 
+(3,786,887 
+) 
+(2,512,091 
+) 
+Future development costs 
+(1,742,978 
+) 
+(1,036,352 
+) 
+(789,493 
+) 
+Future income taxes 
+(1,609,397 
+) 
+(1,740,394 
+) 
+(1,335,576 
+) 
+Future net cash flows 
+4,763,148 
+4,307,648 
+2,960,999 
+10 percent annual discount 
+(1,742,134 
+) 
+(1,727,608 
+) 
+(1,294,632 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+3,021,014 
+$ 
+2,580,040 
+$ 
+1,666,367 
+The principle sources of change in the standardized measure of discounted future net cash flows are: 
+For the Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands) 
+Standardized measure, beginning of year 
+$ 
+2,580,040 
+$ 
+1,666,367 
+$ 
+1,015,967 
+Sales of oil, gas, and NGLs produced, net of production costs 
+(1,081,997 
+) 
+(1,042,281 
+) 
+(641,213 
+) 
+Net changes in prices and production costs 
+(550,293 
+) 
+454,646 
+557,681 
+Extensions, discoveries and other including infill reserves in an existing proved field, net of production costs 
+1,872,810 
+1,816,640 
+989,365 
+Sales of reserves in place 
+(41,020 
+) 
+(369,820 
+) 
+(151,315 
+) 
+Purchase of reserves in place 
+3,785 
+— 
+804 
+Development costs incurred during the year 
+163,937 
+49,246 
+43,900 
+Changes in estimated future development costs 
+47,980 
+(31,410 
+) 
+49,531 
+Revisions of previous quantity estimates 
+(452,454 
+) 
+32,992 
+66,759 
+Accretion of discount 
+346,118 
+234,433 
+128,408 
+Net change in income taxes 
+53,005 
+(203,169 
+) 
+(409,848 
+) 
+Changes in timing and other 
+79,103 
+(27,604 
+) 
+16,328 
+Standardized measure, end of year 
+$ 
+3,021,014 
+$ 
+2,580,040 
+$ 
+1,666,367 
+139 
+Table of Contents 
+Quarterly Financial Information (unaudited) 
+The Company’s quarterly financial information for fiscal years 2012 and 2011 is as follows (in thousands, except per share amounts): 
+First 
+Second 
+Third 
+Fourth (1) 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+Year Ended December 31, 2012 
+Total operating revenues 
+$ 
+377,423 
+$ 
+304,420 
+$ 
+378,951 
+$ 
+444,308 
+Total operating expenses 
+321,198 
+252,029 
+421,787 
+530,105 
+Income (loss) from operations 
+$ 
+56,225 
+$ 
+52,391 
+$ 
+(42,836 
+) 
+$ 
+(85,797 
+) 
+Income (loss) before income taxes 
+$ 
+42,017 
+$ 
+39,684 
+$ 
+(61,072 
+) 
+$ 
+(104,146 
+) 
+Net income (loss) 
+$ 
+26,336 
+$ 
+24,889 
+$ 
+(38,336 
+) 
+$ 
+(67,138 
+) 
+Basic net income (loss) per common share 
+$ 
+0.41 
+$ 
+0.39 
+$ 
+(0.58 
+) 
+$ 
+(1.02 
+) 
+Diluted net income (loss) per common share 
+$ 
+0.39 
+$ 
+0.37 
+$ 
+(0.58 
+) 
+$ 
+(1.02 
+) 
+Dividends declared per common share 
+$ 
+0.05 
+$ 
+— 
+$ 
+0.05 
+$ 
+— 
+Year Ended December 31, 2011 
+Total operating revenues 
+$ 
+315,329 
+$ 
+377,873 
+$ 
+530,574 
+$ 
+379,542 
+Total operating expenses 
+335,301 
+166,166 
+157,786 
+559,681 
+Income (loss) from operations 
+$ 
+(19,972 
+) 
+$ 
+211,707 
+$ 
+372,788 
+$ 
+(180,139 
+) 
+Income (loss) before income taxes 
+$ 
+(29,558 
+) 
+$ 
+197,384 
+$ 
+363,443 
+$ 
+(192,268 
+) 
+Net income (loss) 
+$ 
+(18,503 
+) 
+$ 
+124,533 
+$ 
+230,097 
+$ 
+(120,711 
+) 
+Basic net income (loss) per common share 
+$ 
+(0.29 
+) 
+$ 
+1.96 
+$ 
+3.60 
+$ 
+(1.89 
+) 
+Diluted net income (loss) per common share 
+$ 
+(0.29 
+) 
+$ 
+1.86 
+$ 
+3.41 
+$ 
+(1.89 
+) 
+Dividends declared per common share 
+$ 
+0.05 
+$ 
+— 
+$ 
+0.05 
+$ 
+— 
+(1) 
+The fourth quarter of 2012 and 2011 included $170.4 million and $170.5 million , respectively, of impairment of proved properties expense. Please refer to the caption Impairment of Proved and Unproved Properties included in Note 1 - Summary of Significant Accounting Policies for additional discussion. 
+140 
+Table of Contents 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+None. 
+ITEM 9A. CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Controls and Procedures 
+We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. 
+Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant. 
+An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls 
+are effective at a reasonable assurance level. 
+Changes in Internal Control Over Financial Reporting 
+There have been no changes during the fourth quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+141 
+Table of Contents 
+Management’s Report on Internal Control over Financial Reporting 
+Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that: 
+(i) 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+(ii) 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+(iii) 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements. 
+Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. 
+Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012 . In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. 
+Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2012 . 
+The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal controls over financial reporting. That report immediately follows this report. 
+142 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Board of Directors and Stockholders of 
+SM Energy Company and Subsidiaries 
+Denver, Colorado 
+We have audited the internal control over financial reporting of SM Energy Company and subsidiaries (the “Company”) as of December 31, 2012 , based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012 , based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 , of the Company and our report dated February 21, 2013 , expressed an unqualified opinion on those financial statements. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 21, 2013 
+143 
+Table of Contents 
+ITEM 9B. OTHER INFORMATION 
+None. 
+PART III 
+ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE 
+The information required by this Item concerning SM Energy’s Directors and corporate governance is incorporated by reference to the information provided under the captions Structure of the Board of Directors, Proposal 1 - Election of Directors, and Corporate Governance in SM Energy’s definitive proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012 . 
+The information required by this Item concerning compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated by reference to the information provided under the caption Section 16(a) Beneficial Ownership Reporting Compliance in SM Energy’s definitive proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012 . 
+EXECUTIVE OFFICERS OF THE REGISTRANT 
+The following table sets forth the names, ages and positions of SM Energy’s executive officers. The age of the executive officers is as of February 14, 2013. 
+Name 
+Age 
+Position 
+Anthony J. Best 
+63 
+Chief Executive Officer 
+Javan D. Ottoson 
+54 
+President and Chief Operating Officer 
+A. Wade Pursell 
+47 
+Executive Vice President and Chief Financial Officer 
+David W. Copeland 
+56 
+Senior Vice President, General Counsel and Corporate Secretary 
+Gregory T. Leyendecker 
+55 
+Senior Vice President and Regional Manager 
+Mark D. Mueller 
+48 
+Senior Vice President and Regional Manager 
+Lehman E. Newton, III 
+57 
+Senior Vice President and Regional Manager 
+Herbert S. Vogel 
+52 
+Senior Vice President - Portfolio Development and Technical Services 
+Kenneth J. Knott 
+48 
+Vice President - Land 
+Mary Ellen Lutey 
+41 
+Vice President and Regional Manager 
+Mark T. Solomon 
+44 
+Vice President - Controller and Assistant Secretary 
+David J. Whitcomb 
+50 
+Vice President - Marketing 
+Dennis A. Zubieta 
+46 
+Vice President - Engineering, Evaluation and A&D 
+Anthony J. Best. Mr. Best joined the Company in June 2006 as President and Chief Operating Officer. In December 2006, Mr. Best relinquished his position as Chief Operating Officer when the Board appointed Javan D. Ottoson to that office. Mr. Best was elected Chief Executive Officer and a director of the Company in February 2007. Mr. Best relinquished his position as President when the Board appointed Mr. Ottoson to that office in October 2012. From November 2005 to June 2006, Mr. Best was developing a business plan and securing capital commitments for a new exploration and production entity. From 2003 to October 2005, Mr. Best was President and Chief Executive Officer of Pure Resources, Inc., an independent oil and natural gas exploration and production company that was a subsidiary of Unocal, where he managed all of Unocal’s onshore United States assets. From 2000 to 2002, Mr. Best had an oil and gas consulting practice, working with various energy firms. From 1979 to 2000, Mr. Best was with ARCO in a variety of positions, including serving as President-ARCO Latin America, President-ARCO Permian, Field Manager for Prudhoe Bay and VP-External Affairs for ARCO Alaska. Mr. Best has over 34 years of experience in the energy industry. 
+144 
+Table of Contents 
+Javan D. Ottoson. Mr. Ottoson joined the Company in December 2006 as Executive Vice President and Chief Operating Officer. Mr. Ottoson was appointed as President of the Company in October 2012. Mr. Ottoson has been in the energy industry for over 31 years. From April 2006 until he joined the Company in December 2006, Mr. Ottoson was Senior Vice President-Drilling and Engineering at Energy Partners, Ltd., an independent oil and natural gas exploration and production company, where his responsibilities included overseeing all aspects of its drilling and engineering functions. Mr. Ottoson managed Permian Basin assets for Pure Resources, Inc., a Unocal subsidiary, and its successor owner, Chevron, from July 2003 to April 2006. From April 2000 to July 2003, Mr. Ottoson owned and operated a homebuilding company in Colorado and ran his family farm. Prior to 2000, Mr. Ottoson worked for ARCO in management and operational roles, including serving as President of ARCO China, Commercial Director of ARCO United Kingdom, and Vice President of Operations and Development, ARCO Permian. 
+A. Wade Pursell. Mr. Pursell joined the Company in September 2008 as Executive Vice President and Chief Financial Officer. Mr. Pursell was Executive Vice President and Chief Financial Officer for Helix Energy Solutions Group, Inc., a global provider of life-of-field services and development solutions to offshore energy producers and an oil and gas producer, from February 2007 to September 2008. From October 2000 to February 2007, he was Senior Vice President and Chief Financial Officer of Helix. He joined Helix in May 1997, as Vice President-Finance and Chief Accounting Officer. From 1988 through May 1997, Mr. Pursell was with Arthur Andersen LLP, serving lastly as an Experienced Manager specializing in the offshore services industry. Mr. Pursell has over 25 years of experience in the energy industry. 
+David W. Copeland. Mr. Copeland joined the Company in January 2011 as Senior Vice President and General Counsel. He was appointed as the Company’s Corporate Secretary in July 2011. Mr. Copeland has over 31 years of experience in the legal profession, including over 21 years as internal counsel for various energy companies. Prior to joining the Company, he co-founded Concho Resources Inc., in Midland, Texas, where he served as its Vice President, General Counsel and Secretary from April 2004 through November 2009, and then as its Senior Counsel through December 2010. From August 1997 through March 2004, Mr. Copeland served as an executive officer and general counsel of two energy companies he co-founded in Midland, Texas with others. Mr. Copeland started his career in 1982 with the Stubbeman, McRae, Sealy, Laughlin & Browder law firm in Midland, Texas. 
+Gregory T. Leyendecker. Mr. Leyendecker was appointed Senior Vice President and Regional Manager in May 2010. From July 2007 to May 2010, he served as Vice President and Regional Manager. Mr. Leyendecker joined the Company in December 2006 as Operations Manager for the South Texas & Gulf Coast region in Houston, Texas. Mr. Leyendecker has over 32 years of experience in the energy industry, and held various positions with Unocal Corporation, an independent oil and natural gas exploration and production company, from 1980 until its acquisition in 2005. During his career with Unocal, he was the Asset Manager for Unocal Gulf Region USA from 2003 to June 2004 and Production and Reservoir Engineering Technology Manager for Unocal from June 2004 to August 2005. He was appointed Drilling and Workover Manager for the San Joaquin Valley business unit of Chevron, as successor-by-merger of Unocal Corporation, in Bakersfield, California in August 2005, and held this position until January 2006. Immediately prior to joining the Company, Mr. Leyendecker was Vice President of Drilling Management Services from February 2006 to November 2006 for Enventure Global Technology, a provider of solid expandable tubular technology. 
+145 
+Table of Contents 
+Mark D. Mueller. Mr. Mueller joined the Company in September 2007 as Senior Vice President. Mr. Mueller was appointed as the Regional Manager of the Rocky Mountain region effective January 1, 2008. Mr. Mueller has been in the energy industry for over 26 years. From September 2006 to September 2007, he was Vice President and General Manager at Samson Exploration Ltd., an oil and gas exploration and production company that was a subsidiary of Samson Investment Company, in Calgary, Canada, where his responsibilities included fiscal performance, reserves, and all operational functions of the company. From April 2005 until its sale in August 2006, Mr. Mueller was Vice President and General Manager for Samson Canada Ltd., an oil and gas exploration and production company that was a subsidiary of Samson Investment Company, where he was responsible for all business units and the eventual sale of the company. Mr. Mueller joined Samson Canada Ltd. as Project Manager in May 2003 to build a new basin-centered gas business unit and was Vice President from December 2003 to August 2006. Prior to joining Samson, Mr. Mueller was West Central Alberta Engineering Manager for Northrock Resources Ltd., a Canadian oil and gas company that was a wholly-owned subsidiary of Unocal Corporation, in Calgary, Canada. From 1986 to 2003, Mr. Mueller held positions of increasing responsibility in engineering and management for Unocal throughout North America and Southeast Asia. 
+Lehman E. Newton, III. Mr. Newton joined the Company in December 2006 as General Manager for the Midland, Texas office, was appointed Vice President and Regional Manager of the Permian region in June 2007, and was appointed Senior Vice President and Regional Manager in May 2010. Mr. Newton has over 34 years of experience in the energy industry. From November 2005 to November 2006, Mr. Newton served as Project Manager for one of Chevron’s largest Lower 48 projects. Mr. Newton joined Pure Resources in February 2003 as the Business Development Manager and worked in that capacity until October 2005. Mr. Newton was a founding partner in Westwin Energy, an independent Permian Basin exploration and production company, from June 2000 to January 2003. Prior to that, Mr. Newton spent 21 years with ARCO in various engineering, operations and management roles, including as Asset Manager, ARCO’s East Texas operations, Vice President, Business Development, ARCO Permian, and Vice President of Operations and Development, ARCO Permian. 
+Herbert S. Vogel . Mr. Vogel joined the Company in March 2012 as Senior Vice President-Portfolio Development and Technical Services, and is responsible for Corporate Exploration, Engineering, Land, Marketing and EHS activities. Mr. Vogel has over 28 years of experience in the oil and gas business. He joined the Company after his retirement from BP, where he most recently served as the President of BP Energy Co. and Regional Business Unit Leader of North American Gas & Power. His previous roles included COO-NGL, Power & Financial Products in Houston, Managing Director Gas Europe & Africa in London, and Sr. VP of the Tangguh LNG Project in Indonesia. Mr. Vogel started his career as a reservoir engineer with ARCO Alaska, Inc., and progressed through a series of positions of increasing responsibility in engineering, operations management, new ventures development, and business unit management at ARCO and BP. 
+Kenneth J. Knott . Mr. Knott was appointed Vice President - Land in October 2012, and is responsible for all of the Company's regional and administrative land functions. Mr. Knott was appointed Vice President of Business Development & Land and Assistant Secretary in August 2008. Mr. Knott joined SM Energy in November 2000 as Senior Landman for the Gulf Coast region in Lafayette, Louisiana, and later assumed the position of Gulf Coast Regional Land Manager when the office was moved to Houston in March 2004. 
+146 
+Table of Contents 
+Mary Ellen Lutey . Ms. Lutey was appointed Vice President and Regional Manager of the Mid-Continent region in December 2012. She joined SM Energy in June 2008 as North Rockies Asset Manager, where she managed the Company's activities in the Williston Basin. Prior to joining SM Energy, Ms. Lutey held various technical and managerial positions in several regions of the United States and Canada. She was a Senior Reservoir Engineer with Chesapeake Energy Corporation from September 2007 until June 2008, where she was responsible for the resource development of the Fayetteville Shale in Arkansas. Ms. Lutey was a Team Lead for Engineering and Geoscience, with ConocoPhillips Canada from April 2006 until September 2007, where she was responsible for the technical and business performance of two multi-discipline groups in Western Canada. From July 2005 until April 2006, she was a Team Lead for Engineering and Geoscience, with Burlington Resources Canada where she managed the growth and development of resource plays in Western Canada. From 1994 until 2005, Ms. Lutey held various engineering and leadership positions of increasing responsibility for Burlington Resources. Ms. Lutey has over 21 years of experience in the energy industry. 
+Mark T. Solomon. Mr. Solomon was appointed Vice President-Controller and Assistant Secretary of the Company in May 2011. He was appointed Controller of the Company in January 2007. Mr. Solomon served as the Company’s Acting Principal Financial Officer from April 2008, to September 2008, which was during the period of time that the Company’s Chief Financial Officer position was vacant. Mr. Solomon joined the Company in 1996. He served as Financial Reporting Manager from February 1999 to September 2002, Assistant Vice President-Financial Reporting from September 2002 to May 2006 and Assistant Vice President-Assistant Controller from May 2006 to January 2007. Prior to joining the Company, Mr. Solomon was an auditor with Ernst & Young. Mr. Solomon has over 16 years of experience in the energy industry. 
+David J. Whitcomb . Mr. Whitcomb was appointed Vice President - Marketing in August 2008. Mr. Whitcomb joined SM Energy in November 1994 as Gas Contract Analyst and was named Assistant Vice President of Gas Marketing in October 1995. In March 2007, his responsibilities were expanded to include oil marketing, at which time his title was changed to Assistant Vice President and Director of Marketing. 
+Dennis A. Zubieta. Mr. Zubieta was appointed Vice President-Engineering, Evaluation and A&D in October 2012. He was appointed Vice President-Engineering and Evaluation of the Company in August 2008. Mr. Zubieta joined the Company in June 2000 as Corporate A&D Engineer, assumed the role of Reservoir Engineer in February 2003, and was appointed Reservoir Engineering Manager in August 2005. Mr. Zubieta was employed by Burlington Resources from June 1988 to May 2000 in various operations and reservoir engineering capacities. Mr. Zubieta has over 25 years of experience in the energy industry. 
+ITEM 11. EXECUTIVE COMPENSATION 
+The information required by this Item is incorporated by reference to the information provided under the captions, Executive Compensation and Director Compensation in SM Energy’s definitive proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012 . 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The information required by this Item concerning security ownership of certain beneficial owners and management is incorporated by reference to the information provided under the caption Security Ownership of Certain Beneficial Owners and Management in SM Energy’s definitive proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012 . 
+147 
+Table of Contents 
+Securities Authorized for Issuance Under Equity Compensation Plans. SM Energy has the Equity Plan under which options and shares of SM Energy common stock are authorized for grant or issuance as compensation to eligible employees, consultants, and members of the Board of Directors. Our stockholders have approved this plan. See Note 7 – Compensation Plans included in Part II, Item 8 of this report for further information about the material terms of our equity compensation plans. The following table is a summary of the shares of common stock authorized for issuance under the equity compensation plans as of December 31, 2012 : 
+(a) 
+(b) 
+(c) 
+Plan category 
+Number of securities to be issued upon exercise of outstanding options, warrants, and rights 
+Weighted-average exercise price of outstanding options, warrants, and rights 
+Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) 
+Equity compensation plans approved by security holders: 
+Equity Incentive Compensation Plan 
+Stock options and incentive stock options (1) 
+267,846 
+$ 
+14.95 
+Restricted stock (1)(3) 
+496,244 
+N/A 
+Performance share units (1)(3)(4) 
+899,604 
+N/A 
+Total for Equity Incentive Compensation Plan 
+1,663,694 
+$ 
+14.95 
+1,366,465 
+Employee Stock Purchase Plan (2) 
+- 
+- 
+1,307,484 
+Equity compensation plans not approved by security holders 
+- 
+- 
+- 
+Total for all plans 
+1,663,694 
+$ 
+14.95 
+2,673,949 
+(1) 
+In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and members of the Board of Directors of SM Energy or any affiliate of SM Energy. The Equity Plan serves as the successor to the St. Mary Land & Exploration Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock Option Plan, the SM Energy Company Restricted Stock Plan, and the SM Energy Company Non-Employee Director Stock Compensation Plan (collectively referred to as the “Predecessor Plans”). All grants of equity are now made under the Equity Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under a Predecessor Plan immediately prior to the effective date of the Equity Plan continues to be governed solely by the terms and conditions of the instruments evidencing such grants or issuances. Our Board of Directors approved amendments to the Equity Plan in 2009 and 2010 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The awards granted in 2012, 2011, and 2010 under the Equity Plan were 724,671 , 386,802 , and 540,774 , respectively. 
+(2) 
+Under the SM Energy Company ESPP, eligible employees may purchase shares of our common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the six-month offering period, and shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. Shares issued under the ESPP totaled 66,485 , 41,358 , and 52,948 in 2012, 2011, and 2010, respectively. 
+(3) 
+RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per share fair value, which is presented in order to provide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per share fair value for the outstanding RSUs and PSUs was $ 51.81 and $63.08, respectively. Please refer to Note 7 - Compensation Plan for additional discussion. 
+(4) 
+The number of awards vested assumes a one multiplier. The final number of shares issued upon settlement may vary depending on the three -year multiplier determined at the end of the performance period under the Equity Plan, which ranges from zero to two . 
+148 
+Table of Contents 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+The information required by this Item is incorporated by reference to the information provided under the caption Certain Relationships and Related Transactions, and Corporate Governance, in SM Energy’s definitive proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012 . 
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+The information required by this Item is incorporated by reference to the information provided under the caption Independent Registered Public Accounting Firm and Audit Committee Preapproval Policy and Procedures in SM Energy’s definitive proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012 . 
+149 
+Table of Contents 
+PART IV 
+ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
+(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules: 
+Report of Independent Registered Public Accounting Firm 
+89 
+Consolidated Balance Sheets 
+90 
+Consolidated Statements of Operations 
+91 
+Consolidated Statements of Comprehensive Income (Loss) 
+92 
+Consolidated Statements of Stockholders’ Equity 
+93 
+Consolidated Statements of Cash Flows 
+94 
+Notes to Consolidated Financial Statements 
+96 
+All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto. 
+(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K: 
+Exhibit 
+Number 
+Description 
+2.1 
+Purchase and Sale Agreement dated December 17, 2009 and effective as of November 1, 2009, between Legacy Reserves Operating LP and St. Mary Land & Exploration Company (filed as Exhibit 2.5 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference) 
+2.2 
+Purchase and Sale Agreement dated January 7, 2010 and effective as of November 1, 2009, between Sequel Energy Partners LP, Bakken Energy Partners, LLC, Three Forks Energy Partners, LLC and St. Mary Land & Exploration Company (filed as Exhibit 2.6 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference) 
+2.3 
+Purchase and Sale Agreement dated June 9, 2011, among SM Energy Company, Statoil Texas Onshore Properties LLC, and Talisman Energy USA Inc. (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 and incorporated herein by reference) 
+2.4 
+Acquisition and Development Agreement dated June 29, 2011 between SM Energy Company and Mitsui E&P Texas LP (filed as Exhibit 2.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 and incorporated herein by reference) 
+2.5 
+First Amendment to Acquisition and Development Agreement dated October 13, 2011 between SM Energy Company and Mitsui E&P Texas (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 and incorporated herein by reference) 
+3.1 
+Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+3.2 
+Amended and Restated By-Laws of SM Energy Company amended effective as of January 1, 2013 (filed as Exhibit 3.1 to the registrant’s Current Report on Form 8-K filed on January 7, 2013, and incorporated herein by reference) 
+150 
+Table of Contents 
+4.1 
+Indenture related to the 3.50% Senior Convertible Notes due 2027, dated as of April 4, 2007, between St. Mary Land & Exploration Company and Wells Fargo Bank, National Association, as trustee (including the form of 3.50% Senior Convertible Note due 2027) (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on April 4, 2007 and incorporated herein by reference) 
+4.2 
+Indenture related to the 6.625% Senior Notes due 2019, dated as of February 7, 2011, by and between SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on February 10, 2011, and incorporated herein by reference) 
+4.3 
+Indenture related to the 6.50% Senior Notes due 2021, dated as of November 8, 2011, by and among SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on November 10, 2011, and incorporated herein by reference) 
+4.4 
+Indenture related to the 6.50% Senior Notes due 2023, dated June 29, 2012, between SM Energy Company, as Issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on July 3, 2012, and incorporated herein by reference) 
+4.5 
+Registration Rights Agreement, dated June 29, 2012, among SM Energy Company and Wells Fargo Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as representatives of several purchasers (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on July 3, 2012, and incorporated herein by reference) 
+10.1† 
+Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference) 
+10.2† 
+Incentive Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.2 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference) 
+10.3† 
+Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001 and incorporated herein by reference) 
+10.4† 
+Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.9 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein by reference) 
+10.5† 
+Employment Agreement of A.J. Best dated May 1, 2006 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 4, 2006 and incorporated herein by reference) 
+10.6 
+Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement for the benefit of Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference) 
+10.7 
+Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference) 
+10.8† 
+Equity Incentive Compensation Plan as Amended and Restated as of March 26, 2009 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 27, 2009, and incorporated herein by reference) 
+10.9† 
+Equity Incentive Compensation Plan As Amended and Restated as of April 1, 2010 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on June 2, 2010, and incorporated herein by reference) 
+10.10 s 
+SM Energy Company Equity Incentive Compensation Plan, As Amended as of July 30, 2010 (filed as Exhibit 10.7 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.11† 
+Third Amendment to Employee Stock Purchase Plan dated September 23, 2009 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, and incorporated herein by reference) 
+151 
+Table of Contents 
+10.12† 
+Fourth Amendment to Employee Stock Purchase Plan dated December 29, 2009 (filed as Exhibit 10.46 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein by reference) 
+10.13 s 
+Employee Stock Purchase Plan, As Amended and Restated as of July 30, 2010 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.14 
+Carry and Earning Agreement between St. Mary Land & Exploration Company and Encana Oil & Gas (USA) Inc. executed as of April 29, 2010 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.15† 
+Form of Performance Share and Restricted Stock Unit Award Agreement as of July 1, 2010 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.16† 
+Form of Performance Share and Restricted Stock Unit Award Notice as of July 1, 2010 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.17† 
+Form of Non-Employee Director Restricted Stock Award Agreement as of May 27, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.18*** 
+Gas Services Agreement effective as of July 1, 2010 between SM Energy Company and Eagle Ford Gathering LLC (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.19 s 
+Cash Bonus Plan, As Amended on July 30, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.20 s 
+Net Profits Interest Bonus Plan, As Amended by the Board of Directors on July 30, 2010 (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.21 s 
+SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan, As Amended as of July 30, 2010 (filed as Exhibit 10.8 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.22† 
+Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on December 29, 2010, and incorporated herein by reference) 
+10.23† 
+Amendment to A.J. Best Employment Agreement dated December 31, 2010 (filed as Exhibit 10.28 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference) 
+10.24 
+Purchase Agreement, dated January 31, 2011, among SM Energy Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as representatives of the Initial Purchasers named therein (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on February 1, 2011, and incorporated herein by reference) 
+10.25 
+Pension Plan for Employees of SM Energy Company as Amended and Restated as of January 1, 2010 (filed as Exhibit 10.30 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference) 
+10.26+ 
+SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan as Amended as of November 9, 2010 (filed as Exhibit 10.31 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference) 
+10.27*† 
+Summary of Compensation Arrangements for Non-Employee Directors 
+10.28 
+Fourth Amended and Restated Credit Agreement dated May 27, 2011 among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.29 
+Gas Gathering Agreement dated May 31, 2011 between Regency Field Services LLC and SM Energy Company (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+152 
+Table of Contents 
+10.30 
+Gathering and Natural Gas Services Agreement effective as of April 1, 2011 between SM Energy Company and ETC Texas Pipeline, Ltd. (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.31 
+Gas Processing Agreement effective as of April 1, 2011 between ETC Texas Pipeline, Ltd. and SM Energy Company (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.32† 
+Employee Stock Purchase Plan, As Amended and Restated as of June 10, 2011 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.33† 
+Form of Performance Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.34† 
+Form of Restricted Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.7 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.35† 
+Form of Performance Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference) 
+10.36† 
+Form of Restricted Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference) 
+10.37 
+Amendment No. 1 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2011 (filed as Exhibit 10.41 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and incorporated herein by reference) 
+10.38 
+Amendment No. 2 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2012 (filed as Exhibit 10.42 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and incorporated herein by reference) 
+12.1* 
+Computation of Ratio of Earnings to Fixed Charges 
+21.1* 
+Subsidiaries of Registrant 
+23.1* 
+Consent of Deloitte & Touche LLP 
+23.2* 
+Consent of Ryder Scott Company L.P. 
+24.1* 
+Power of Attorney 
+31.1* 
+Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002 
+31.2* 
+Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002 
+32.1** 
+Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002 
+99.1* 
+Ryder Scott Audit Letter 
+101.INS**** 
+XBRL Instance Document 
+101.SCH**** 
+XBRL Schema Document 
+101.CAL**** 
+XBRL Calculation Linkbase Document 
+101.LAB**** 
+XBRL Label Linkbase Document 
+101.PRE**** 
+XBRL Presentation Linkbase Document 
+101.DEF**** 
+XBRL Taxonomy Extension Definition Linkbase Document 
+* Filed with this Form 10-K. 
+** Furnished with this Form 10-K. 
+*** 
+Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934. 
+**** 
+Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of 
+153 
+Table of Contents 
+Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections. 
+† 
+Exhibit constitutes a management contract or compensatory plan or agreement. 
+s 
+Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the recent change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the substantive terms and conditions in this document. 
++ 
+Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal Revenue Code. There were no material changes to the substantive terms and conditions in this document. 
+(c) Financial Statement Schedules. See Item 15(a) above. 
+154 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+SM ENERGY COMPANY 
+(Registrant) 
+Date: 
+February 21, 2013 
+By: 
+/s/ ANTHONY J. BEST 
+Anthony J. Best 
+Chief Executive Officer 
+(Principal Executive Officer) 
+GENERAL POWER OF ATTORNEY 
+KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints each of Anthony J. Best and A. Wade Pursell his or her true and lawful attorney-in-fact and agent with full power of substitution and resubstitution, and each with full power to act alone, for the undersigned and in his or her name, place and stead, in any and all capacities, to sign any amendments to this Annual Report on Form 10-K for the fiscal year ended December 31, 2012 , and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorney-in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof. 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signature 
+Title 
+Date 
+/s/ ANTHONY J. BEST 
+Chief Executive Officer and Director 
+February 21, 2013 
+Anthony J. Best 
+(Principal Executive Officer) 
+/s/ A. WADE PURSELL 
+Executive Vice President and Chief Financial Officer 
+February 21, 2013 
+A. Wade Pursell 
+(Principal Financial Officer) 
+/s/ MARK T. SOLOMON 
+Vice President - Controller and Assistant Secretary 
+February 21, 2013 
+Mark T. Solomon 
+(Principal Accounting Officer) 
+155 
+Table of Contents 
+Signature 
+Title 
+Date 
+/s/ WILLIAM D. SULLIVAN 
+Chairman of the Board of Directors 
+February 21, 2013 
+William D. Sullivan 
+/s/ BARBARA M. BAUMANN 
+Director 
+February 21, 2013 
+Barbara M. Baumann 
+/s/ LARRY W. BICKLE 
+Director 
+February 21, 2013 
+Larry W. Bickle 
+/s/ STEPHEN R. BRAND 
+Director 
+February 21, 2013 
+Stephen R. Brand 
+/s/ WILLIAM J. GARDINER 
+Director 
+February 21, 2013 
+William J. Gardiner 
+/s/ LOREN M. LEIKER 
+Director 
+February 21, 2013 
+Loren M. Leiker 
+/s/ JULIO M. QUINTANA 
+Director 
+February 21, 2013 
+Julio M. Quintana 
+/s/ JOHN M. SEIDL 
+Director 
+February 21, 2013 
+John M. Seidl 
+156
\ No newline at end of file
diff --git a/raw/filings/0000893538/2012/0000893538-13-000011/filing_metadata.csv b/raw/filings/0000893538/2012/0000893538-13-000011/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..9df9a29ecdbc6d3f57f86350f6afd567bc08456d
--- /dev/null
+++ b/raw/filings/0000893538/2012/0000893538-13-000011/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000893538,SM,SM Energy Co,10-K,2013-02-21,2012-12-31,2013-02-21T13:59:54.000Z,0000893538-13-000011,sm-20121231x10k.htm,FORM 10-K,18779938,1,0,https://www.sec.gov/Archives/edgar/data/893538/000089353813000011/sm-20121231x10k.htm,https://www.sec.gov/Archives/edgar/data/893538/000089353813000011/,2012,2012,1
diff --git a/raw/filings/0000893538/2012/0000893538-13-000011/item1.txt b/raw/filings/0000893538/2012/0000893538-13-000011/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2012/0000893538-13-000011/item13.txt b/raw/filings/0000893538/2012/0000893538-13-000011/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..55f6c7cbde4cd2168fe21de78c49ae8d0fc08361
--- /dev/null
+++ b/raw/filings/0000893538/2012/0000893538-13-000011/item13.txt
@@ -0,0 +1,3 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+The information required by this Item is incorporated by reference to the information provided under the caption Certain Relationships and Related Transactions, and Corporate Governance, in SM Energy’s definitive proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012 .
\ No newline at end of file
diff --git a/raw/filings/0000893538/2012/0000893538-13-000011/item9a.txt b/raw/filings/0000893538/2012/0000893538-13-000011/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..965c215f34419a6d0dd54846cca411267fe2c723
--- /dev/null
+++ b/raw/filings/0000893538/2012/0000893538-13-000011/item9a.txt
@@ -0,0 +1,39 @@
+ITEM 9A. CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Controls and Procedures 
+We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. 
+Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant. 
+An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls 
+are effective at a reasonable assurance level. 
+Changes in Internal Control Over Financial Reporting 
+There have been no changes during the fourth quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+141 
+Table of Contents 
+Management’s Report on Internal Control over Financial Reporting 
+Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that: 
+(i) 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+(ii) 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+(iii) 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements. 
+Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. 
+Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012 . In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. 
+Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2012 . 
+The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal controls over financial reporting. That report immediately follows this report. 
+142 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Board of Directors and Stockholders of 
+SM Energy Company and Subsidiaries 
+Denver, Colorado 
+We have audited the internal control over financial reporting of SM Energy Company and subsidiaries (the “Company”) as of December 31, 2012 , based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012 , based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 , of the Company and our report dated February 21, 2013 , expressed an unqualified opinion on those financial statements. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 21, 2013 
+143 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000893538/2012/0000893538-13-000011/rp_note.txt b/raw/filings/0000893538/2012/0000893538-13-000011/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2012/0000893538-13-000011/rpt_disclosure.txt b/raw/filings/0000893538/2012/0000893538-13-000011/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..a8771ab3e70e5213a01053593154ea2c932d786f
--- /dev/null
+++ b/raw/filings/0000893538/2012/0000893538-13-000011/rpt_disclosure.txt
@@ -0,0 +1,41 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+Policies and Procedures on Transactions with Related Persons 
+We have adopted a Policy and Procedures with Respect to Related Person Transactions (the "Related Person Transactions Policy"), which
+sets forth the policies and procedures for the Audit Committee's review of any transaction, arrangement, or relationship (including any indebtedness or guarantee of indebtedness) or series of similar
+transactions, arrangements, or relationships in which (a) we are a participant, (b) the aggregate amount involved will or may be expected to exceed $120,000 per annum, and (c) a
+related person has or will have a direct or indirect material interest. For purposes of our Related Person Transactions Policy, a "related person" means (i) any of our directors, executive
+officers, or nominees for director, (ii) any stockholder that beneficially owns more than 5% of our outstanding shares of common stock, and (iii) any immediate family member of any of
+the foregoing. The Audit Committee approves or ratifies only those transactions that it determines in good faith are in, or are not inconsistent with, our best interests and the best interests of our
+stockholders. 
+In
+determining whether to approve or ratify a transaction with a related person, the Audit Committee takes into account the factors it deems appropriate, which may include, among others,
+the benefits to us, the availability of other sources for comparable products or services, the impact on a director's independence in the event the related person is a director, and the extent of the
+related person's interest in the transaction. The policy also provides for the delegation of Audit Committee authority to the Chair of the Audit Committee for any related person transaction requiring
+pre-approval or ratification between meetings of the Audit Committee. The Audit Committee reviews and assesses ongoing relationships with a related person on at least an annual basis to
+ensure that they are in compliance with the policy and remain appropriate. 
+In
+addition, our By-Laws provide that a director, officer, or employee of our company may not pursue for his or her own account a business or investment opportunity that he
+or she learned about 
+11 
+Table of Contents 
+through
+his or her affiliation with us. These restrictions do not apply to the acquisition of less than 1% of the publicly traded stock of another company. 
+Related Person Transactions 
+We recognize that transactions with related persons may raise questions among stockholders regarding whether those transactions are
+consistent with our best interests and the best interests of our stockholders. It is our policy to enter into or ratify such transactions only when the Board, acting through the Audit Committee or as
+otherwise described herein, determines that the transaction in question is in, or is not inconsistent with, our best interests and the best interests of our stockholders. Such transactions include,
+but are not limited to, situations where we may obtain products or services of a nature, quantity or quality, or on other terms, that are not readily available from alternate sources, or when we
+obtain products or services from, or provide products or services to, related persons on an arm's length basis on terms comparable to those obtained from or provided to unrelated third parties or on
+terms comparable to those obtained from or provided to employees generally. The only transaction between our company and a related person since January 1, 2012, is our relationship with Tesco,
+which was referenced above. Mr. Quintana is the President, Chief Executive Officer, and a director of Tesco, which designs, manufactures, and delivers technology based solutions for the
+upstream energy industry, including oilfield drilling and completion technology, services, and equipment. We have an agreement with Tesco for its provision of equipment and services to us in
+connection with our drilling and completion operations. This agreement continues until canceled by either us or Tesco on 30 days advance written notice. Pursuant to this agreement, we are
+obligated to pay Tesco only for services actually performed or equipment provided, as the case may be, as requested by us from time to time. This agreement does not require us to make any other
+payments to Tesco, nor does it obligate us to use Tesco for any services or equipment. Mr. Quintana does not have any direct or indirect interest in the transaction, other than as a result of
+serving as an executive officer and director of Tesco. Mr. Quintana had no input in our selection of Tesco for equipment and services or the terms of our agreement with Tesco. Decisions to use
+Tesco are made by technical professionals supervising the relevant regional activity, based on their assessment of Tesco's equipment and services and related costs in comparison to other providers. In
+2012, we paid Tesco $600,265. The amount we paid Tesco during 2012 for equipment and services represented approximately 6% of the total amount paid by us to all service providers (including Tesco) for
+similar equipment and services during 2012. As of March 31, 2013, we had paid Tesco $350,517 for equipment and services rendered during 2013. In accordance with our Related Person Transactions
+Policy, the Audit Committee reviewed the relationship between us and Tesco and determined that the relationship is in our best interests and the best interests of our stockholders. 
+12 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000893538/2013/0000893538-14-000010/filing.txt b/raw/filings/0000893538/2013/0000893538-14-000010/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..253c6843ba86bba6f7d1326cbada27960089ace3
--- /dev/null
+++ b/raw/filings/0000893538/2013/0000893538-14-000010/filing.txt
@@ -0,0 +1,7822 @@
+10-K
+1
+sm-20131231x10k.htm
+10-K
+SM-2013.12.31-10K 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+þ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 
+For the fiscal year ended December 31, 2013 
+or 
+o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 
+Commission file number 001-31539 
+SM ENERGY COMPANY 
+(Exact name of registrant as specified in its charter) 
+Delaware 
+(State or other jurisdiction 
+of incorporation or organization) 
+41-0518430 
+(I.R.S. Employer Identification No.) 
+1775 Sherman Street, Suite 1200, Denver, Colorado 
+(Address of principal executive offices) 
+80203 
+(Zip Code) 
+(303) 861-8140 
+(Registrant’s telephone number, including area code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+Common stock, $.01 par value 
+New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer þ 
+Accelerated filer o 
+Non-accelerated filer o (Do not check if a smaller reporting company) 
+Smaller reporting company o 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ 
+The aggregate market value of the 65,508,073 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant's common stock on June 28, 2013 , the last business day of the registrant’s most recently completed second fiscal quarter, of $59.98 per share, as reported on the New York Stock Exchange; was $3,929,174,219 . Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes. 
+As of February 12, 2014 , the registrant had 67,056,441 shares of common stock outstanding, which is net of 22,412 treasury shares held by the registrant. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its 2014 annual meeting of stockholders to be filed within 120 days after December 31, 2013 . 
+1 
+TABLE OF CONTENTS 
+ITEM 
+PAGE 
+PART I 
+ITEMS 1. and 2. 
+BUSINESS and PROPERTIES 
+4 
+General 
+4 
+Strategy 
+4 
+Significant Developments in 2013 
+4 
+Outlook for 2014 
+5 
+Core Operational Areas 
+6 
+Reserves 
+8 
+Production 
+12 
+Productive Wells 
+13 
+Drilling and Completion Activity 
+13 
+Acreage 
+14 
+Delivery Commitments 
+15 
+Major Customers 
+15 
+Employees and Office Space 
+15 
+Title to Properties 
+16 
+Seasonality 
+16 
+Competition 
+16 
+Government Regulations 
+17 
+Cautionary Information about Forward-Looking Statements 
+21 
+Available Information 
+23 
+Glossary of Oil and Gas Terms 
+24 
+ITEM 1A. 
+RISK FACTORS 
+29 
+ITEM 1B. 
+UNRESOLVED STAFF COMMENTS 
+52 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+52 
+ITEM 4. 
+MINE SAFETY DISCLOSURES 
+52 
+PART II 
+53 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+53 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+55 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF 
+FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+58 
+Overview of the Company 
+58 
+Financial Results of Operations and Additional Comparative Data 
+66 
+Comparison of Financial Results and Trends between 2013 and 2012 
+69 
+Comparison of Financial Results between 2012 and 2011 
+72 
+Overview of Liquidity and Capital Resources 
+75 
+Critical Accounting Policies and Estimates 
+82 
+Accounting Matters 
+84 
+Environmental 
+85 
+Non-GAAP Financial Measures 
+86 
+2 
+TABLE OF CONTENTS 
+(Continued) 
+ITEM 
+PAGE 
+ITEM 7A. 
+QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT 
+MARKET RISK (included within the content of ITEM 7) 
+87 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+88 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS 
+ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+148 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+148 
+ITEM 9B. 
+OTHER INFORMATION 
+151 
+PART III 
+151 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE 
+GOVERNANCE 
+151 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+151 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL 
+OWNERS AND MANAGEMENT AND RELATED 
+STOCKHOLDER MATTERS 
+151 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, 
+AND DIRECTOR INDEPENDENCE 
+153 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+153 
+PART IV 
+154 
+ITEM 15. 
+EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
+154 
+3 
+PART I 
+When we use the terms “SM Energy,” “the Company,” “we,” “us,” or “our,” we are referring to SM Energy Company and its subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business under Glossary of Oil and Gas Terms. Throughout this document we make statements that may be classified as “forward-looking.” Please refer to the Cautionary Information about Forward-Looking Statements section of this document for an explanation of these types of statements. 
+ITEMS 1. and 2. BUSINESS and PROPERTIES 
+General 
+We are an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout the document) in onshore North America, with a current focus on oil and liquids-rich resource plays. We were founded in 1908 and incorporated in Delaware in 1915. Our initial public offering of common stock was in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.” 
+Our principal offices are located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is (303) 861-8140. 
+Strategy 
+Our business strategy is to focus on the early capture of resource plays in order to create and then enhance value for our stockholders while maintaining a strong balance sheet. We strive to leverage industry-leading acquisition, exploration, and operations teams to quickly acquire and test new resource play concepts at a reasonable cost. Once we have identified potential value through these efforts, our goal is to develop such potential through top-tier operational and project execution, and as appropriate, mitigate our risks by selectively divesting certain assets. We continually examine our portfolio for opportunities to improve the quality of our asset base in order to optimize our returns and preserve our financial strength. 
+At year-end 2012, our reserves shifted from being majority gas to majority liquids. As a result, we now report equivalent volumes and per-unit metrics on a BOE basis rather than on an MCFE basis. Prior year volumes have been conformed to current year presentation. 
+Significant Developments in 2013 
+• 
+Resource Play Delineation and Development Results in Record Production and Record Year-End Proved Reserve Estimates. Our estimated proved reserves increased 46 percent to 428.7 MMBOE at December 31, 2013 , from 293.4 MMBOE at December 31, 2012 . We added 195.5 MMBOE through drilling activities during the year, which was led by our efforts in the Eagle Ford shale in South Texas and the Bakken/Three Forks plays in North Dakota. We also achieved record levels of production in 2013 . Our average daily production was composed of 38.2 MBbl of oil, 409.2 MMcf of gas, and 26.0 MBbl of NGLs for an average equivalent production rate of 132.4 MBOE per day, which was an increase of 33 percent from an average of 99.7 MBOE per day in 2012 . Costs incurred in 2013 for drilling and exploration activities and acquisitions remained essentially flat compared to 2012 at $1.7 billion . Please refer to Core Operational Areas below for additional discussion concerning our 2013 estimated proved reserves, production, and capital investment. 
+4 
+• 
+Divestiture Activity . We continuously look to improve the quality of our asset portfolio through the divestiture of non-strategic properties. Our divestiture activity helps to generate cash that can be used to fund the acquisition or development of assets with higher potential value. During 2013, we sold a total of 18.2 MMBOE of reserves. We received $445.8 million in total cash proceeds at closing (referred throughout this report as “divestiture proceeds”) from these divestitures of non-strategic properties, with the sale of our Anadarko Basin assets in December 2013 being the most significant transaction. 
+• 
+Impairments. We recorded impairment of proved properties expense of $172.6 million for the year ended December 31, 2013 . The impairments in 2013 were a result of negative engineering revisions on Mississippian limestone assets in our Permian region at the end of the year, a plugging and abandonment program of our Olmos interval, dry gas assets in our South Texas & Gulf Coast region, and our decision to no longer pursue the development of certain under-performing assets during the year. 
+Outlook for 2014 
+We enter 2014 with a projected $1.9 billion capital program, approximately $1.7 billion of which we expect to allocate to drilling and completion activities with the remaining being allocated to the construction of facilities, land acquisitions, exploration overhead, and geological and geophysical costs. Our proposed 2014 capital program allocates the majority of drilling and completion capital to oil and liquids-rich programs. Please refer to Core Operational Areas below and Outlook for 2014 under Part II, Item 7 of this report for additional discussion surrounding our capital plans for 2014 . 
+5 
+Core Operational Areas 
+Our operations are concentrated in four onshore operating areas in the United States. The following table summarizes estimated proved reserves, PV-10 reserve value, production, and costs incurred in oil and gas activities for the year ended December 31, 2013 , for our core operating areas: 
+South Texas & Gulf Coast 
+Rocky 
+Mountain 
+Permian 
+Mid- 
+Continent 
+Total (1) 
+Proved Reserves 
+Oil (MMBbl) 
+50.6 
+64.0 
+11.8 
+0.2 
+126.6 
+Gas (Bcf) 
+947.3 
+72.1 
+26.9 
+142.9 
+1,189.3 
+NGLs (MMBbl) 
+102.7 
+— 
+— 
+1.2 
+103.9 
+MMBOE (1) 
+311.2 
+76.0 
+16.3 
+25.2 
+428.7 
+Relative percentage 
+73 
+% 
+18 
+% 
+4 
+% 
+6 
+% 
+100 
+% 
+Proved Developed % 
+42 
+% 
+59 
+% 
+91 
+% 
+78 
+% 
+49 
+% 
+PV-10 Values (in millions) (2) 
+Proved Developed 
+$ 
+1,989.3 
+$ 
+1,306.5 
+$ 
+435.7 
+$ 
+167.1 
+$ 
+3,898.6 
+Proved Undeveloped 
+1,122.6 
+462.7 
+26.9 
+17.7 
+1,629.9 
+Total Proved 
+$ 
+3,111.9 
+$ 
+1,769.2 
+$ 
+462.6 
+$ 
+184.8 
+$ 
+5,528.5 
+Relative percentage 
+56 
+% 
+32 
+% 
+8 
+% 
+3 
+% 
+100 
+% 
+Production 
+Oil (MMBbl) 
+5.2 
+6.4 
+1.8 
+0.5 
+13.9 
+Gas (Bcf) 
+98.5 
+5.8 
+3.6 
+41.4 
+149.3 
+NGLs (MMBbl) 
+9.2 
+— 
+— 
+0.2 
+9.5 
+MMBOE (1) 
+30.9 
+7.4 
+2.4 
+7.7 
+48.3 
+Avg. Daily Equivalents 
+(MBOE/d) 
+84.7 
+20.3 
+6.5 
+21.0 
+132.4 
+Relative percentage 
+64 
+% 
+15 
+% 
+5 
+% 
+16 
+% 
+100 
+% 
+Costs Incurred (in millions) (3) 
+$ 
+849.4 
+$ 
+474.7 
+$ 
+275.7 
+$ 
+91.9 
+$ 
+1,721.1 
+(1) 
+Totals may not sum or recalculate due to rounding. 
+(2) 
+The standardized measure PV-10 calculation is presented in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown in the Reserves section below. 
+(3) 
+Amounts do not sum to total costs incurred due to certain costs relating to our new venture projects being excluded from the regional table above. 
+South Texas & Gulf Coast Region. Operations in our South Texas & Gulf Coast region are managed from our office in Houston, Texas. Our current development activities in this region focus primarily on our Eagle Ford shale program. Our acreage position covers a significant portion of the western Eagle Ford shale play, including acreage in the oil, NGL-rich gas, and dry gas windows of the play. As of December 31, 2013 , we had approximately 189,000 net acres in the play. We operate approximately 145,000 of these net acres, with a working interest of 100 percent. We believe we have secured the requisite services, such as gas pipeline takeaway capacity and drilling and completion services, to support our current operated development plans. 
+We continued to acquire acreage in our new venture play in East Texas in 2013, bringing our total acreage position to approximately 215,000 net acres. The Austin Chalk, Woodbine, and Eagle Ford intervals are present across our acreage. We intend to devote capital in 2014 to test a number of geologic concepts in this new venture play. 
+6 
+Nearly all capital deployed in our South Texas & Gulf Coast region in 2013 targeted our operated Eagle Ford shale program and our exploration program in East Texas. Production in 2013 increased 65 percent from the 18.8 MMBOE produced in 2012 . Estimated proved reserves at year-end 2013 increased 73 percent from 179.9 MMBOE at year-end 2012 . We added approximately 162.6 MMBOE of estimated proved reserves through drilling activities. The increase in production and proved reserves reflects the success we are having in our Eagle Ford shale program and is a result of our ongoing investment and development in this area. Our capital expenditures in our South Texas & Gulf Coast region increased slightly from $848.4 million in 2012 to $849.4 million in 2013. During 2012 and 2013, we were carried for substantially all of our drilling and completion costs in our outside operated Eagle Ford program pursuant to our Acquisition and Development Agreement with Mitsui E&P Texas LP (“Mitsui”), an indirect subsidiary of Mitsui & Co., Ltd. (the “Acquisition and Development Agreement”). We expect the total carry amount to be exhausted in early 2014. Please refer to Note 12 - Acquisition and Development Agreement for additional discussion. 
+Rocky Mountain Region. Operations in our Rocky Mountain region are managed from our office in Billings, Montana. Our development activities in 2013 primarily targeted the Bakken/Three Forks formations in the North Dakota portion of the Williston Basin in our Gooseneck and Raven/Bear Den areas, where we have approximately 79,000 net acres. In 2013 , we focused on infill drilling in these areas to optimize development through pad drilling. 
+We have an emerging resource play in the Powder River Basin. During the second quarter of 2013, we closed an acquisition of approximately 40,000 net acres that is prospective for the Frontier and Shannon formations. We also traded out of the North DJ Basin and received 33,000 net acres in our core area in the Powder River Basin. We now have approximately 140,000 total net acres in the basin. During 2013, several delineation wells were drilled across our acreage position with encouraging results. 
+Capital expenditures in our Rocky Mountain region increased from $406.8 million in 2012 to $474.7 million in 2013 , largely as a result of our Powder River Basin acquisition. Estimated proved reserves for the region at the end of 2013 increased 35 percent from 56.3 MMBOE at year-end 2012 . During the year, we added approximately 25.0 MMBOE of proved reserves in this region through drilling activities. Total regional production for 2013 increased 20 percent from the 6.2 MMBOE produced in 2012 . The increase in production and proved reserves reflects the continued development activity in our Bakken/Three Forks program. 
+Permian Region. Operations in our Permian region are managed from our office in Midland, Texas. Our Permian region covers western Texas and southeastern New Mexico. During 2013, we acquired additional acreage in the Midland Basin, bringing our Permian Basin acreage total to approximately 130,000 net acres. Nearly all of the aforementioned acreage is located in the Midland Basin, which we believe is prospective for various shale targets, including the Wolfcamp shale. In the first half of 2013, we executed a delineation program in our Tredway prospect, which focused on a Mississippian limestone target. As we transitioned to the second half of the year, our focus moved to Wolfcamp drilling on our Sweetie Peck acreage, where we expect higher and more consistent returns. 
+Our capital expenditures in our Permian region increased to $275.7 million in 2013 compared to $232.5 million in 2012 , due to an increase in expenditures on our drilling program. The region’s 2013 production was 2.4 MMBOE, compared to 2012 production of 1.9 MMBOE. Estimated proved reserves at the end of 2013 were 16.3 MMBOE, which was an increase from 2012 year-end proved reserves of 15.8 MMBOE. 
+7 
+Mid-Continent Region. Operations in our Mid-Continent region are managed from our office in Tulsa, Oklahoma. Our Mid-Continent region manages our assets in the Haynesville shale and Woodford shale. Although gas prices improved in 2013, we reduced activity in our Mid-Continent region, which resulted in a decrease in our 2013 capital expenditures and production. In December 2013, we closed the previously announced divestiture of our Anadarko Basin assets, including our interests in the Granite Wash interval, and an additional package of non-operated Cotton Valley assets. The divestiture of these two asset packages resulted in decreased year-end reserves, as further discussed below. 
+In 2013 , we incurred costs of $91.9 million in our Mid-Continent region for exploration, development, and acquisition activities, compared to $168.2 million incurred in 2012 . In 2013 , our Mid-Continent region’s production was 7.7 MMBOE, a decrease from the 9.7 MMBOE produced in 2012 . Estimated proved reserves at the end of 2013 decreased 39 percent from 41.4 MMBOE at the end of 2012 . 
+Reserves 
+The table below presents summary information with respect to the estimates of our proved reserves for each of the years in the three-year period ended December 31, 2013 . We engaged Ryder Scott Company, L.P. (“Ryder Scott”) to audit at least 80 percent of the PV-10 value of our estimated proved reserves in each year presented. The prices used in the calculation of proved reserve estimates as of December 31, 2013 , were $96.94 per Bbl for oil, $3.67 per MMBtu for natural gas, and $40.29 per Bbl for NGLs. 
+Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. The PV-10 values shown in the following table are not intended to represent the current market value of our estimated proved reserves. Neither prices nor costs have been escalated. The actual quantities and present values of our estimated proved reserves may be less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the Securities and Exchange Commission (“SEC”), since the beginning of the last fiscal year. The following table should be read along with the section entitled Risk Factors – Risks Related to Our Business contained herein. 
+Our ability to replace our production is critical to us. Please refer to the reserve replacement terms in the Glossary of Oil and Gas Terms section of this report for information describing how our reserve replacement metrics are calculated. Our reserve replacement percentages are calculated using information from the Oil and Gas Reserve Quantities section of Supplemental Oil and Gas Information located in Part II, Item 8 of this report. 
+8 
+We believe the concept of reserve replacement as described in the Glossary of Oil and Gas Terms section of this report, as well as permutations that may include other captions of the Oil and Gas Reserve Quantities section of Supplemental Oil and Gas Information located in Part II, Item 8 of this report, are widely understood by those who make investment decisions related to the oil and gas exploration and production business. 
+As of December 31, 
+2013 
+2012 
+2011 
+Reserve data: 
+Proved developed 
+Oil (MMBbl) 
+70.2 
+58.8 
+50.3 
+Gas (Bcf) 
+569.2 
+483.2 
+451.2 
+NGLs (MMBbl) 
+43.8 
+27.2 
+15.2 
+MMBOE (1) 
+208.9 
+166.5 
+140.7 
+Proved undeveloped 
+Oil (MMBbl) 
+56.3 
+33.5 
+21.4 
+Gas (Bcf) 
+620.1 
+350.2 
+212.8 
+NGLs (MMBbl) 
+60.2 
+35.1 
+12.3 
+MMBOE (1) 
+219.9 
+126.9 
+69.2 
+Total Proved (1) 
+Oil (MMBbl) (1) 
+126.6 
+92.2 
+71.7 
+Gas (Bcf) (1) 
+1,189.3 
+833.4 
+664.0 
+NGLs (MMBbl) (1) 
+103.9 
+62.3 
+27.5 
+MMBOE (1) 
+428.7 
+293.4 
+209.9 
+Proved developed reserves % 
+49 
+% 
+57 
+% 
+67 
+% 
+Proved undeveloped reserves % 
+51 
+% 
+43 
+% 
+33 
+% 
+Reserve value data (in millions): 
+Proved developed PV-10 
+$ 
+3,898.6 
+$ 
+2,982.6 
+$ 
+2,836.3 
+Proved undeveloped PV-10 
+1,629.9 
+866.5 
+624.9 
+Total proved PV-10 
+$ 
+5,528.5 
+$ 
+3,849.1 
+$ 
+3,461.2 
+Standardized measure of discounted future cash flows 
+$ 
+4,009.4 
+$ 
+3,021.0 
+$ 
+2,580.0 
+Reserve replacement – drilling, excluding revisions 
+405 
+% 
+411 
+% 
+310 
+% 
+All in – including sales of reserves 
+380 
+% 
+329 
+% 
+262 
+% 
+All in – excluding sales of reserves 
+418 
+% 
+337 
+% 
+317 
+% 
+Reserve life (years) 
+8.9 
+8.0 
+7.4 
+(1) Totals may not sum or recalculate due to rounding. 
+9 
+The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 value (Non-GAAP) of total proved reserves. The PV-10 value measure excludes the impact of income taxes. Please see the definitions of standardized measure of discounted future net cash flows and PV-10 value in the Glossary of Oil and Gas Terms . 
+As of December 31, 
+2013 
+2012 
+2011 
+(in millions) 
+Standardized measure of discounted future net cash flows 
+$ 
+4,009.4 
+$ 
+3,021.0 
+$ 
+2,580.0 
+Add: 10 percent annual discount, net of income taxes 
+2,500.6 
+1,742.1 
+1,727.6 
+Add: future undiscounted income taxes 
+2,722.2 
+1,609.4 
+1,740.4 
+Undiscounted future net cash flows 
+9,232.2 
+6,372.5 
+6,048.0 
+Less: 10 percent annual discount without tax effect 
+(3,703.7 
+) 
+(2,523.4 
+) 
+(2,586.8 
+) 
+PV-10 value 
+$ 
+5,528.5 
+$ 
+3,849.1 
+$ 
+3,461.2 
+Proved Undeveloped Reserves 
+Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period. As of December 31, 2013 , we had no undrilled proved undeveloped reserves that had been on our books in excess of five years. 
+For locations that are more than one location removed from producing developed locations, we utilized reliable geologic and engineering technology to add approximately 40.4 MMBOE of proved undeveloped reserves in the more developed portions of our Eagle Ford shale position and 0.9 MMBOE of proved undeveloped reserves in the more developed portions of our Bakken shale position. We incorporated public and proprietary data from multiple sources to establish geologic continuity of each formation and their producing properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (both vertically and horizontally collected), and petrophysical analysis of the log data, mud logs, gas sample analysis, measurements of total organic content, thermal maturity, test production, fluid properties, and core data as well as significant statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas where both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonably certain results. In all other areas, we restricted proved undeveloped locations to immediate offsets to producing wells. 
+As of December 31, 2013 , we had 219.9 MMBOE of proved undeveloped reserves, which is an increase of 93.0 MMBOE, or 73 percent , over proved undeveloped reserves of 126.9 MMBOE at December 31, 2012 . We added 151.6 MMBOE of proved undeveloped reserves through our drilling program, 105.2 MMBOE of which were extensions and discoveries, primarily in our Eagle Ford shale play, as well as an additional 46.4 MMBOE of infill proved undeveloped reserves primarily in our assets in the Bakken/Three Forks and Eagle Ford shale plays. A negative price revision of 1.7 MMBOE was primarily due to slightly lower reserves in our Eagle Ford shale assets in our South Texas & Gulf Coast region as a result of our election to reject ethane as allowed under our contracts. We realize higher overall net value by rejecting ethane. We had a positive performance revision of 2.9 MMBOE primarily related to improved performance in our operated Eagle Ford shale assets. We removed 2.8 MMBOE of proved undeveloped reserves from our books as a result of the SEC’s five-year limitation on the number of years 
+10 
+that proved undeveloped reserves may be booked without being developed. During the year, we sold a total of 1.0 MMBOE proved undeveloped reserves in our Mid-Continent and Rocky Mountain regions. During 2013 , we converted 56.0 MMBOE of proved undeveloped reserves to proved developed reserves, primarily in our Eagle Ford shale and Bakken/Three Forks plays. During 2013, a total of $562.9 million was spent on projects associated with reserves that were carried as proved undeveloped reserves at the end of 2012. Please refer to Note 12 - Acquisition and Development Agreement for discussion of the carry of certain drilling and completion costs in our outside operated Eagle Ford program. As of December 31, 2013 , estimated future development costs relating to our proved undeveloped reserves were approximately $1.2 billion, $980 million, and $355 million in 2014, 2015, and 2016, respectively. 
+Internal Controls Over Proved Reserves Estimates 
+Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with the SEC’s regulations. Our process for managing and monitoring our proved reserves is delegated to our reservoir engineering group, which is managed by Dennis A. Zubieta, our Vice President - Engineering, Evaluation and A&D, subject to the oversight of our management and the Audit Committee of our Board of Directors, as discussed below. Mr. Zubieta joined us in June 2000 as a Corporate Acquisition & Divestiture Engineer, assumed the role of Reservoir Engineer in February 2003, was appointed Reservoir Engineering Manager in August 2005, was appointed Vice President - Engineering and Evaluation in August 2008, and was appointed Vice President - Engineering, Evaluation and A&D in October 2012. Mr. Zubieta was employed by Burlington Resources Oil and Gas Company from June 1988 to May 2000 in various operations and reservoir engineering capacities. Mr. Zubieta received a Bachelor of Science degree in Petroleum Engineering from Montana Tech of The University of Montana in May 1988. Technical reviews are performed throughout the year by regional staff who evaluate geological and engineering data. This data, in conjunction with economic data and our ownership information, is used in making a determination of estimated proved reserve quantities. Our regional engineering technical staff do not report directly to Mr. Zubieta; they report to either their respective regional technical managers or directly to the regional manager. This is intended to promote objective and independent analysis within our regions in the proved reserves estimation process. 
+Third-party Reserves Audit 
+Ryder Scott performed an independent audit using its own engineering assumptions but with economic and ownership data we provided. Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve PV-10 value. In the aggregate, the proved reserve values of our audited properties determined by Ryder Scott are required to be within 10 percent of our proved reserve valuations for the total company, as well as for each respective region. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world for over seventy years. The technical person at Ryder Scott primarily responsible for overseeing our reserves audit is an Advising Senior Vice President who received a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Engineers, and the Society of Petroleum Evaluation Engineers. The Ryder Scott 2013 report concerning our reserves is included as Exhibit 99.1. 
+In addition to a third party audit, our reserves are reviewed by management with the Audit Committee of our Board of Directors. Management, which includes our Chief Executive Officer, President and Chief Operating Officer, Executive Vice President and Chief Financial Officer, and Senior Vice President - Portfolio Development and Technical Services, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate in conjunction with Ryder Scott’s results and also meets with Ryder Scott representatives from time to time to discuss processes and findings. 
+11 
+Production 
+The following table summarizes the volumes and realized prices of oil, gas, and NGLs produced and sold from properties in which we held an interest during the periods indicated. Realized prices presented below exclude the effects of derivative contract settlements. Also presented is a summary of related production costs per BOE. 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+Net production 
+Oil (MMBbl) 
+13.9 
+10.4 
+8.1 
+Gas (Bcf) 
+149.3 
+120.0 
+100.3 
+NGLs (MMBbl) 
+9.5 
+6.1 
+3.5 
+MMBOE (2) 
+48.3 
+36.5 
+28.3 
+Eagle Ford net production (1) 
+Oil (MMBbl) 
+5.1 
+3.1 
+2.5 
+Gas (Bcf) 
+97.1 
+58.1 
+32.9 
+NGLs (MMBbl) 
+9.2 
+5.7 
+3.1 
+MMBOE (2) 
+30.5 
+18.5 
+11.1 
+Average net daily production 
+Oil (MBbl per day) 
+38.2 
+28.3 
+22.1 
+Gas (MMcf per day) 
+409.2 
+328.0 
+274.8 
+NGLs (MBbl per day) 
+26.0 
+16.7 
+9.6 
+MBOE per day (2) 
+132.4 
+99.7 
+77.5 
+Eagle Ford average net daily production (1) 
+Oil (MBbl per day) 
+14.1 
+8.6 
+6.8 
+Gas (MMcf per day) 
+265.9 
+158.8 
+90.1 
+NGLs (MBbl per day) 
+25.2 
+15.5 
+8.6 
+MBOE per day (2) 
+83.6 
+50.5 
+30.4 
+Realized price 
+Oil (per Bbl) 
+$ 
+91.19 
+$ 
+85.45 
+$ 
+88.23 
+Gas (per Mcf) 
+$ 
+3.93 
+$ 
+2.98 
+$ 
+4.32 
+NGLs (per Bbl) 
+$ 
+35.95 
+$ 
+37.61 
+$ 
+53.32 
+Per BOE 
+$ 
+45.50 
+$ 
+40.39 
+$ 
+47.10 
+Production costs per BOE 
+Lease operating expense 
+$ 
+4.82 
+$ 
+4.93 
+$ 
+5.30 
+Transportation costs 
+$ 
+5.34 
+$ 
+3.81 
+$ 
+3.05 
+Production taxes 
+$ 
+2.19 
+$ 
+2.00 
+$ 
+1.90 
+(1) In each of the years 2013 , 2012 , and 2011 , total estimated proved reserves attributed to our Eagle Ford shale properties exceeded 15 percent of our total proved reserves expressed on an equivalent basis. 
+(2) Amounts may not recalculate due to rounding. 
+12 
+Productive Wells 
+As of December 31, 2013 , we had working interests in 1,061 gross (634 net) productive oil wells and 2,293 gross (916 net) productive gas wells. Productive wells are either wells producing in commercial quantities or wells mechanically capable of commercial production, but are currently shut-in. Multiple completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil produced when it first commenced production; such designation may not be indicative of current production. 
+Drilling and Completion Activity 
+All of our drilling and completion activities are conducted using independent contractors. We do not own any drilling or completion equipment. The following table summarizes the number of operated and non-operated wells drilled and completed or recompleted on our properties in 2013 , 2012 , and 2011 , excluding non-consented projects, active injector wells, salt water disposal wells, and any wells in which we own only a royalty interest: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development wells: 
+Oil 
+154 
+75.4 
+127 
+47.2 
+125 
+32.1 
+Gas 
+443 
+162.5 
+337 
+124.5 
+273 
+81.0 
+Non-productive 
+10 
+8.5 
+10 
+6.3 
+11 
+4.0 
+607 
+246.4 
+474 
+178.0 
+409 
+117.1 
+Exploratory wells: 
+Oil 
+6 
+5.1 
+9 
+6.9 
+16 
+6.3 
+Gas 
+4 
+2.4 
+8 
+6.8 
+48 
+8.6 
+Non-productive 
+1 
+0.3 
+8 
+6.8 
+3 
+1.0 
+11 
+7.8 
+25 
+20.5 
+67 
+15.9 
+Total 
+618 
+254.2 
+499 
+198.5 
+476 
+133.0 
+A productive well is an exploratory, development, or extension well that is producing or capable of commercial production of oil, gas, and/or NGLs. A non-productive well, frequently referred to within the industry as a dry hole, is an exploratory, development, or extension well that proves to be incapable of producing oil, gas, and/or NGLs in commercial quantities. 
+As defined by the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive and is part of a development project, which is defined as the means by which petroleum resources are brought to economically producible status. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of equipment for production of oil, gas, and/or NGLs, or in the case of a dry well, the reporting to the appropriate authority that the well has been plugged and abandoned. 
+13 
+In addition to the wells drilled and completed in 2013 (included in the table above), as of February 12, 2014 , we were participating in the drilling of 34 gross wells. We operate 18 of these wells on a gross basis (15 on a net basis) and other companies operate the remaining 16 gross wells (three on a net basis). With respect to completion activity, at such date, there were 284 gross wells in which we have an interest that were being completed. We operate 35 of these completion activities on a gross basis (31 on a net basis), and were participating in 249 gross (45 net) non-operated completion activities. Substantially all of these operations relate to the drilling and completion of wells during the primary term of the respective oil and gas lease or leases. 
+Acreage 
+The following table sets forth the gross and net acres of developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held by us as of December 31, 2013 . Undeveloped acreage includes leasehold interests that contain proved undeveloped reserves. 
+Developed Acres (1) 
+Undeveloped Acres (2) 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Louisiana 
+51,093 
+19,212 
+32,559 
+30,081 
+83,652 
+49,293 
+Montana 
+56,214 
+38,050 
+278,481 
+191,583 
+334,695 
+229,633 
+Nevada 
+— 
+— 
+197,634 
+197,634 
+197,634 
+197,634 
+North Dakota 
+155,150 
+107,170 
+68,960 
+37,049 
+224,110 
+144,219 
+Oklahoma 
+45,550 
+26,034 
+47,655 
+22,932 
+93,205 
+48,966 
+Texas 
+270,403 
+156,579 
+724,997 
+432,246 
+995,400 
+588,825 
+Wyoming 
+49,604 
+23,695 
+329,663 
+244,701 
+379,267 
+268,396 
+Other (3) 
+4,872 
+2,451 
+55,736 
+40,955 
+60,608 
+43,406 
+632,886 
+373,191 
+1,735,685 
+1,197,181 
+2,368,571 
+1,570,372 
+Louisiana Fee Properties 
+10,499 
+10,499 
+14,415 
+14,415 
+24,914 
+24,914 
+Louisiana Mineral Servitudes 
+7,426 
+4,217 
+4,528 
+4,166 
+11,954 
+8,383 
+17,925 
+14,716 
+18,943 
+18,581 
+36,868 
+33,297 
+Total (4) 
+650,811 
+387,907 
+1,754,628 
+1,215,762 
+2,405,439 
+1,603,669 
+(1) 
+Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation in each respective state. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but has been included only as developed acreage in the presentation above. 
+(2) 
+Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves. 
+(3) 
+Includes interests in Arkansas, Colorado, Kansas, Illinois, Mississippi, Nebraska, New Mexico, Pennsylvania, and Utah. 
+(4) 
+As of the filing date of this report, we had 72,858, 174,694, and 170,314 net acres scheduled to expire by December 31, 2014 , 2015 , and 2016 , respectively, if production is not established or we take no other action to extend the terms of the applicable lease or leases. 
+14 
+Delivery Commitments 
+As of December 31, 2013 , we had gathering, processing, and transportation through-put commitments with various parties that require us to deliver fixed, determinable quantities of production over specified time frames. We have an aggregate minimum commitment to deliver 1,807 Bcf of natural gas and 53 MMBbl of oil. These contracts expire at various dates through 2023. We are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. If a shortfall in the minimum volume commitment for natural gas is projected, we have rights under certain contracts to arrange for third party gas to be delivered, and such volume will count toward our minimum volume commitment. Our current production is insufficient to offset these aggregate contractual liabilities, but we expect to fulfill the delivery commitments with production from the future development of our proved undeveloped reserves and from the future development of resources not yet characterized as proved reserves or through arranging for the delivery of third party gas. Therefore, we currently do not expect any significant shortfalls. 
+Major Customers 
+During 2013 , we had three major customers, Regency Gas Services LLC , Anadarko Petroleum Corporation (“Anadarko”), and Plains Marketing LP , which accounted for approximately 26 percent , 16 percent , and 12 percent , respectively, of our total production revenue. During the third quarter of 2013, we entered into various marketing agreements with Anadarko, whereby we are subject to certain gathering, transportation, and processing through-put commitments for up to 10 years pursuant to each contract. While Anadarko is the first purchaser under these contracts, we also share with Anadarko the risk of non-performance by Anadarko’s counterparty purchasers. Several of Anadarko’s counterparty purchasers under these contracts are also direct purchasers of products produced by us. 
+During 2012 , we had two major customers, Regency Gas Services LLC and Plains Marketing LP , which accounted for approximately 21 percent and 13 percent , respectively, of our total production revenue. During 2011 , we had one major customer, Regency Gas Services LLC , which accounted for approximately 18 percent of our total production revenue. 
+Employees and Office Space 
+As of February 12, 2014 , we had 793 full-time employees. None of our employees are subject to a collective bargaining agreement, and we consider our relations with our employees to be good. 
+The following table summarizes the approximate square footage of office space leased or owned by us, as of December 31, 2013 : 
+Location 
+Approximate Square Footage 
+Leased Office Space: 
+Denver, CO 
+95,000 
+Houston, TX 
+62,000 
+Tulsa, OK 
+56,000 
+Midland, TX 
+22,000 
+Billings, MT 
+44,000 
+Williston & Watford City, ND 
+7,000 
+Casper, WY 
+4,000 
+Huntsville, TX 
+3,000 
+Total Leased Office Space 
+293,000 
+15 
+In addition to the leased office space in the table above, we own a total of 24,000 square feet of office space across all four of our operating regions. 
+Title to Properties 
+Substantially all of our interests are held pursuant to oil and gas leases from third parties. A title opinion is usually obtained prior to the commencement of initial drilling operations. We have obtained title opinions or have conducted other title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. Most of our producing properties are subject to mortgages securing indebtedness under our credit facility, royalty and overriding royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere with the use of, or affect the value of, such properties. We typically perform only minimal title investigation before acquiring undeveloped leasehold acreage. 
+Seasonality 
+Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. The impact of seasonality on oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of worldwide production capacity in excess of existing worldwide demand for oil. Certain of our drilling, completion, and other operations are also subject to seasonal limitations. Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. See Risk Factors - Risks Related to Our Business for additional discussion. 
+Competition 
+The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We believe our leasehold position provides a foundation for development activities that we expect to fuel our future growth. Our competitive position also depends on our geological, geophysical, and engineering expertise, as well as our financial resources. We believe the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams enable us to compete in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies, which in some cases have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have gathering, processing or refining operations, market refined products, own drilling rigs or other equipment, or generate electricity. 
+We also compete with other oil and gas companies in securing drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells. Consequently, we may face shortages, delays or increased costs in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may be affected by future energy, climate-related, financial, and/or other policies, legislation, and regulations. 
+In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals. Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the availability of individuals with these skills is becoming more limited due to the evolving demographics of our industry. We are not insulated from the competition for quality people, and we must compete effectively in order to be successful. 
+16 
+Government Regulations 
+Our business is extensively controlled by numerous federal, state, and local laws and governmental regulations. These laws and regulations may be changed from time to time in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations have the potential of increasing our cost of doing business and consequently could affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry. 
+Energy Regulations. Many of the states in which we conduct our operations have adopted laws and regulations governing the exploration for and production of oil, gas, and NGLs, including laws and regulations that require permits for the drilling of wells, impose bonding requirements in order to drill or operate wells, and govern the timing of drilling and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to various state conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the unitization or pooling of oil and gas properties. In addition, state conservation laws sometimes establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. 
+Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of Land Management (“BLM”). These leases contain relatively standardized terms and require compliance with detailed regulations and orders that are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and must comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may suspend or terminate our operations on federal leases. 
+In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes have increased the amount of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM. 
+Our sales of natural gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce. FERC’s current regulatory framework generally provides for a competitive and open access market for sales and transportation of natural gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for natural gas production. 
+17 
+Environmental, Health and Safety Matters 
+General. Our operations are subject to stringent and complex federal, state, tribal and local laws and regulations governing protection of the environment and worker health and safety as well as the discharge of materials into the environment. These laws and regulations may, among other things: 
+• 
+require the acquisition of various permits before drilling commences; 
+• 
+restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities; 
+• 
+limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and 
+• 
+require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells. 
+These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes may result in more stringent permitting, waste handling, disposal and cleanup requirements for the oil and natural gas industry and could have a significant impact on our operating costs. 
+The following is a summary of some of the existing laws, rules and regulations to which our business is subject. 
+Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. 
+Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+18 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, pay fines, remediate contaminated property, or perform remedial operations to prevent future contamination. 
+Water discharges. The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, U.S. Army Corps of Engineers or analogous state agencies. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. 
+The Oil Pollution Act of 1990 (“OPA”) addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil liability. 
+Air emissions. The federal Clean Air Act (“CAA”), and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. 
+Climate change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change could have an adverse effect on our operations and the demand for oil and gas. See Risk Factors - Risks Related to Our Business - Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for crude oil, natural gas and NGLs . In addition to the effects of regulation, the meteorological effects of global climate change could pose additional risks to our operations, including physical damage risks associated with more frequent, more intensive storms and flooding, and could adversely affect the demand for our products. 
+Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on these species. It is also possible that a federal or state agency could order a complete halt to activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling, completion and production 
+19 
+activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas. 
+National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay development of some of our oil and natural gas projects. 
+OSHA and other laws and regulation. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe that we are in substantial compliance with the applicable requirements of OSHA and comparable laws. 
+Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in most of our drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s (the “SDWA”) Underground Injection Control Program. The federal SDWA protects the quality of the nation’s public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids, including saltwater disposal fluids, into below-ground formations that may adversely affect drinking water sources. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas activities using hydraulic fracturing techniques, which could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and delays, all of which could adversely affect our financial position, results of operations and cash flows. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, which could result in additional permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. 
+We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. While we believe that we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot give any assurance that we will not be adversely affected in the future. 
+Environmental, Health and Safety Initiatives. We are committed to conducting our business in a manner that protects the environment and the health and safety of our employees, contractors and the public. We set annual goals for our environmental, health and safety program focused on reducing the number of safety related incidents that occur and the number and impact of spills of produced fluids. We also periodically conduct regulatory compliance audits of our operations to ensure our compliance with all regulations and provide appropriate training 
+20 
+for our employees. Reducing air emissions as a result of leaks, venting or flaring of natural gas during operations has become a major focus area for regulatory efforts and for our compliance efforts. While flaring is sometimes necessary, releases of natural gas to the environment and flaring is an economic waste and reducing these volumes is a priority for us. To avoid flaring where possible, we restrict testing periods and make every effort to ensure that our production is connected to gas pipeline infrastructure as quickly as possible after well completions. During this last year, we also cooperated with other producers in North Dakota in the ongoing development of recommendations to reduce the amount of flaring that is occurring there as a result of area wide infrastructure limitations that are beyond our control. Another focus for our environmental effort has been reduction of water use through recycling of flowback water in South Texas for use as frac fluid. We have incurred in the past, and expect to incur in the future, capital costs related to environmental compliance. Such expenditures are included within our overall capital budget and are not separately itemized. 
+Cautionary Information about Forward-Looking Statements 
+This Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear in a number of places in this Form 10-K, and include statements about such matters as: 
+• 
+the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures; 
+• 
+the drilling of wells and other exploration and development activities and plans, as well as possible future acquisitions; 
+• 
+the possible divestiture or farm-down of, or joint venture relating to, certain properties; 
+• 
+proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those proved reserve estimates; 
+• 
+future oil, gas, and NGL production estimates; 
+• 
+our outlook on future oil, gas, and NGL prices, well costs, and service costs; 
+• 
+cash flows, anticipated liquidity, and the future repayment of debt; 
+• 
+business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and 
+• 
+other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in Item 7 of this report. 
+Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different 
+21 
+from any future results or performance expressed or implied by the forward-looking statements. Some of these risks are described in the Risk Factors section of this Form 10-K, and include such factors as: 
+• 
+the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves; 
+• 
+weakness in economic conditions and uncertainty in financial markets; 
+• 
+our ability to replace reserves in order to sustain production; 
+• 
+our ability to raise the substantial amount of capital that is required to develop and/or replace our reserves; 
+• 
+our ability to compete against competitors that have greater financial, technical, and human resources; 
+• 
+our ability to attract and retain key personnel; 
+• 
+the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves; 
+• 
+the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities; 
+• 
+the possibility that exploration and development drilling may not result in commercially producible reserves; 
+• 
+our limited control over activities on outside operated properties; 
+• 
+our reliance on the skill and expertise of third-party service providers on our operated properties; 
+• 
+the possibility that title to properties in which we have an interest may be defective; 
+• 
+the possibility that our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production; 
+• 
+the uncertainties associated with divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate; 
+• 
+the uncertainties associated with enhanced recovery methods; 
+• 
+our commodity derivative contracts may result in financial losses or may limit the prices that we receive for oil, gas, and NGL sales; 
+• 
+the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations; 
+• 
+our ability to deliver necessary quantities of natural gas or crude oil to contractual counterparties; 
+• 
+price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values; 
+• 
+the impact that lower oil, gas, or NGL prices could have on the amount we are able to borrow under our credit facility; 
+22 
+• 
+the possibility that our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt; 
+• 
+the possibility that covenants in our debt agreements may limit our discretion in the operation of our business, prohibit us from engaging in beneficial transactions or lead to the accelerated payment of our debt; 
+• 
+operating and environmental risks and hazards that could result in substantial losses; 
+• 
+the impact of seasonal weather conditions and lease stipulations on our ability to conduct drilling activities; 
+• 
+our ability to acquire adequate supplies of water and dispose of or recycle water we use at a reasonable cost in accordance with environmental and other applicable rules; 
+• 
+complex laws and regulations, including environmental regulations, that result in substantial costs and other risks; 
+• 
+the availability and capacity of gathering, transportation, processing, and/or refining facilities; 
+• 
+our ability to sell and/or receive market prices for our oil, gas, and NGLs; 
+• 
+new technologies may cause our current exploration and drilling methods to become obsolete; 
+• 
+the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and 
+• 
+litigation, environmental matters, the potential impact of legislation and government regulations, and the use of management estimates regarding such matters. 
+We caution you that forward-looking statements are not guarantees of future performance and that actual results or performance may be materially different from those expressed or implied in the forward-looking statements. The forward-looking statements in this report speak as of the filing date of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws. 
+Available Information 
+Our internet website address is www.sm-energy.com. We routinely post important information for investors on our website. Within our website’s investor relations section, we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. We also make available through our website’s corporate governance section our Corporate Governance Guidelines, Code of Business Conduct and Conflict of Interest Policy, Financial Code of Ethics, and the Charters of the Audit, Compensation, Executive, and Nominating and Corporate Governance Committees of our Board of Directors. Information on our website is not incorporated by reference into this report and should not be considered part of this document. 
+23 
+Glossary of Oil and Gas Terms 
+The oil and gas terms defined in this section are used throughout this report. The definitions of the terms developed reserves, exploratory well, field, proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under SEC Rule 4-10(a) of Regulation S-X, as amended effective for fiscal years ending after December 31, 2009. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located through the SEC’s website at www.sec.gov. 
+Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons. 
+Bcf . Billion cubic feet, used in reference to natural gas. 
+BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs. 
+BTU. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit. 
+Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production. 
+Developed reserves. Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. 
+Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+Dry hole. A well found to be incapable of producing either oil, natural gas, and/or NGLs in commercial quantities. 
+Exploratory well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir beyond its known horizon. 
+Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil and natural gas) rights. 
+Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition. 
+Finding and development cost. Expressed in dollars per BOE. Finding and development cost metrics provide information as to the cost of adding proved reserves from various activities, and are widely utilized within the exploration and production industry, as well as by investors and analysts. The information used to calculate these metrics is included in the Supplemental Oil and Gas Information section in Part II, Item 8 of this report. It should be noted that finding and development cost metrics have limitations. For example, exploration efforts related to a particular set of proved reserve additions may extend over several years. As a result, the exploration costs incurred in earlier periods are not included in the amount of exploration costs incurred during the period in which that set of proved reserves is added. In addition, consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred. Since the additional development costs that will need to be incurred in the future before the proved undeveloped reserves are ultimately produced are not included in the amount of costs incurred during the period in which those reserves were added, those development costs in future 
+24 
+periods will be reflected in the costs associated with adding a different set of reserves. The calculations of various finding and development cost metrics are explained below. 
+Finding and development cost – Drilling, excluding revisions. Calculated by dividing the amount of costs incurred for development and exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, and infill drilling, during the same period. 
+Finding and development cost – Drilling, including revisions. Calculated by dividing the amount of costs incurred for development and exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, and revisions of previous estimates, during the same period. 
+Finding and development cost – Drilling and acquisitions, excluding revisions. Calculated by dividing the amount of costs incurred for development, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, and acquisitions, during the same period. 
+Finding and development cost – Drilling and acquisitions, including revisions. Calculated by dividing the amount of costs incurred for development, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates, during the same period. 
+Finding and development cost –All in, including sales of reserves. Calculated by dividing the amount of total capital expenditures for oil and natural gas activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates less sales of reserves, during the same period. 
+Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions. 
+Frac spread. Hydraulic fracturing requires custom-designed and purpose-built equipment. A “spread” is the equipment necessary to carry out a fracturing job. 
+Gross acre. An acre in which a working interest is owned. 
+Gross well. A well in which a working interest is owned. 
+Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical. 
+Lease operating expenses. The expenses incurred in the lifting of crude oil, natural gas, and/or associated liquids from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs. 
+MBbl. One thousand barrels of crude oil or other liquid hydrocarbons. 
+MBOE. One thousand barrels of oil equivalent. 
+Mcf. One thousand cubic feet, used in reference to natural gas. 
+MCFE. Million cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs. 
+MMBbl. One million barrels of oil or other liquid hydrocarbons. 
+MMBOE. One million barrels of oil equivalent. 
+25 
+MMBtu. One million British thermal units. 
+MMcf. One million cubic feet, used in reference to natural gas. 
+Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells. 
+Net asset value per share. The result of the fair market value of total assets less total liabilities, divided by the total number of outstanding shares of common stock. 
+NGLs. The combination of ethane, propane, butane, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature. 
+NYMEX WTI. New York Mercantile Exchange West Texas Intermediate, a common industry benchmark price for crude oil. 
+OPIS . Oil Price Information Service Mont Belvieu, a common industry benchmark for NGL pricing. 
+PV-10 value (Non-GAAP). The present value of estimated future revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period. This is a non-GAAP measure. 
+Productive well. A well that is producing crude oil, natural gas, and/or NGLs or that is capable of commercial production of those products. 
+Proved reserves. Those quantities of oil, gas, and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 
+Recompletion. The completion of an existing wellbore in a formation other than that in which the well has previously been completed. 
+Reserve life. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period. 
+26 
+Reserve replacement. Reserve replacement metrics are used as indicators of a company’s ability to replenish annual production volumes and grow its reserves, and provide information related to how successful a company is at growing its proved reserve base. These are believed to be useful non-GAAP measures that are widely utilized within the exploration and production industry, as well as by investors and analysts. They are easily calculable metrics, and the information used to calculate these metrics is included in the Supplemental Oil and Gas Information section of Part II, Item 8 of this report. It should be noted that reserve replacement metrics have limitations. They are limited because they typically vary widely based on the extent and timing of new discoveries and property acquisitions. Their predictive and comparative value is also limited for the same reasons. In addition, because the metrics do not embed the cost or timing of future production of new reserves, they cannot be used as a measure of value creation. The calculations of various reserve replacement metrics are explained below. 
+Reserve replacement – Drilling, excluding revisions. Calculated as a numerator comprised of the sum of reserve extensions and discoveries and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling activity. 
+Reserve replacement – Drilling, including revisions. Calculated as a numerator comprised of the sum of reserve extensions, discoveries, infill reserves, and revisions of previous estimates in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling activity with an adjustment for revisions. 
+Reserve replacement – Drilling and acquisitions, excluding revisions. Calculated as a numerator comprised of the sum of reserve acquisitions and reserve extensions, discoveries, and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities. 
+Reserve replacement – Drilling and acquisitions, including revisions. Calculated as a numerator comprised of the sum of reserve acquisitions and reserve extensions, discoveries, infill reserves, and revisions of previous estimates in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities with an adjustment for revisions. 
+Reserve replacement percentage – All in, excluding sales of reserves. The sum of reserve extensions and discoveries, infill drilling, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period. 
+Reserve replacement percentage –All in, including sales of reserves. The sum of sales of reserves, infill drilling, reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period. 
+Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude oil, natural gas, and/or associated liquid resources that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 
+Resource play. A term used to describe an accumulation of crude oil, natural gas, and/or associated liquid resources known to exist over a large areal expanse, which when compared to a conventional play typically has lower expected geological risk. 
+Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil, natural gas, and NGLs produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well. 
+27 
+Royalty interest. An interest in an oil and natural gas property entitling the owner to shares of crude oil, natural gas, and NGL production free of costs of exploration, development, and production operations. 
+Seismic. The sending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape, and depth of subsurface rock formations. 
+Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock. 
+Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a 10 percent annual discount rate. The information for this calculation is included in the supplemental information regarding disclosures about oil and gas producing activities following the Notes to Consolidated Financial Statements included in this report. 
+Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, natural gas, and associated liquids regardless of whether such acreage contains estimated net proved reserves. 
+Undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The applicable SEC definition of undeveloped reserves provides that undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. 
+Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share in the production, sales, and costs. 
+28 
+ITEM 1A. RISK FACTORS 
+In addition to the other information included in this report, the following risk factors should be carefully considered when evaluating an investment in us. 
+Risks Related to Our Business 
+Crude oil, natural gas, and NGL prices are volatile, and declines in prices adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow. 
+Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and natural gas properties depend heavily on the prices we receive for crude oil, natural gas and NGL sales. Crude oil, natural gas, and NGL prices also affect our cash flows available for capital expenditures and other items, our borrowing capacity, and the amount and value of our crude oil, natural gas, and NGL reserves. For example, the amount of our borrowing base under our credit facility is subject to periodic redeterminations based on crude oil, natural gas, and NGL prices specified by our bank group at the time of redetermination. In addition, we may have crude oil and natural gas property impairments or downward revisions of estimates of proved reserves if prices fall significantly. 
+Historically, the markets for crude oil, natural gas, and NGLs have been volatile, and they are likely to continue to be volatile. Wide fluctuations in crude oil, natural gas, and NGL prices may result from relatively minor changes in the supply of and demand for crude oil, natural gas, and NGLs, market uncertainty, and other factors that are beyond our control, including: 
+• 
+global and domestic supplies of crude oil, natural gas, and NGLs, and the productive capacity of the industry as a whole; 
+• 
+the level of consumer demand for crude oil, natural gas, and NGLs; 
+• 
+overall global and domestic economic conditions; 
+• 
+weather conditions; 
+• 
+the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas that may affect the realized price for crude oil, natural gas, or NGLs; 
+• 
+liquefied natural gas deliveries to and from the United States; 
+• 
+the price and level of imports and exports of crude oil, refined petroleum products, and liquefied natural gas; 
+• 
+the price and availability of alternative fuels; 
+• 
+technological advances and regulations affecting energy consumption and conservation; 
+• 
+the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to agree to and maintain crude oil price and production controls; 
+• 
+political instability or armed conflict in crude oil or natural gas producing regions; 
+• 
+strengthening and weakening of the United States dollar relative to other currencies; and 
+• 
+governmental regulations and taxes. 
+29 
+These factors and the volatility of crude oil, natural gas, and NGL markets make it extremely difficult to predict future crude oil, natural gas, and NGL price movements with any certainty. Declines in crude oil, natural gas, and NGL prices would reduce our revenues and could also reduce the amount of crude oil, natural gas, and NGLs that we can produce economically, which could have a materially adverse effect on us. 
+Weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict. 
+In recent years, the United States and global economies and financial systems have experienced turmoil and upheaval characterized by extreme volatility in prices of equity and debt securities, periods of diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, increased levels of unemployment, and an unprecedented level of intervention by the United States federal government and other governments. Although the United States economy appears to have stabilized and may be recovering, the extent and timing of a recovery, and whether it can be sustained, are uncertain. Renewed weakness in the United States or other large economies could materially adversely affect our business and financial condition. For example: 
+• 
+natural gas prices have recently been lower than at various times in the last decade because of increased supply resulting from, among other things, increased drilling in unconventional reservoirs, leading to lower revenues, which could affect our financial condition and results of operations; 
+• 
+the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables; 
+• 
+the liquidity available under our credit facility could be reduced if any lender is unable to fund its commitment; 
+• 
+our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for the exploration and/or development of reserves; 
+• 
+our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; and 
+• 
+variable interest rate spread levels, including for LIBOR and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our credit facility. 
+If we are unable to replace reserves, we will not be able to sustain production. 
+Our future operations depend on our ability to find, develop, or acquire crude oil, natural gas, and NGL reserves that are economically producible. Our properties produce crude oil, natural gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate and develop or acquire new crude oil, natural gas, and NGL reserves to replace those being depleted by production. Without successful drilling or acquisition activities, our reserves and production will decline over time. In addition, competition for crude oil and natural gas properties is intense, and many of our competitors have financial, technical, human, and other resources necessary to evaluate and integrate acquisitions that are substantially greater than those available to us. 
+In the event we do complete an acquisition, its successful impact on our business will depend on a number of factors, many of which are beyond our control. These factors include the purchase price, future crude oil, natural gas, and NGL prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and development activities on the acquired properties, and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities 
+30 
+of proved oil and gas reserves, actual future production rates, and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems. 
+Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited. 
+Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions. 
+Substantial capital is required to develop and replace our reserves. 
+We must make substantial capital expenditures to find, acquire, develop, and produce crude oil, natural gas, and NGL reserves. Future cash flows and the availability of financing are subject to a number of factors, such as the level of production from existing wells, prices received for crude oil, natural gas, and NGL sales, our success in locating and developing and acquiring new reserves, and the orderly functioning of credit and capital markets. If crude oil, natural gas, and NGL prices decrease or if we encounter operating difficulties that result in our cash flows from operations being less than expected, we may reduce our planned capital expenditures unless we can raise additional funds through debt or equity financing or the divestment of assets. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms, and the proceeds offered to us for potential divestitures may not always be of acceptable value to us. 
+If our revenues decrease due to lower crude oil, natural gas, or NGL prices, decreased production, or other reasons, and if we cannot obtain funding through our credit facility, other acceptable debt or equity financing arrangements, or through the sale of assets, our ability to execute development plans, replace our reserves, maintain our acreage, or maintain production levels could be greatly limited. 
+Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do. 
+We face intense competition from major oil and gas companies, independent oil and gas exploration and production companies, and institutional and individual investors who seek oil and gas investments throughout the world, as well as the equipment, expertise, labor, and materials required to operate crude oil and natural gas properties. Many of our competitors have financial, technical, and other resources exceeding those available to us, and many crude oil and natural gas properties are sold in a competitive bidding process in which our competitors may be able and willing to pay more for exploratory and development prospects and productive properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for properties. We may not be successful in acquiring and developing profitable properties in the face of this competition. In addition, other companies may have a greater ability to continue drilling activities during periods of low natural gas or oil prices and to absorb the burden of current and future governmental regulations and taxation. In addition, shortages of equipment, labor, or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. Also, we compete for human resources. Over the last few years, the need for talented people across all disciplines in the industry has grown, while the number of talented people available has not grown at the same pace, and in many cases, is declining due to the demographics of the industry. Our inability to compete effectively with companies in any area of our 
+31 
+business could have a material adverse impact on our business activities, financial condition and results of operations. 
+The loss of key personnel could adversely affect our business. 
+We depend to a large extent on the efforts and continued employment of our executive management team and other key personnel. The loss of the services of these or other key personnel could adversely affect our business. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen and other professionals. Competition for many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed. 
+The actual quantities and present value of our proved crude oil, natural gas, and NGL reserves may be less than we have estimated. 
+This report and other of our SEC filings contain estimates of our proved crude oil, natural gas, and NGL reserves and the estimated future net revenues from those reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to crude oil, natural gas, and NGL prices, drilling and completion costs, gathering and transportation costs, operating expenses, capital expenditures, effects of governmental regulation, taxes, timing of operations, and availability of funds. The process of estimating crude oil, natural gas, and NGL reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent on many variables, and therefore changes often occur as our knowledge of these variables evolve. Therefore, these estimates are inherently imprecise. In addition, the reserve estimates we make for properties that do not have a significant production history may be less reliable than estimates for properties with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing and/or amount of development expenditures. 
+Actual future production, prices for crude oil, natural gas, and NGLs, revenues, production taxes, development expenditures, operating expenses, and quantities of producible crude oil, natural gas, and NGL reserves will most likely vary from those estimated. Any significant variance of any nature could materially affect the estimated quantities of and present value related to proved reserves disclosed by us, and the actual quantities and present value may be significantly less than we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration, operations and development activity, prevailing crude oil, natural gas, and NGL prices, costs to develop and operate properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties, which we may not control. 
+As of December 31, 2013 , 51 percent , or 219.9 MMBOE, of our estimated proved reserves were proved undeveloped, and three percent , or 10.9 MMBOE, were proved developed non-producing. In order to develop our proved undeveloped reserves, as of December 31, 2013 , we estimate approximately $2.8 billion of capital expenditures would be required. Production revenues from proved developed non-producing reserves will not be realized until sometime in the future and after some investment of capital. In order to develop our proved developed non-producing reserves, as of December 31, 2013 , we estimate capital expenditures of approximately $29 million would be required. Although we have estimated our proved reserves and the costs associated with these proved reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled, and actual results may not occur as estimated. 
+32 
+You should not assume that the PV-10 value and standardized measure of discounted future net cash flows included in this report represent the current market value of our estimated proved crude oil, natural gas, and NGL reserves. Management has based the estimated discounted future net cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. For example, values of our reserves as of December 31, 2013 , were estimated using a calculated 12-month average sales price of $3.67 per MMBtu of natural gas (NYMEX Henry Hub spot price), $96.94 per Bbl of oil (NYMEX WTI spot price), and $40.29 per Bbl of NGL (OPIS spot price). We then adjust these prices to reflect appropriate basis, quality, and location differentials over that period in estimating our proved reserves. During 2013 , our monthly average realized natural gas prices, excluding the effect of derivative cash settlements, were as high as $4.41 per Mcf and as low as $3.45 per Mcf. For the same period, our monthly average realized crude oil prices before the effect of derivative cash settlements were as high as $97.87 per Bbl and as low as $83.14 per Bbl, and were as high as $39.36 per Bbl and as low as $31.20 per Bbl for NGLs. Many other factors will affect actual future net cash flows, including: 
+• 
+amount and timing of actual production; 
+• 
+supply and demand for crude oil, natural gas, and NGLs; 
+• 
+curtailments or increases in consumption by oil purchasers and natural gas pipelines; and 
+• 
+changes in government regulations or taxes, including severance and excise taxes. 
+The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing the PV-10 value. In addition, the 10 percent discount factor required by the SEC to be used to calculate the PV-10 value for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and natural gas industry in general are subject. 
+Our property acquisitions may not be worth what we paid due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities. 
+Successful property acquisitions require an assessment of a number of factors, some of which are beyond our control. These factors include exploration potential, future crude oil, natural gas, and NGL prices, operating costs, and potential environmental and other liabilities. These assessments are not precise and their accuracy is inherently uncertain. 
+In connection with our acquisitions, we typically perform a customary review of the acquired properties that will not necessarily reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. 
+In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such acquisitions may be limited. 
+33 
+Integrating acquired properties and businesses involves a number of other special risks, including the risk that management may be distracted from normal business concerns by the need to integrate operations and systems as well as retain and assimilate additional employees. Therefore, we may not be able to realize all of the anticipated benefits of our acquisitions. 
+We have limited control over the activities on properties we do not operate. 
+Some of our properties, including a portion of our operations in the Eagle Ford shale in South Texas, are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including the nature and timing of drilling and operational activities, the operator’s skill and expertise, compliance with environmental, safety and other regulations, the approval of other participants in such properties, the selection and application of suitable technology, or the amount of expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the expenditures of such properties. These limitations and our dependence on the operator and other working interest owners in these projects could cause us to incur unexpected future costs and materially and adversely affect our financial condition and results of operations. 
+We rely on third-party service providers to conduct the drilling and completion operations on properties we operate. 
+Where we are the operator of a property, we rely on third-party service providers to perform necessary drilling and completion operations. The ability of third-party service providers to perform such drilling and completion operations will depend on those service providers’ ability to compete for and retain qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the supply and demand for oil, natural gas liquids and natural gas, prevailing economic conditions and financial, business and other factors. The failure of a third-party service provider to adequately perform operations could delay drilling or completion or reduce production from the property and adversely affect our financial condition and results of operations. 
+Title to the properties in which we have an interest may be impaired by title defects. 
+We generally rely on title reports in acquiring oil and gas leasehold interests and obtain title opinions only on significant properties that we drill. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Title insurance is not available for oil and gas properties. As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work of examining records in the appropriate governmental offices and title abstract facilities before attempting to acquire or place under lease a specific mineral interest and/or undertake drilling activities. We, in some cases, perform curative work to correct deficiencies in the marketability of the title to us. Generally, under the terms of the operating agreements affecting our properties, any monetary loss attributable to a loss of title is to be borne by all parties to any such agreement in proportion to their interests in such property. A material title defect can reduce the value of a property or render it worthless, thus adversely affecting our financial condition, results of operations and operating cash flow if such property is of sufficient value. 
+34 
+Exploration and development drilling may not result in commercially producible reserves. 
+Crude oil and natural gas drilling, completion and production activities are subject to numerous risks, including the risk that no commercially producible crude oil, natural gas, or associated liquids will be found. The cost of drilling and completing wells is often uncertain, and crude oil, natural gas or associated liquids drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors include: 
+• 
+unexpected adverse drilling or completion conditions; 
+• 
+title problems; 
+• 
+disputes with owners or holders of surface interests on or near areas where we operate; 
+• 
+pressure or geologic irregularities in formations; 
+• 
+engineering and construction delays; 
+• 
+equipment failures or accidents; 
+• 
+hurricanes, tornadoes, flooding, or other adverse weather conditions; 
+• 
+governmental permitting delays; 
+• 
+compliance with environmental and other governmental requirements; and 
+• 
+shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies. 
+The prevailing prices for crude oil, natural gas, and NGLs affect the cost of and the demand for drilling rigs, completion and production equipment, and other related services. However, changes in costs may not occur simultaneously with corresponding changes in commodity prices. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region. In addition, the recent economic and financial downturn has adversely affected the financial condition of some drilling contractors, which may constrain the availability of drilling services in some areas. 
+Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a materially adverse effect on our ability to explore or develop our properties. 
+The wells we drill may not be productive, and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well if crude oil, natural gas, or NGLs are present, or whether they can be produced economically. The cost of drilling, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover drilling and completion costs. Even if sufficient amounts of crude oil, natural gas, or NGLs exist, we may damage a potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing a well, which could result in reduced or no production from the well, significant expenditure to repair the well, and/or the loss and abandonment of the well. 
+35 
+Results in our newer resource plays may be more uncertain than results in resource plays that are more developed and have longer established production histories. For example, industry experience and knowledge in the Eagle Ford shale play, is more limited compared to more established resource plays, such as the Barnett or Woodford shales, and we and the industry generally have less information with respect to the ultimate recoverability of reserves and the production decline rates in newer resource plays than other areas with longer histories of development and production. Drilling and completion techniques that have proven to be successful in other resource plays are being used in the early development of these new plays; however, we can provide no assurance of the ultimate success of these drilling and completion techniques. 
+In addition, a significant part of our strategy involves increasing our inventory of drilling locations. Such multi-year drilling inventories can be more susceptible to long-term uncertainties that could materially alter the occurrence or timing of actual drilling. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled, although we have the present intent to do so for locations booked as proved undeveloped locations, or if we will be able to produce crude oil, natural gas, or NGLs from these potential drilling locations. 
+Our future drilling activities may not be successful. Our overall drilling success rate or our drilling success rate within a particular area may decline. In addition, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Unless production is established within the spacing units covering undeveloped acres on which our drilling locations are identified, the leases for such acreage will expire and we would lose our right to develop the related properties. Our total net acreage expiring in the next three years represents approximately 34 percent of our total net undeveloped acreage at December 31, 2013 . Although we have identified numerous potential drilling locations, we may not be able to economically produce crude oil, natural gas, or NGLs from all of them and our actual drilling activities may materially differ from those presently identified, which could adversely affect our financial condition, results of operations and operating cash flow. 
+Part of our strategy involves drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory and delineation drilling in these plays are subject to drilling and completion technique risks, and results may not meet our expectations for reserves or production. As a result, we may incur material write-downs, and the value of our undeveloped acreage could decline if drilling results are unsuccessful. 
+Many of our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize production and ultimate recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our well bore outside the desired drilling zone, deviating from the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore, and being able to run tools and recover equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, the inability to fracture stimulate the planned number of stages, the inability to run tools and other equipment the entire length of the well bore during completion operations, the inability to recover such tools and other equipment, and successfully cleaning out the well bore after completion of the final fracture stimulation. 
+Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or prices for crude oil, natural gas, and NGL decline, then the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of our undeveloped acreage could decline in the future. 
+36 
+Uncertainties associated with enhanced recovery methods may result in us not realizing an acceptable return on our investments in such projects. 
+We inject water into formations on some of our properties to increase the production of crude oil, natural gas, and associated liquids. We may in the future expand these efforts to more of our properties or employ other enhanced recovery methods in our operations. The additional production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of crude oil, natural gas, and associated liquids in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects. In addition, if proposed legislation and regulatory initiatives relating to hydraulic fracturing become law, the cost of some of these enhanced recovery methods could increase substantially. 
+Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own. 
+Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators. 
+Our commodity derivative contract activities may result in financial losses or may limit the prices that we receive for crude oil, natural gas, and NGL sales. 
+To mitigate a portion of the exposure to potentially adverse market changes in crude oil, natural gas, and NGL prices and the associated impact on cash flows, we have entered into various derivative contracts. Our derivative contracts in place include swap and collar arrangements for crude oil, natural gas, and NGLs. As of December 31, 2013 , we were in a net accrued asset position of $21.5 million with respect to our crude oil, natural gas, and NGL derivative activities. These activities may expose us to the risk of financial loss in certain circumstances, including instances in which: 
+• 
+our production is less than expected; 
+• 
+one or more counterparties to our commodity derivative contracts default on their contractual obligations; or 
+• 
+there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement. 
+The risk of one or more counterparties defaulting on their obligations is heightened by the recent global and domestic economic and financial downturn affecting many banks and other financial institutions, including our counterparties and their affiliates. These circumstances may adversely affect the ability of our counterparties to meet their obligations to us pursuant to derivative transactions, which could reduce our revenues and cash flows from realized derivative cash settlements. As a result, our financial condition, results of operations, and cash flows could be materially affected in an adverse way if our counterparties default on their contractual obligations under our commodity derivative contracts. 
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+In addition, commodity derivative contracts may limit the prices that we receive for our crude oil, natural gas and NGL sales if crude oil, natural gas, or NGL prices rise substantially over the price established by the commodity derivative contract. 
+The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results. 
+Substantially all of our accounts receivable result from crude oil, natural gas, and NGL sales or joint interest billings to co-owners of oil and gas properties we operate. This concentration of customers and joint interest owners may impact our overall credit risk because these entities may be similarly affected by various economic and other conditions, including the recent global and domestic economic and financial downturn. During 2013 , we had three major customers, Regency Gas Services LLC , Anadarko, and Plains Marketing LP , which accounted for approximately 26 percent , 16 percent , and 12 percent , respectively, of our total production revenue. Please refer to Note 1 - Summary of Significant Accounting Policies, under the heading Concentration of Credit Risk and Major Customers in Part II, Item 8 of this report for further discussion of our concentration of credit risk and major customers. The loss of one or more of these customers could reduce competition for our products and negatively impact the prices of commodities we sell. 
+We have entered into firm transportation contracts that require us to pay fixed amounts of money to our counterparties regardless of quantities actually shipped, processed, or gathered. If we are unable to deliver the necessary quantities of natural gas to our counterparties, our results of operations and liquidity could be adversely affected. 
+As of December 31, 2013 , we were contractually committed to deliver 1,807 Bcf of natural gas and 53 MMBbl of oil pursuant to contracts expiring at various dates through 2023. We may enter into additional firm transportation agreements as our development of our resource plays expands. At the current time, we do not have enough proved developed reserves to offset these contractual liabilities, but we intend to develop reserves that will exceed the commitments and therefore do not expect any shortfalls. We expect our production volumes, as well as those of our competitors, to increase significantly in the Eagle Ford shale. The use of firm transportation commitments gives us the strategic advantage of priority space in a transportation pipeline. In the event we encounter delays in drilling and completing our wells or otherwise due to construction, interruptions of operations, or delays in connecting new volumes to gathering systems or pipelines for an extended period of time, the requirements to pay for quantities not delivered could have a material impact on our results of operations and liquidity. 
+Future crude oil, natural gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values. 
+We follow the successful efforts method of accounting for our crude oil and natural gas properties. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If commercial quantities of hydrocarbons are not discovered with an exploratory well, the costs of drilling the well are expensed. 
+The capitalized costs of our crude oil, natural gas, and NGL properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net revenues, we generally must write down the costs of each depletion pool to the estimated discounted future net cash flows of that depletion pool. Unproved properties are evaluated at the lower of cost or fair market value. We incurred an impairment of proved properties and impairment of unproved properties totaling $172.6 million and $46.1 million , respectively, during 2013 , $208.9 million and $16.3 million , respectively, during 2012 , and $219.0 million and $7.4 million , respectively, during 2011 . Significant declines in crude oil, natural gas, or NGL prices in the future or unsuccessful exploration efforts could cause additional proved and/or unproved property impairments in the future. 
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+We review the carrying value of our properties for indicators of impairment on a quarterly basis using the prices in effect as of the end of each quarter. Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date, even if crude oil, natural gas, or NGL prices increase. 
+Lower crude oil, natural gas, or NGL prices could limit our ability to borrow under our credit facility. 
+Our credit facility has a current commitment amount of $1.3 billion , subject to a borrowing base that the lenders redetermine semi-annually based on the bank group’s assessment of the value of our crude oil, natural gas, and NGL properties, which in turn is impacted by crude oil, natural gas, and NGL prices. The current borrowing base under our credit facility is $2.2 billion . Declines in crude oil, natural gas, or NGL prices in the future could limit our borrowing base and reduce the amount we can borrow under our credit facility. Additionally, divestitures of properties could result in a reduction of our borrowing base. 
+The amount of our debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt. 
+As of December 31, 2013 , we had $350.0 million of long-term senior unsecured debt outstanding relating to our 6.625% Senior Notes due 2019 (the “2019 Notes”) that we issued on February 7, 2011; $350.0 million of long-term senior unsecured debt outstanding relating to our 6.50% Senior Notes due 2021 (the “2021 Notes”) that we issued on November 8, 2011; $400.0 million of long-term senior unsecured debt outstanding relating to our 6.50% Senior Notes due 2023 (the “2023 Notes”) that we issued on June 29, 2012; and $500.0 million of long-term senior unsecured debt outstanding relating to our 5.0% Senior Notes due 2024 (the “2024 Notes”) that we issued on May 20, 2013 (collectively, the 2019 Notes, the 2021 Notes, the 2023 Notes, and the 2024 Notes are referred to as our “Senior Notes”); and no outstanding borrowings under our secured credit facility. We had three outstanding letters of credit in the aggregate amount of $808,000 (which reduce the amount available for borrowing under the facility on a dollar-for-dollar basis), resulting in $1,299.2 million of available debt capacity under our credit facility, assuming the borrowing conditions under this facility will be met. Our long-term debt represented 50 percent of our total book capitalization as of December 31, 2013 . 
+Our indebtedness could have important consequences for our operations, including: 
+• 
+making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements; 
+• 
+requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to productive investments; 
+• 
+limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends; 
+• 
+placing us at a competitive disadvantage compared to our competitors that have less debt; and 
+• 
+making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business. 
+Our ability to make payments on our debt, refinance our debt, and fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory, and other factors that are beyond our control. If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our credit facility or from other sources, we might not be able to service our debt or fund our other liquidity needs. If we are unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity securities, divest assets, and/or restructure or refinance our debt. We might 
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+not be able to sell our equity, sell our assets, or restructure or refinance our debt on a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our existing and future credit agreements, may prohibit us from pursuing any of these alternatives. Further, changes in the credit ratings of our debt may negatively affect the cost, terms, conditions, and availability of future financing. 
+Our debt agreements, including the agreement governing our credit facility and the indentures governing the Senior Notes, permit us to incur additional debt in the future, subject to compliance with restrictive covenants under those agreements. In addition, entities we may acquire in the future could have significant amounts of debt outstanding that we could be required to assume, and in some cases accelerate repayment thereof, in connection with the acquisition, or we may incur our own significant indebtedness to consummate an acquisition. 
+As discussed above, our credit facility is subject to periodic borrowing base redeterminations. We could be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowing base or arrange new financing, we may be forced to sell significant assets. 
+The agreements governing our debt contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt. 
+Our debt agreements contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under our credit facility is subject to compliance with certain financial covenants, including (i) maintenance of a quarterly ratio of total debt to 12-month trailing consolidated earnings before interest, taxes, depreciation, amortization, and exploration expense of less than 4.0, and (ii) maintenance of an adjusted current ratio of no less than 1.0, each as defined in our credit facility. Our credit facility also requires us to comply with certain financial covenants, including requirements that we maintain certain levels of stockholders’ equity and limit our annual cash dividends to no more than $50.0 million . These restrictions on our ability to operate our business could seriously harm our business by, among other things, limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate opportunities. 
+The respective indentures governing the Senior Notes also contain covenants that, among other things, limit our ability and the ability of our subsidiaries to: 
+• 
+incur additional debt; 
+• 
+make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire capital stock; 
+• 
+sell assets, including capital stock of our subsidiaries; 
+• 
+restrict dividends or other payments of our subsidiaries; 
+• 
+create liens that secure debt; 
+• 
+enter into transactions with affiliates; and 
+• 
+merge or consolidate with another company. 
+Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all or a portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness. 
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+We are subject to operating and environmental risks and hazards that could result in substantial losses or liabilities that may not be fully insured. 
+Crude oil and natural gas operations are subject to many risks, including human error and accidents that could cause personal injury, death and property damage, well blowouts, craterings, explosions, uncontrollable flows of crude oil, natural gas and associated liquids or well fluids, migration of fracture fluids into surrounding groundwater, spills or releases from facilities and equipment used to deliver these materials, spills or releases of brine or other produced or flowback water, subsurface conditions that prevent us from stimulating the planned number of stages, accessing the entirety of the wellbore with our tools during completion, or removing fracturing materials from the wellbore to allow production to begin, fires, adverse weather such as hurricanes or tornadoes, freezing conditions, floods, droughts, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas such as hydrogen sulfide, and other environmental risks and hazards. If any of these types of events occurs, we could sustain substantial losses. 
+Furthermore, if we experience any of the problems with well stimulation and completion activities referenced above, such as hydraulic fracturing, our ability to explore for and produce crude oil, natural gas, or NGLs may be adversely affected. We could incur substantial losses or otherwise fail to realize reserves in particular formations as a result of the need to shutdown, abandon and relocate drilling operations, the need to sample, test and monitor drinking water in particular areas and to provide filtration or other drinking water supplies to users of water supplies that may have been impacted or threatened by potential contamination from fracturing fluids, the need to modify drill sites to ensure there are no spills or releases off-site and to investigate and/or remediate any spills or releases that might have occurred, and suspension of our operations. 
+There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our current and past generation, handling and disposal of materials, including solid and hazardous wastes and petroleum hydrocarbons. We may incur joint and several, strict liability under applicable United States federal and state environmental laws in connection with releases of petroleum hydrocarbons and other hazardous substances at, on, under or from our leased or owned properties, some of which have been used for natural gas and oil exploration and production activities for a number of years, often by third parties not under our control. For our outside operated properties, we are dependent on the operator for operational and regulatory compliance, and could be subject to liabilities in the event of non-compliance. These properties and the wastes disposed thereon or away from could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including the CERCLA or the Superfund law, the RCRA, the Clean Water Act, the CAA, the OPA, and analogous state laws. Under any implementing regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damage allegedly caused by the release of petroleum hydrocarbons or other hazardous substances into the environment. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur losses. 
+We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden environmental damage. We do not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damage or insurance coverage for environmental damage that occurs over time is available at a reasonable cost. In addition, pollution and environmental risks generally are not fully insurable. Further, we may elect not to obtain other insurance coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks to which we are subject. Accordingly, we may be subject to liability or may lose substantial assets in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer a material loss. 
+41 
+Following severe Atlantic hurricanes in recent years, the insurance markets suffered significant losses. As a result, insurance coverage for wind storms has been substantially more expensive, and future availability and costs of coverage are uncertain. 
+Our operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs and other risks. 
+Federal, state, tribal, and local authorities extensively regulate the oil and natural gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may become more stringent and, as a result, may affect, among other things, the pricing or marketing of crude oil, natural gas and NGL production. Noncompliance with statutes and regulations and more vigorous enforcement of such statutes and regulations by regulatory agencies may lead to substantial administrative, civil, and criminal penalties, including the assessment of natural resource damages, the imposition of significant investigatory and remedial obligations and may also result in the suspension or termination of our operations. The overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells and related facilities and, in turn, decreases profitability. 
+Governmental authorities regulate various aspects of drilling for and the production of crude oil, natural gas, and NGLs, including the permit and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in crude oil and natural gas properties, rights-of-way and easements, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment, and restoration standards, oil and gas operations, and restoration. Public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain projects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or impose conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or develop certain properties. Federal authorities also may require any of our ongoing or planned operations on federal leases to be delayed, suspended, or terminated. Any such delay, suspension, or termination could have a materially adverse effect on our operations. 
+Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, tribal and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, including the designation of previously unprotected wildlife or plant species as threatened or endangered in areas we operate, could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. Under existing or future environmental laws and regulations, we could incur significant liability, including joint and several, strict liability under federal, state, and tribal environmental laws for noise emissions and for discharges of crude oil, natural gas, and associated liquids or other pollutants into the air, soil, surface water, or groundwater. We could be required to spend substantial amounts on investigations, litigation, and remediation for these emissions and discharges and other compliance issues. Any unpermitted release of petroleum or other pollutants from our operations could result not only in cleanup costs, but also natural resources, real or personal property and other compensatory damages and civil and criminal liability. The listing of additional wildlife or plant species as federally endangered or threatened could result in limitations on exploration and production activities in certain locations. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a materially adverse effect on us. 
+Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. 
+Operations in certain of our regions, such as our Rocky Mountain and Permian regions, are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife or plant species. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during 
+42 
+limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. Wildlife seasonal restrictions may limit access to federal leases or across federal lands. Possible restrictions may include seasonal restrictions in greater sage-grouse habitat during breeding and nesting seasons, within a certain distance of active raptor nests during fledging, and in big game winter or parturition ranges during winter or calving seasons. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. 
+Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. 
+Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of oil, natural gas and associated liquids from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques to many of our oil and natural gas properties, including our unconventional resource plays in the Eagle Ford shale of south Texas and the Bakken/Three Forks formations in North Dakota. Hydraulic fracturing involves using water, sand and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and natural gas commissions. However, the EPA and other federal agencies have asserted federal regulatory authority over certain aspects of hydraulic fracturing activities as outlined below. 
+The EPA has authority to regulate underground injections that contain diesel in the fluid system under the SDWA. The EPA has published draft guidance documents related to regulation of fracturing fluids using this regulatory authority. The EPA also plans to update its chloride water quality criteria for the protection of aquatic life under the Clean Water Act. Flowback and produced water from the hydraulic fracturing process contain total dissolved solids, including chlorides, and regulation of these fluids could be affected by the new criteria. The EPA has delayed issuing a draft criteria document until 2014. The EPA has also announced that it will develop pre-treatment standards for disposal of wastewater produced from shale gas operations through publicly owned treatment works. The regulations will be developed under the EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. The EPA anticipates issuing the proposed rules in 2014. If the EPA implements further regulations of hydraulic fracturing, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells. 
+Certain states that we operate in, including Texas and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components and volume of water used in the hydraulic fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general and/or hydraulic fracturing in particular. Recently, several municipalities have passed or proposed zoning ordinances that ban or strictly regulate hydraulic fracturing within city boundaries. For example, the city of Longmont, Colorado is currently in litigation with the State of Colorado to uphold the city’s ordinance that bans hydraulic fracturing. Similar events and processes are playing out in several cities, counties, and townships across the United States. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct, operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells. 
+Several agencies of the federal governmental are actively involved in studies or reviews that focus on environmental aspects and impacts of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating a review of hydraulic fracturing practices, and a committee of the United States House of 
+43 
+Representatives has conducted an investigation of hydraulic fracturing practices and government studies related thereto. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA issued a progress report in 2012, and plans to issue a draft report of results in 2014 for public comment and independent peer review by the Science Advisory Board. The United States Department of Energy is actively involved in research on hydraulic fracturing practices, including groundwater protection. Also, the United States Department of the Interior proposed a rule to regulate hydraulic fracturing on public lands in May of 2013. The proposed rule contains disclosure requirements and other mandates for well integrity and management of water produced by the process, and will likely be finalized in 2014. 
+Legislation has been introduced before Congress, including during the 113th Congress, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. If hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit or disclosure requirements, associated permitting delays, operational restrictions, litigation risk and potential cost increases. Additionally, certain members of Congress have called upon the United States Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the United States Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. The United States Geological Survey Offices of Energy Resources Program, Water Resources and Natural Hazards and Environmental Health Offices also have ongoing research projects on hydraulic fracturing. These ongoing studies, depending on their course and outcomes, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory processes. 
+Further, on August 16, 2012, the EPA issued final rules subjecting all oil and gas operations (production, processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. The EPA rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards require the use of reduced emission completion (“REC”) techniques developed in the EPA's Natural Gas STAR program along with the pit flaring of gas not sent to the gathering line beginning in January 2015. The standards are applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (“MACT”) standards for those glycol dehydrators and certain storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. These rules will require additional control equipment, changes to procedure, and extensive monitoring and reporting. The EPA stated in January 2013, however, that it intends to reconsider portions of the final rule. On September 23, 2013, the EPA published new standards for storage tanks subject to the NSPS. The EPA has stated that it continues to review other issues raised in petitions for reconsideration. We are currently evaluating the effect of these rules on our business. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing such activity to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. Over the past year, several court cases have addressed aspects of hydraulic fracturing. In a case that could delay operations on public lands, a court in California held that the BLM did not adequately consider the impact of hydraulic fracturing and horizontal drilling before issuing leases. Courts in New York and Colorado reduced the level of evidence required before a court will agree to consider alleged damage claims from hydraulic fracturing by property owners. Litigation resulting in financial compensation for damages linked to hydraulic fracturing could spur future litigation and bring increased attention to the practice of hydraulic fracturing. Judicial decisions could also lead to 
+44 
+increased regulation, permitting requirements, enforcement actions, and penalties. Additional legislation or regulation could also lead to operational delays or increased costs in the exploration for and production of oil, natural gas, and associated liquids, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state, or local laws, or the implementation of new regulations, regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, or an increase in compliance costs and delays, which could adversely affect our financial position, results of operations, and cash flows. 
+Our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations and/or completions or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules. 
+The hydraulic fracturing process on which we and others in our industry depend to complete wells that will produce commercial quantities of crude oil, natural gas, and associated liquids requires the use and disposal of significant quantities of water. 
+Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of crude oil, natural gas, and natural gas liquids. 
+Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition. 
+Certain United States federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation . 
+Recent federal budget proposals, if enacted into law, would eliminate certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These potential changes include: 
+• 
+the elimination of current deductions for intangible drilling and development costs; 
+• 
+the repeal of the percentage depletion allowance for oil and natural gas properties; 
+• 
+the elimination of the deduction for certain domestic production activities; and 
+• 
+an extension of the amortization period for certain geological and geophysical expenditures. 
+It is unclear when or if these or similar changes will be enacted. The passage of legislation enacting these or similar changes in federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows. 
+45 
+Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for crude oil, natural gas, and NGLs. 
+In December 2009, the EPA made a finding that emissions of carbon dioxide, methane, and other “greenhouse gases” endanger public health and the environment because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on this “endangerment finding,” the EPA has over the past four years adopted and implemented a comprehensive suite of regulations to restrict and otherwise regulate emissions of greenhouse gases under existing provisions of the CAA. In particular, the EPA has adopted two sets of rules regulating greenhouse gas emissions under the CAA. One rule requires a reduction in greenhouse gas emissions from motor vehicles, and the other regulates permitting and greenhouse gas emissions from certain large stationary sources. These EPA regulatory actions have been challenged by various industry groups, initially in the D.C. Circuit, which in 2012 ruled in favor of the EPA in all respects. However, the U.S. Supreme Court agreed to hear certain of industry’s challenges to the EPA’s application of the greenhouse gas endangerment finding to stationary sources, and a decision is expected in 2014. The EPA has also adopted reporting rules for greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries as well as certain onshore oil and natural gas production facilities. 
+Several other kinds of cases on greenhouse gases have been heard by the courts in recent years. While courts have generally declined to assign direct liability for climate change to large sources of greenhouse gas emissions, some have required increased scrutiny of such emissions by federal agencies and permitting authorities. There is a continuing risk of claims being filed against companies that have significant greenhouse gas emissions, and new claims for damages and increased government scrutiny will likely continue. Such cases often seek to challenge air emissions permits that greenhouse gas emitters apply for, seek to force emitters to reduce their emissions, or seek damages for alleged climate change impacts to the environment, people, and property. Any court rulings, laws or regulations that restrict or require reduced emissions of greenhouse gases could lead to increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas that we produce. 
+The United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas “cap and trade” programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. Recently, the Congressional Budget Office provided Congress with a study on the potential effects on the U.S. economy of a tax on greenhouse gas emissions. While “carbon tax” legislation has been introduced in the Senate, the prospects for passage of such legislation are highly uncertain at this time. 
+On June 25, 2013, President Obama outlined plans to address climate change through a variety of executive actions, including reduction of methane emissions from oil and gas production and processing operations as well as pipelines and coal mines (the “Climate Plan”). The President’s Climate Plan, along with recent regulatory initiatives and ongoing litigation filed by states and environmental groups, signal a new focus on methane emissions that could pose substantial regulatory risk to our operations. The Climate Plan could eventually result in: 
+• requirements for methane emission reductions from oil and gas equipment; 
+• increased scrutiny for sources emitting high levels of methane, including during permitting processes; 
+• analysis, regulation and reduction of methane emissions as a requirement for project approval; 
+46 
+• agency adoption of regulations to reduce methane emissions from oil and gas production, processing, 
+and pipelines, including emissions associated with equipment leaks, fugitives, flowback or waste; 
+• and actions taken by one agency for a specific industry establishing precedents for other agencies and 
+industry sectors. 
+In relation to the Climate Plan, proposals to increase both the assumed “Global Warming Potential” (“GWP”) and the assumed social costs associated with methane and other greenhouse gas emissions have been introduced. Changes to these measurement tools could adversely impact permitting requirements, application of agencies’ existing regulations for source categories with high methane emissions, and determinations of whether a source qualifies for regulation under the CAA. These changes to how the impact of methane is measured and evaluated are still in process, and the potential outcome of the proposals remains uncertain. 
+Finally, it should be noted that some scientists have predicted that increasing concentrations of greenhouse gases in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. Some scientists refute these predictions. However, President Obama’s Climate Plan emphasizes preparation for such events. If such effects were to occur, our operations could be adversely affected. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from flooding or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of such events. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. Federal regulations or policy changes regarding climate change preparation requirements could also impact our costs and planning requirements. 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. 
+The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which was signed into law on July 21, 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act also establishes margin requirements and certain transaction clearing and trade execution requirements. On October 18, 2011, the Commodities Futures Trading Commission (the “CFTC”) approved regulations to set position limits for certain futures and option contracts in the major energy markets, which were successfully challenged in federal district court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. On November 5, 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. Comments on these new rules were due in early January 2014, and, as these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. 
+47 
+Under CFTC final rules promulgated under the Dodd-Frank Act, we believe our derivatives activity will qualify for the non-financial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement. The Dodd-Frank Act may also require us to comply with margin requirements in our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. Therefore, the Dodd-Frank Act and the rules promulgated thereunder could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. 
+If we reduce our use of derivatives as a result of the Dodd-Frank Act and related regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and related regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows. 
+Our ability to sell crude oil, natural gas and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines and other transportation systems owned or operated by others or by other interruptions. 
+The marketability of our crude oil, natural gas, and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing facilities, and pipeline and other transportation systems owned or operated by third parties. Any significant interruption in service from, damage to, or lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay or discontinuance of development plans for our properties, or lower price realizations. Although we have some contractual control over the processing and transportation of our operated production, material changes in these business relationships could materially affect our operations. Federal and state regulation of crude oil, natural gas, and NGL production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process, and transport crude oil, natural gas, and NGLs. 
+In particular, if drilling in the Eagle Ford shale and Bakken/Three Forks resource play continues to be successful, the amount of crude oil, natural gas, and NGLs being produced by us and others could exceed the capacity of, and result in strains on, the various gathering and transportation systems, pipelines, processing facilities, and other infrastructure available in these areas. It will be necessary for additional infrastructure, pipelines, gathering and transportation systems and processing facilities to be expanded, built or developed to accommodate anticipated production from these areas. Because of the current economic climate, certain processing, pipeline, and other gathering or transportation projects that might be, or are being, considered for these areas may not be developed timely or at all due to lack of financing or other constraints. Capital and other constraints could also limit our ability to build or access intrastate gathering and transportation systems necessary to transport our production to interstate pipelines or other points of sale or delivery. In such event, we might have to delay or discontinue development activities or shut in our wells to wait for sufficient infrastructure development or capacity expansion and/or sell production at significantly lower prices, which would adversely affect our results of operations and cash flows. In addition, the operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state, and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. 
+48 
+Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations. 
+A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily and adversely affect our cash flows and results of operations. 
+New technologies may cause our current exploration and drilling methods to become obsolete. 
+The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected. 
+Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions. 
+As a crude oil, natural gas, and NGL producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows. 
+Cybersecurity attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. 
+The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for crude oil, natural gas, and NGLs, all of which could adversely affect the markets for our operations. Energy assets might be specific targets of terrorist attacks. These developments have subjected our operations to increased risk and, depending on their occurrence and ultimate magnitude, could have a material adverse effect on our business. 
+49 
+Risks Related to Our Common Stock 
+The price of our common stock may fluctuate significantly, which may result in losses for investors. 
+From January 1, 2013 , to February 12, 2014 , the closing daily sale price of our common stock as reported by the New York Stock Exchange ranged from a low of $53.77 per share in January 2013 to a high of $91.98 per share in November 2013. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include: 
+• 
+changes in crude oil, natural gas, or NGL prices; 
+• 
+variations in drilling, recompletion, and operating activity; 
+• 
+changes in financial estimates by securities analysts; 
+• 
+changes in market valuations of comparable companies; 
+• 
+additions or departures of key personnel; 
+• 
+future sales of our common stock; and 
+• 
+changes in the national and global economic outlook. 
+We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could decline as a result. 
+Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment, which could adversely affect the price of our common stock. 
+Delaware corporate law and our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or preventing a change of control of us or our management. These provisions, among other things, provide for non-cumulative voting in the election of members of the Board of Directors and impose procedural requirements on stockholders who wish to make nominations for the election of directors or propose other actions at stockholder meetings. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock. 
+Shares eligible for future sale may cause the market price of our common stock to drop significantly, even if our business is doing well. 
+The potential for sales of substantial amounts of our common stock in the public market may have a materially adverse effect on our stock price. As of February 12, 2014 , 66,997,786 shares of our common stock were freely tradable without substantial restriction or the requirement of future registration under the Securities Act. Also as of that date, options to purchase 39,088 shares of our common stock were outstanding, all of which were exercisable. These options are exercisable at $20.87 per share. In addition, restricted stock units (“RSUs”) providing for the issuance of up to a total of 574,188 shares of our common stock and 799,851 performance share units (“PSUs”) were outstanding. The PSUs represent the right to receive, upon settlement of the PSUs after the completion of a three-year performance period, a number of shares of our common stock that may be from zero to two times the number of PSUs granted, depending on the extent to which the underlying performance criteria have 
+50 
+been achieved and the extent to which the PSUs have vested. As of February 12, 2014 , there were 67,056,441 shares of our common stock outstanding, which is net of 22,412 treasury shares. 
+We may not always pay dividends on our common stock. 
+Payment of future dividends remains at the discretion of our Board of Directors, and will continue to depend on our earnings, capital requirements, financial condition, and other factors. In addition, the payment of dividends is subject to a covenant in our credit facility limiting our annual cash dividends to no more than $50.0 million , and to covenants in the indentures for our Senior Notes that limit our ability to pay dividends beyond a certain amount. Our Board of Directors may determine in the future to reduce the current semi-annual dividend rate of $0.05 per share, or discontinue the payment of dividends altogether. 
+51 
+ITEM 1B. UNRESOLVED STAFF COMMENTS 
+We have no unresolved comments from the SEC staff regarding our periodic or current reports under the Securities Exchange Act of 1934. 
+ITEM 3. LEGAL PROCEEDINGS 
+From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. As of the filing date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows. 
+We filed a declaratory judgment action in Webb County, Texas, captioned SM Energy Company vs. W.H. Sutton, et al. , seeking a judgment declaring a prior lease in the Eagle Ford shale play in South Texas had terminated with respect to 18,000 acres, based upon a failure of continuous development, and that any overriding royalty interest claimed by the defendants has been extinguished. On September 19, 2012, the District Court in Webb County, Texas, granted our motion for summary judgment, concluding that the defendants’ claims for any overriding royalty interest had been extinguished. The plaintiffs appealed the District Court’s judgment to the Fourth Court of Appeals, which affirmed the District Court’s judgment on November 13, 2013. This judgment became final on January 23, 2014. 
+We, and our working interest partners, filed an action against Endeavour Operating Corporation (“Endeavour”) in Harris County, Texas, captioned SM Energy Company, et al. v. Endeavour Operating Corporation , seeking an order requiring Endeavour to honor its obligations to consummate the purchase of certain assets located in Pennsylvania, or in the alternative, for damages. We continue to prosecute this action to recover any relief to which we are entitled. 
+On January 27, 2011, Chieftain Royalty Company (“Chieftain”) filed a Class Action Petition against us in the District Court of Beaver County, Oklahoma, claiming damages related to royalty valuation on all of our Oklahoma wells. These claims include breach of contract, breach of fiduciary duty, fraud, unjust enrichment, tortious breach of contract, conspiracy, and conversion, based generally on asserted improper deduction of post-production costs. We removed this lawsuit to the United States District Court for the Western District of Oklahoma on February 22, 2011. We have responded to the petition and denied the allegations. The district court did not rule on Chieftain’s motion to certify the putative class, and stayed all proceedings until the United States Court of Appeals for the Tenth Circuit issued its rulings on class certification in two similar royalty class action lawsuits. On July 9, 2013, the Tenth Circuit issued its opinions, reversing the trial courts’ grant of class certification and remanding the matters to the trial courts for those cases. The district court presiding over our case subsequently lifted its stay, and we expect Chieftain to file a new motion for class certification in the first half of 2015. 
+This case involves complex legal issues and uncertainties; a potentially large class of plaintiffs, and a large number of related producing properties, lease agreements and wells; and an alleged class period commencing in 1988 and spanning the entire producing life of the wells. Because the proceedings are in the early stages, with substantive discovery yet to be conducted, we are unable to estimate what impact, if any, the action will have on our financial condition, results of operations or cash flows. We are still evaluating the claims, but believe that we have properly paid royalties under Oklahoma law and have and will continue to vigorously defend this case. On December 30, 2013, we sold a substantial portion of our assets that were subject to this matter, and the buyer assumed any such liabilities related to such properties. 
+ITEM 4. MINE SAFETY DISCLOSURES 
+These disclosures are not applicable to us. 
+52 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Market Information. Our common stock is currently traded on the New York Stock Exchange under the ticker symbol “SM.” The following table presents the range of high and low intraday sales prices per share for the indicated quarterly periods in 2013 and 2012 , as reported by the New York Stock Exchange: 
+Quarter Ended 
+High 
+Low 
+December 31, 2013 
+$ 
+94.00 
+$ 
+76.72 
+September 30, 2013 
+$ 
+77.70 
+$ 
+60.22 
+June 30, 2013 
+$ 
+65.55 
+$ 
+55.30 
+March 31, 2013 
+$ 
+62.26 
+$ 
+52.67 
+December 31, 2012 
+$ 
+62.09 
+$ 
+45.25 
+September 30, 2012 
+$ 
+59.39 
+$ 
+39.44 
+June 30, 2012 
+$ 
+71.81 
+$ 
+43.12 
+March 31, 2012 
+$ 
+84.40 
+$ 
+69.40 
+PERFORMANCE GRAPH 
+The following performance graph compares the cumulative return on our common stock, for the period beginning December 31, 2008, and ending on December 31, 2013 , with the cumulative total returns of the Dow Jones U.S. Exploration and Production Board Index, and the Standard & Poor’s 500 Stock Index. 
+COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURNS 
+The preceding information under the caption Performance Graph shall be deemed to be furnished, but not filed with the SEC. 
+Holders. As of February 12, 2014 , the number of record holders of our common stock was 81. Based upon inquiry, management believes that the number of beneficial owners of our common stock is approximately 27,700. 
+53 
+Dividends. We have paid cash dividends to our stockholders every year since 1940. Annual dividends of $0.05 per share were paid in each of the years 1998 through 2004. Annual dividends of $0.10 per share were paid in 2005 through 2013 . We expect that our practice of paying dividends on our common stock will continue, although the payment of future dividends will continue to depend on our earnings, cash flow, capital requirements, financial condition, and other factors, including the discretion of our Board of Directors. In addition, the payment of dividends is subject to covenants in our credit facility that limit our annual dividend payment to no more than $50.0 million per year. We are also subject to certain covenants under our Senior Notes that restrict certain payments, including dividends; provided, however, the first $6.5 million of dividends paid each year are not restricted by this covenant. Based on our current performance, we do not anticipate that these covenants will restrict future annual dividend payments of $0.10 per share of common stock. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $6.7 million in 2013 and $6.5 million in 2012 . 
+Restricted Shares. We have no restricted shares outstanding as of December 31, 2013 , aside from Rule 144 restrictions on shares held by insiders and shares issued to members of the Board of Directors under our Equity Incentive Compensation Plan (“Equity Plan”). 
+Purchases of Equity Securities by the Issuer and Affiliated Purchasers. The following table provides information about purchases by the Company and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the indicated quarters and year ended December 31, 2013 , of shares of the Company’s common stock, which is the sole class of equity securities registered by the Company pursuant to Section 12 of the Exchange Act. 
+ISSUER PURCHASES OF EQUITY SECURITIES 
+Total Number of Shares Purchased (1) 
+Average Price Paid per Share 
+Total Number of Shares Purchased as Part of Publicly Announced Program 
+Maximum Number of Shares that May Yet be Purchased Under the Program (2) 
+January 1, 2013 - 
+March 31, 2013 
+— 
+$ 
+— 
+— 
+3,072,184 
+April 1, 2013 - 
+June 30, 2013 
+390 
+$ 
+59.84 
+— 
+3,072,184 
+July 1, 2013 - 
+September 30, 2013 
+267,362 
+$ 
+60.50 
+— 
+3,072,184 
+October 1, 2013 - 
+October 31, 2013 
+285 
+$ 
+77.19 
+— 
+3,072,184 
+November 1, 2013 - 
+November 30, 2013 
+— 
+$ 
+— 
+— 
+3,072,184 
+December 1, 2013 - 
+December 31, 2013 
+— 
+$ 
+— 
+— 
+3,072,184 
+Total October 1, 2013 - 
+December 31, 2013 
+285 
+$ 
+77.19 
+— 
+3,072,184 
+Total 
+268,037 
+$ 
+60.51 
+— 
+3,072,184 
+(1) 
+All shares purchased in 2013 were to offset tax withholding obligations that occur upon the delivery of outstanding shares underlying RSUs and PSUs delivered under the terms of grants under the Equity Plan. 
+(2) 
+In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of this filing, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility, the indentures governing our Senior Notes and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow, or borrowings under our credit facility. The stock repurchase program may be suspended or discontinued at any time. Please refer to Dividends above for a description of our dividend limitations. 
+54 
+ITEM 6. SELECTED FINANCIAL DATA 
+The following table sets forth selected supplemental financial and operating data for us as of the dates and periods indicated. The financial data for each of the five years presented were derived from our consolidated financial statements. The following data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report, which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our consolidated financial statements included in this report. 
+Years Ended December 31, 
+2013 
+2012 
+2011 
+2010 
+2009 
+(in millions, except per share data) 
+Total operating revenues 
+$ 
+2,293.4 
+$ 
+1,505.1 
+$ 
+1,603.3 
+$ 
+1,092.8 
+$ 
+832.2 
+Net income (loss) 
+$ 
+170.9 
+$ 
+(54.2 
+) 
+$ 
+215.4 
+$ 
+196.8 
+$ 
+(99.4 
+) 
+Net income (loss) per share: 
+Basic 
+$ 
+2.57 
+$ 
+(0.83 
+) 
+$ 
+3.38 
+$ 
+3.13 
+$ 
+(1.59 
+) 
+Diluted 
+$ 
+2.51 
+$ 
+(0.83 
+) 
+$ 
+3.19 
+$ 
+3.04 
+$ 
+(1.59 
+) 
+Total assets at year-end 
+$ 
+4,705.2 
+$ 
+4,199.5 
+$ 
+3,799.0 
+$ 
+2,744.3 
+$ 
+2,360.9 
+Long-term debt: 
+Revolving credit facility 
+$ 
+— 
+$ 
+340.0 
+$ 
+— 
+$ 
+48.0 
+$ 
+188.0 
+3.50% Senior Convertible Notes, net of debt discount 
+$ 
+— 
+$ 
+— 
+$ 
+285.1 
+$ 
+275.7 
+$ 
+266.9 
+Senior Notes 
+$ 
+1,600.0 
+$ 
+1,100.0 
+$ 
+700.0 
+$ 
+— 
+$ 
+— 
+Cash dividends declared and paid per common share 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+$ 
+0.10 
+55 
+Supplemental Selected Financial and Operations Data 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+2010 
+2009 
+Balance Sheet Data (in millions) 
+Total working capital (deficit) 
+$ 
+8.4 
+$ 
+(201.0 
+) 
+$ 
+(42.6 
+) 
+$ 
+(227.4 
+) 
+$ 
+(87.6 
+) 
+Total stockholders’ equity 
+$ 
+1,606.8 
+$ 
+1,414.5 
+$ 
+1,462.9 
+$ 
+1,218.5 
+$ 
+973.6 
+Weighted-average common shares outstanding (in thousands) 
+Basic 
+66,615 
+65,138 
+63,755 
+62,969 
+62,457 
+Diluted 
+67,998 
+65,138 
+67,564 
+64,689 
+62,457 
+Reserves 
+Oil (MMBbl) 
+126.6 
+92.2 
+71.7 
+57.4 
+53.8 
+Gas (Bcf) 
+1,189.3 
+833.4 
+664.0 
+640.0 
+449.5 
+NGLs (MMBbl) 
+103.9 
+62.3 
+27.5 
+— 
+— 
+MMBOE 
+428.7 
+293.4 
+209.9 
+164.1 
+128.7 
+Production and Operations (in millions) 
+Oil, gas, and NGL production revenue 
+$ 
+2,199.6 
+$ 
+1,473.9 
+$ 
+1,332.4 
+$ 
+836.3 
+$ 
+616.0 
+Oil, gas, and NGL production expense 
+$ 
+597.0 
+$ 
+391.9 
+$ 
+290.1 
+$ 
+195.1 
+$ 
+206.8 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion expense 
+$ 
+822.9 
+$ 
+727.9 
+$ 
+511.1 
+$ 
+336.1 
+$ 
+304.2 
+General and administrative 
+$ 
+149.6 
+$ 
+119.8 
+$ 
+118.5 
+$ 
+106.7 
+$ 
+76.0 
+Production Volumes 
+Oil (MMBbl) 
+13.9 
+10.4 
+8.1 
+6.4 
+6.3 
+Gas (Bcf) 
+149.3 
+120.0 
+100.3 
+71.9 
+71.1 
+NGLs (MMBbl) 
+9.5 
+6.1 
+3.5 
+— 
+— 
+MMBOE 
+48.3 
+36.5 
+28.3 
+18.3 
+18.2 
+Realized price 
+Oil (per Bbl) 
+$ 
+91.19 
+$ 
+85.45 
+$ 
+88.23 
+$ 
+72.65 
+$ 
+54.40 
+Gas (per Mcf) 
+$ 
+3.93 
+$ 
+2.98 
+$ 
+4.32 
+$ 
+5.21 
+$ 
+3.82 
+NGL (per Bbl) 
+$ 
+35.95 
+$ 
+37.61 
+$ 
+53.32 
+$ 
+— 
+$ 
+— 
+Adjusted price (net of derivative cash settlements) 
+Oil (per Bbl) 
+$ 
+89.92 
+$ 
+83.52 
+$ 
+78.89 
+$ 
+66.85 
+$ 
+56.74 
+Gas (per Mcf) 
+$ 
+4.14 
+$ 
+3.48 
+$ 
+4.80 
+$ 
+6.05 
+$ 
+5.59 
+NGL (per Bbl) 
+$ 
+36.66 
+$ 
+38.90 
+$ 
+47.90 
+$ 
+— 
+$ 
+— 
+Expense per BOE 
+Lease operating expense 
+$ 
+4.82 
+$ 
+4.93 
+$ 
+5.30 
+$ 
+6.63 
+$ 
+8.00 
+Transportation 
+$ 
+5.34 
+$ 
+3.81 
+$ 
+3.05 
+$ 
+1.15 
+$ 
+1.14 
+Production taxes 
+$ 
+2.19 
+$ 
+2.00 
+$ 
+1.90 
+$ 
+2.86 
+$ 
+2.24 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion expense 
+$ 
+17.02 
+$ 
+19.95 
+$ 
+18.07 
+$ 
+18.33 
+$ 
+16.73 
+General and administrative 
+$ 
+3.09 
+$ 
+3.28 
+$ 
+4.19 
+$ 
+5.82 
+$ 
+4.18 
+Statement of Cash Flow Data (in millions) 
+Provided by operating activities 
+$ 
+1,338.5 
+$ 
+922.0 
+$ 
+760.5 
+$ 
+497.1 
+$ 
+436.1 
+Used in investing activities 
+$ 
+(1,192.9 
+) 
+$ 
+(1,457.3 
+) 
+$ 
+(1,264.9 
+) 
+$ 
+(361.6 
+) 
+$ 
+(304.1 
+) 
+Provided by (used in) financing activities 
+$ 
+130.7 
+$ 
+422.1 
+$ 
+618.5 
+$ 
+(141.1 
+) 
+$ 
+(127.5 
+) 
+56 
+Note: Beginning in 2011, we changed our reporting for natural gas volumes to show natural gas and NGL production volumes consistent with title transfer for each product. Rapid production growth from our NGL-rich assets associated with plant product sales contracts necessitated a change in our reporting of production volumes. Our 2010 and 2009 NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of the amounts. 
+57 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+This discussion includes forward-looking statements. Please refer to Cautionary Information about Forward-Looking Statements in Part I, Items 1 and 2 of this report for important information about these types of statements. 
+Overview of the Company 
+General Overview 
+We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America. Our assets include leading positions in the Eagle Ford shale and Bakken/Three Forks resource plays, oil-focused plays in the Permian Basin, and positions in emerging plays in East Texas and the Powder River Basin in Wyoming. We have built a portfolio of onshore properties in the contiguous United States primarily through early entry into existing and emerging resource plays. This portfolio is comprised of properties with established production and reserves, prospective drilling opportunities, and unconventional resource prospects. We believe our strategy provides for stable and predictable production and reserves growth. Furthermore, by entering these plays early, we believe we can capture larger resource potential at a lower cost. At year-end 2012, our reserves shifted from being majority gas to majority liquids. As a result, we now report equivalent volumes and per-unit metrics on a BOE basis rather than on an MCFE basis. Prior year volumes have been conformed to current year presentation. 
+Our principal business strategy is to focus on the early capture of resource plays in order to create and then enhance value for our stockholders while maintaining a strong balance sheet. We strive to leverage industry-leading exploration and leasehold acquisition teams to quickly acquire and test new resource play concepts at a reasonable cost. Once we have identified potential value through these efforts, our goal is to develop such potential through top-tier operational and project execution, and as appropriate, high-grade our portfolio by selectively divesting certain assets. We continually examine our portfolio for opportunities to improve the quality of our asset base in order to optimize our returns and preserve our financial strength. 
+In 2013 , we had the following financial and operational results: 
+• 
+At year-end 2013 , we had estimated proved reserves of 428.7 MMBOE, of which 54 percent were liquids (oil and NGLs) and 49 percent were characterized as proved developed. We added 195.5 MMBOE from our drilling program, the majority of which related to our activity in the Eagle Ford shale in South Texas and the Bakken/Three Forks plays in North Dakota. We had slight price revisions that increased our estimated proved reserves by 0.6 MMBOE. The prices used in the calculation of proved reserve estimates as of December 31, 2013 were $96.94 per Bbl, $3.67 per MMBtu, and $40.29 per Bbl, for oil, gas, and NGLs, respectively. These prices were two percent and 33 percent higher for oil and gas, respectively, and 12 percent lower for NGLs than the prices used at year-end 2012 . We had upward engineering revisions of 7.2 MMBOE related primarily to Eagle Ford shale assets, offset partially by downward engineering revisions of certain legacy assets in our Permian region. Additionally, we removed 2.8 MMBOE of proved undeveloped gas reserves mainly in our South Texas & Gulf Coast region as a result of the five-year limitation on the number of years proved undeveloped reserves may remain on the books without being developed. Please refer to the caption Proved Undeveloped Reserves under the section Reserves included in Part I, Items 1 and 2 of this report for additional discussion. We had acquisitions of 1.3 MMBOE and we divested of 18.2 MMBOE of proved reserves during the year, most of which related to the sale of our Anadarko Basin properties. We also divested of certain other assets in our Mid-Continent, Rocky Mountain, and Permian regions. 
+58 
+• 
+The PV-10 value of our estimated proved reserves was $5.5 billion as of December 31, 2013 , compared with $3.8 billion as of December 31, 2012 . The after tax value, represented by the standardized measure calculation, was $4.0 billion as of December 31, 2013 , compared with $3.0 billion as of December 31, 2012 . The standardized measure calculation is presented in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown under Reserves in Part I, Items 1 and 2 of this report. 
+• 
+We had record annual production in 2013 . Our average daily production in 2013 was 38.2 MBbls of oil, 409.2 MMcf of gas, and 26.0 MBbls of NGLs, for an average daily equivalent production rate of 132.4 MBOE, compared with 99.7 MBOE in 2012 , an increase of 33 percent year-over-year. Please refer to the caption Production Results below for additional discussion. 
+• 
+We recorded net income of $170.9 million , or $2.51 per diluted share, for the year ended December 31, 2013 . This compares with a net loss of $54.2 million , or a loss of $0.83 per diluted share, for the year ended December 31, 2012 . Please refer to the caption Comparison of Financial Results and Trends Between 2013 and 2012 below for additional discussion regarding the components of net income (loss). 
+• 
+We had record cash flow provided by operating activities of $1.3 billion for the year ended December 31, 2013 , compared with $922.0 million for the year ended December 31, 2012 , which was an increase of 45 percent year-over-year. Please refer to Analysis of cash flow changes between 2013 and 2012 below for additional discussion. 
+• 
+We received net cash proceeds (net of marketing costs, Net Profits Plan payments, legal fees, and other selling costs paid) from the sale of oil and gas properties of $424.8 million for the year ended December 31, 2013 . Please refer to Analysis of cash flow changes between 2013 and 2012 below for additional discussion. 
+• 
+EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2013 , was $1.5 billion , compared with $1.0 billion for the same period in 2012 . Please refer to the caption Non-GAAP Financial Measures below for additional discussion, including our definition of EBITDAX and reconciliations of our GAAP net income (loss) and net cash provided by operating activities to EBITDAX. 
+• 
+Costs incurred for oil and gas producing activities for the year ended December 31, 2013 , remained relatively flat at $1.7 billion when compared to the same period in 2012 . Please refer to the caption Costs Incurred in Oil and Gas Producing Activities below for additional discussion. 
+Reserve Replacement, Finding and Development Costs, and Growth 
+Like all oil and gas exploration and production companies, we face the challenge of growing proved reserves. An exploration and production company depletes part of its asset base with each unit of oil, gas, or NGL it produces. Our future growth will depend on our ability to organically and economically add reserves in excess of production. 
+59 
+The following table provides various reserve replacement and finding and development cost metrics for the year ended December 31, 2013 : 
+Reserve Replacement Percentage 
+Finding and Development Cost per BOE (1) 
+Excluding Divestitures 
+Including Divestitures 
+Excluding Divestitures 
+Including Divestitures 
+Drilling, excluding revisions 
+405 
+% 
+367 
+% 
+$ 
+7.77 
+$ 
+8.56 
+Drilling, including revisions 
+415 
+% 
+377 
+% 
+$ 
+7.57 
+$ 
+8.33 
+Drilling and acquisitions, excluding revisions 
+407 
+% 
+370 
+% 
+$ 
+7.87 
+$ 
+8.67 
+Drilling and acquisitions, including revisions 
+418 
+% 
+380 
+% 
+$ 
+7.67 
+$ 
+8.43 
+All-in 
+418 
+% 
+380 
+% 
+$ 
+8.53 
+$ 
+9.37 
+(1) Please refer to Note 12 - Acquisition and Development Agreement for discussion on how we are being carried on 90 percent of certain drilling and completion costs. 
+The following table provides average reserve replacement and finding and development cost metrics for the three-year period ended December 31, 2013 : 
+Reserve Replacement Percentage 
+Finding and Development Cost per BOE (1) 
+Excluding Divestitures 
+Including Divestitures 
+Excluding Divestitures 
+Including Divestitures 
+Drilling, excluding revisions 
+383 
+% 
+351 
+% 
+$ 
+10.58 
+$ 
+11.55 
+Drilling, including revisions 
+365 
+% 
+333 
+% 
+$ 
+11.11 
+$ 
+12.19 
+Drilling and acquisitions, excluding revisions 
+384 
+% 
+352 
+% 
+$ 
+10.62 
+$ 
+11.60 
+Drilling and acquisitions, including revisions 
+366 
+% 
+334 
+% 
+$ 
+11.15 
+$ 
+12.23 
+All-in 
+366 
+% 
+334 
+% 
+$ 
+11.98 
+$ 
+13.14 
+(1) Please refer to Note 12 - Acquisition and Development Agreement for discussion on how we are being carried on 90 percent of certain drilling and completion costs. 
+Our challenge is to grow net asset value per share, which we believe drives appreciation in our stock price over the long term. To accomplish this, we believe it is important to organically and economically replace annual production with new reserves. We believe annual reserve replacement percentages and finding and development costs are important analytical measures and are widely used by investors and industry peers in evaluating and comparing the performance of oil and gas companies. While single-year measurements have some meaning in terms of a trend, we believe aberrations, causing both positive and negative results, will occur over short intervals of time. The information used to calculate the above reserve replacement and finding and development cost metrics is included in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. For additional information about these metrics, see the reserve replacement and finding and development cost terms in the Glossary of Oil and Gas Terms at the end of Part I, Items 1 and 2 of this report. 
+Oil, Gas, and NGL Prices 
+Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. We sell the majority of our gas under contracts using first-of-the-month index pricing, which means gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day the gas is produced. For assets where high BTU gas is sold at the wellhead, we also receive additional value for the high energy content contained in the gas stream. Our NGL production is generally sold using contracts paying us a monthly average of the posted OPIS daily settlement prices, adjusted for processing, transportation, and location differentials. Our oil and condensate are sold using contracts paying us various industry posted prices, most commonly NYMEX WTI or Argus Louisiana Light Sweet (“Argus 
+60 
+LLS”). We are paid the average of the daily settlement price for the respective posted prices for the period in which the product is produced, adjusted for quality, transportation, API gravity, and location differentials. Substantially all of our oil production in our South Texas & Gulf Coast region is condensate. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period unless otherwise indicated. 
+The following table is a summary of commodity price data for the years ended December 31, 2013 , 2012 , and 2011 : 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+Crude Oil (per Bbl): 
+Average NYMEX price 
+$ 
+97.99 
+$ 
+94.10 
+$ 
+95.05 
+Realized price 
+$ 
+91.19 
+$ 
+85.45 
+$ 
+88.23 
+Natural Gas: 
+Average NYMEX price (per MMBtu) 
+$ 
+3.73 
+$ 
+2.75 
+$ 
+4.00 
+Realized price (per Mcf) 
+$ 
+3.93 
+$ 
+2.98 
+$ 
+4.32 
+NGLs (per Bbl): 
+Average OPIS price 
+$ 
+40.44 
+$ 
+44.91 
+$ 
+59.47 
+Realized price 
+$ 
+35.95 
+$ 
+37.61 
+$ 
+53.32 
+Note: Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our actual product mix for NGL production. Actual prices received for NGLs produced reflect our actual product mix. 
+We expect future prices for oil, gas, and NGLs to be volatile. In addition to supply and demand fundamentals, as a global commodity, the price of oil will continue to be impacted by real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East. The relative strength of the U.S. dollar compared to other currencies could affect the price of oil. The supply of NGLs in the U.S. is expected to continue to grow in the near term as a result of the number of industry participants targeting projects that produce these products. If demand does not keep pace with anticipated growth in NGL supply, prices could be negatively impacted. The prices of several NGL products correlate to the price of oil and accordingly are likely to directionally follow that market. Gas prices have been under sustained downward pressure due to high levels of supply in recent years, although recent cold weather has provided a near term increase in pricing. Longer term, we think there remains a large amount of productive supply, particularly in the Northeast United States, which we anticipate will keep downward pressure on natural gas pricing. The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (same product mix as discussed under the table above) as of December 31, 2013 , and February 12, 2014 : 
+As of February 12, 2014 
+As of December 31, 2013 
+NYMEX WTI oil (per Bbl) 
+$ 
+96.31 
+$ 
+95.79 
+NYMEX Henry Hub gas (per MMBtu) 
+$ 
+4.64 
+$ 
+4.19 
+OPIS NGLs (per Bbl) 
+$ 
+40.49 
+$ 
+41.17 
+61 
+While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products. Consistent with all prior periods reported, our realized prices shown in the table above do not include the impact of cash settlements from derivative contracts. 
+Derivative Activity 
+We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives. The amount of our production covered by derivatives is driven by the amount of debt on our balance sheet and the level of capital commitments and long-term obligations we have in place. With our current derivative contracts, we believe we have established a base cash flow stream for our future operations and have partially reduced our exposure to volatility in commodity prices. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil, gas, and NGL prices while also setting a price floor for a portion of our production. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional information regarding our oil, gas, and NGL derivatives. 
+The following table presents our realized prices and the effects of derivative cash settlements for the years ended December 31, 2013 , 2012 , and 2011 : 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+Crude Oil (per Bbl): 
+Realized price 
+$ 
+91.19 
+$ 
+85.45 
+$ 
+88.23 
+Effects of derivative cash settlements 
+$ 
+(1.27 
+) 
+$ 
+(1.93 
+) 
+$ 
+(9.34 
+) 
+Natural Gas (per Mcf): 
+Realized price 
+$ 
+3.93 
+$ 
+2.98 
+$ 
+4.32 
+Effects of derivative cash settlements 
+$ 
+0.21 
+$ 
+0.50 
+$ 
+0.48 
+NGLs (per Bbl): 
+Realized price 
+$ 
+35.95 
+$ 
+37.61 
+$ 
+53.32 
+Effects of derivative cash settlements 
+$ 
+0.71 
+$ 
+1.29 
+$ 
+(5.42 
+) 
+The Dodd-Frank Act included provisions requiring over-the-counter derivative transactions to be cleared through clearinghouses and traded on exchanges. On July 10, 2012, the CFTC and the SEC adopted final joint rules under Title VII of the Dodd-Frank Act, which define certain terms that determine what types of transactions will be subject to regulation under the Dodd-Frank Act swap rules. The issuance of these final rules also triggers compliance dates for a number of other final Dodd-Frank Act rules, including new rules proposed by the CFTC governing margin requirements for uncleared swaps entered into by non-bank swap entities, and new rules proposed by U.S. banking regulators regarding margin requirements for uncleared swaps entered into by bank swap entities. The ultimate effect on our business of these new rules and any additional regulations is currently uncertain. Under CFTC rules we believe our derivative activity will qualify for the non-financial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk entered into by entities predominantly engaged in non-financial activity from the mandatory swap clearing requirement. However, we are not certain whether the provisions of the final rules and regulations will exempt us from the requirements to post margin in connection with commodity price risk management activities. Final rules and regulations on major provisions of the legislation, such as new margin requirements, are to be established through regulatory rulemaking. Although we cannot predict the ultimate outcome of these rulemakings, new rules and regulations in this area may result in increased costs and cash collateral requirements for the types of derivative instruments we use to manage our financial risks related to volatility in oil, gas, and NGL commodity prices. 
+62 
+2013 Highlights 
+Production Results. The table below provides a regional breakdown of our production for 2013 : 
+South Texas & Gulf Coast 
+Rocky 
+Mountain 
+Permian 
+Mid-Continent 
+Total (1) 
+Production: 
+Oil (MMBbl) 
+5.2 
+6.4 
+1.8 
+0.5 
+13.9 
+Gas (Bcf) 
+98.5 
+5.8 
+3.6 
+41.4 
+149.3 
+NGLs (MMBbl) 
+9.2 
+— 
+— 
+0.2 
+9.5 
+Equivalent (MMBOE) (1) 
+30.9 
+7.4 
+2.4 
+7.7 
+48.3 
+Avg. Daily Equivalents (MBOE/d) 
+84.7 
+20.3 
+6.5 
+21.0 
+132.4 
+Relative percentage 
+64 
+% 
+15 
+% 
+5 
+% 
+16 
+% 
+100 
+% 
+(1) Totals may not sum or recalculate due to rounding. 
+We had record production in 2013 , which was primarily driven by the continued development of our operated and non-operated Eagle Ford shale programs in our South Texas & Gulf Coast region. Please refer to Comparison of Financial Results and Trends between 2013 and 2012 below for additional discussion on production. 
+Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows: 
+For the Year Ended December 31, 2013 
+(in millions) 
+Development costs 
+$ 
+1,350.1 
+Exploration costs 
+168.6 
+Acquisitions 
+Proved properties 
+29.9 
+Unproved properties 
+172.5 
+Total, including asset retirement obligation 
+$ 
+1,721.1 
+The majority of costs incurred for oil and gas producing activities during 2013 related to the development of our Eagle Ford shale and Bakken/Three Forks programs. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital program in 2014 . 
+Impairment of Proved Properties. We recorded impairment of proved properties expense of $172.6 million for the year ended December 31, 2013 . The impairments in 2013 were a result of negative engineering revisions on Mississippian limestone assets in our Permian region at the end of the year, a plugging and abandonment program of our Olmos interval, dry gas assets in our South Texas & Gulf Coast region, and our decision to no longer pursue the development of certain under-performing assets during the year. 
+Divestiture Activity . During 2013 , we received $445.8 million in total divestiture proceeds from divestitures of non-strategic properties, with the sale of our Anadarko Basin assets in December 2013 being the most significant transaction. Please refer to Note 3 - Divestitures and Assets Held for Sale in Part II, Item 8 of this report for additional discussion. 
+63 
+2024 Notes . During 2013 , we issued $500.0 million in aggregate principal amount of 5.0% Senior Notes. The notes were issued at par and mature on January 15, 2024 . We received net proceeds of $490.2 million from this issuance, which we used to reduce outstanding borrowings under our credit facility. Please refer to Note 5 - Long-term Debt in Part II, Item 8 of this report for additional discussion. 
+Revolving Credit Facility. On April 12, 2013 , we and our lenders entered into a Fifth Amended and Restated Credit Agreement. The credit facility has aggregate lender commitments of $1.3 billion and a maturity date of April 12, 2018 . Please refer to Overview of Liquidity and Capital Resources below for additional discussion of our credit facility. 
+Operational Activities. The primary focus of our operated drilling activity this year was oil and NGL-rich gas projects, with the majority of our 2013 capital budget being deployed to our Eagle Ford, Bakken/Three Forks and Permian development programs. We also participated in outside operated drilling activities primarily in oil and NGL-rich plays. 
+In our Eagle Ford shale program in South Texas, we operated five drilling rigs for the first half of the year. At midyear, we reduced our rig count by one due to gains in efficiencies through pad drilling, which allowed us to complete more wells per drilling rig. Our 2013 drilling program focused largely on multi-well pad drilling on the northern portions of our acreage position, which have higher condensate and NGL yields. 
+In our outside operated Eagle Ford shale program, the operator ran nine drilling rigs throughout 2013 , adding a tenth rig near the end of the year. The majority of our non-operated Eagle Ford drilling and completion costs were funded by Mitsui during 2013 under the terms of our previously announced Acquisition and Development Agreement. 
+In our Bakken/Three Forks program in the North Dakota portion of the Williston Basin, we started the year with four operated rigs. At midyear, we released two of our traditional rigs and contracted a higher efficiency walking rig. Our 2013 drilling program was focused on infill drilling of our Gooseneck and Raven/Bear Den prospects by utilizing multi-well pads to further optimize our program. 
+In the second quarter of 2013, we closed our acquisition of approximately 40,000 net acres in the Powder River Basin, and in the third quarter we acquired an additional 33,000 net acres through a trade of non-core Northern DJ Basin assets, bringing our total year-end acreage in the Powder River Basin to approximately 140,000 net acres. We dedicated one rig to the Powder River Basin in the fourth quarter of 2013, which focused on delineation of the Frontier formation. 
+During 2013, we operated between two and three drilling rigs in our Permian region. In the first half of the year, we focused on three areas: development of the Bone Spring formation in southeast New Mexico, delineation of the Mississippian limestone formation, and testing of various shale targets, including the Wolfcamp shale in the Midland Basin. As we moved into the second half of the year, our focus transitioned to primarily testing the Wolfcamp B interval on our Sweetie Peck acreage in the Midland Basin. During 2013, we acquired additional acreage in the Permian Basin bringing our total to approximately 130,000 net acres at year-end. 
+In December 2013, we closed the sale of our Mid-Continent region Anadarko Basin assets, which included our interests in the Granite Wash interval. Please see the Divestiture Activity section above for additional information. 
+64 
+Outlook for 2014 
+We enter 2014 with a planned capital program of approximately $1.9 billion, of which approximately $1.7 billion will be focused on drilling and completion activities. We expect that approximately 85 percent of our drilling budget will be spent on our Eagle Ford shale, Bakken/Three Forks, and Permian shale programs. 
+In 2014 , we plan to invest approximately $650 million of drilling and completion capital in our operated Eagle Ford shale program. Throughout 2014, we plan to operate five drilling rigs supported by two frac spreads, all of which will be primarily focused on pad drilling in the northern portion of our acreage position where there is a higher liquid contribution to our production mix. During 2014 , we plan to continue to refine our development program and well designs to optimize well performance and capital efficiency. 
+In our non-operated Eagle Ford shale program, we expect the balance of the carry amount to be exhausted in early 2014. We plan to invest approximately $250 million of un-carried drilling and completion capital in this program in 2014 based on our anticipation of increased drilling and completion activity from 2013. 
+We plan to deploy approximately $350 million of our capital budget in our Bakken/Three Forks program, 80 percent of which will be spent on operated properties. In 2014, we plan to operate three drilling rigs focusing on infill drilling of our Raven/Bear Den and Gooseneck prospects. During 2014, we plan to monitor results of various well design and down-spacing tests of both our operated and non-operated properties. 
+In our Permian program, we plan to deploy approximately $155 million of drilling and completion capital. We plan to operate two to three drilling rigs throughout 2014, focusing on horizontal testing and development of the Wolfcamp formation in our Sweetie Peck and Buffalo prospects. 
+Of the remaining $255 million of our drilling and completion capital planned for 2014, the majority will be deployed in our Powder River Basin and East Texas programs. We plan to operate two drilling rigs in the Powder River Basin targeting the Frontier formation. We plan to operate between one and three drilling rigs on our East Texas Eagle Ford shale and Woodbine acreage in 2014. The majority of this budgeted capital will be spent on our operated properties. 
+Please refer to Overview of Liquidity and Capital Resources below for additional discussion regarding how we intend to fund our 2014 capital program. 
+65 
+Financial Results of Operations and Additional Comparative Data 
+The table below provides information regarding selected production and financial information for the quarter ended December 31, 2013 , and the immediately preceding three quarters. Additional details of per BOE costs are presented later in this section. 
+For the Three Months Ended 
+December 31, 
+September 30, 
+June 30, 
+March 31, 
+2013 
+2013 
+2013 
+2013 
+(in millions, except for production data) 
+Production (MMBOE) 
+13.2 
+12.8 
+12.0 
+10.3 
+Oil, gas, and NGL production revenue 
+$ 
+593.7 
+$ 
+601.8 
+$ 
+534.5 
+$ 
+469.6 
+Lease operating expense 
+$ 
+61.1 
+$ 
+61.0 
+$ 
+56.2 
+$ 
+54.7 
+Transportation costs 
+$ 
+75.0 
+$ 
+68.8 
+$ 
+67.0 
+$ 
+47.4 
+Production taxes 
+$ 
+26.7 
+$ 
+29.1 
+$ 
+26.5 
+$ 
+23.5 
+DD&A 
+$ 
+202.6 
+$ 
+195.8 
+$ 
+225.7 
+$ 
+198.7 
+Exploration 
+$ 
+21.8 
+$ 
+16.3 
+$ 
+20.7 
+$ 
+15.4 
+General and administrative 
+$ 
+48.0 
+$ 
+33.9 
+$ 
+35.4 
+$ 
+32.3 
+Net income 
+$ 
+7.0 
+$ 
+70.7 
+$ 
+76.5 
+$ 
+16.7 
+Selected Performance Metrics: 
+For the Three Months Ended 
+December 31, 
+September 30, 
+June 30, 
+March 31, 
+2013 
+2013 
+2013 
+2013 
+Average net daily production equivalent (MBOE per day) 
+143.8 
+138.8 
+131.8 
+115.0 
+Lease operating expense (per BOE) 
+$ 
+4.62 
+$ 
+4.77 
+$ 
+4.69 
+$ 
+5.28 
+Transportation costs (per BOE) 
+$ 
+5.67 
+$ 
+5.38 
+$ 
+5.59 
+$ 
+4.58 
+Production taxes as a percent of oil, gas, and NGL production revenue 
+4.5 
+% 
+4.8 
+% 
+5.0 
+% 
+5.0 
+% 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion expense (per BOE) 
+$ 
+15.31 
+$ 
+15.33 
+$ 
+18.82 
+$ 
+19.20 
+General and administrative (per BOE) 
+$ 
+3.63 
+$ 
+2.66 
+$ 
+2.95 
+$ 
+3.12 
+Note: Amounts may not recalculate due to rounding. 
+66 
+A year-to-year overview of selected production and financial information, including trends: 
+For the Years Ended December 31, 
+Amount Change Between 
+Percent Change Between 
+2013 
+2012 
+2011 
+2013/2012 
+2012/2011 
+2013/2012 
+2012/2011 
+Net production volumes (1) 
+Oil (MMBbl) 
+13.9 
+10.4 
+8.1 
+3.6 
+2.3 
+34 
+% 
+28 
+% 
+Gas (Bcf) 
+149.3 
+120.0 
+100.3 
+29.3 
+19.7 
+24 
+% 
+20 
+% 
+NGLs (MMBbl) 
+9.5 
+6.1 
+3.5 
+3.4 
+2.6 
+55 
+% 
+75 
+% 
+Equivalent (MMBOE) 
+48.3 
+36.5 
+28.3 
+11.8 
+8.2 
+32 
+% 
+29 
+% 
+Average net daily production (1) 
+Oil (MBbl per day) 
+38.2 
+28.3 
+22.1 
+9.9 
+6.2 
+35 
+% 
+28 
+% 
+Gas (MMcf per day) 
+409.2 
+328.0 
+274.8 
+81.2 
+53.1 
+25 
+% 
+19 
+% 
+NGLs (MBbl per day) 
+26.0 
+16.7 
+9.6 
+9.3 
+7.1 
+56 
+% 
+75 
+% 
+Equivalent (MBOE per day) 
+132.4 
+99.7 
+77.5 
+32.7 
+22.2 
+33 
+% 
+29 
+% 
+Oil, gas, and NGL production revenue (in millions) 
+Oil production revenue 
+$ 
+1,271.5 
+$ 
+886.2 
+$ 
+712.8 
+$ 
+385.3 
+$ 
+173.4 
+43 
+% 
+24 
+% 
+Gas production revenue 
+586.3 
+357.7 
+433.4 
+228.6 
+(75.7 
+) 
+64 
+% 
+(17 
+)% 
+NGL production revenue 
+341.8 
+230.0 
+186.2 
+111.8 
+43.8 
+49 
+% 
+24 
+% 
+Total 
+$ 
+2,199.6 
+$ 
+1,473.9 
+$ 
+1,332.4 
+$ 
+725.7 
+$ 
+141.5 
+49 
+% 
+11 
+% 
+Oil, gas, and NGL production expense (in millions) 
+Lease operating expenses 
+$ 
+233.0 
+$ 
+180.1 
+$ 
+149.8 
+$ 
+52.9 
+$ 
+30.3 
+29 
+% 
+20 
+% 
+Transportation costs 
+258.2 
+138.9 
+86.4 
+119.3 
+52.5 
+86 
+% 
+61 
+% 
+Production taxes 
+105.8 
+72.9 
+53.9 
+32.9 
+19.0 
+45 
+% 
+35 
+% 
+Total 
+$ 
+597.0 
+$ 
+391.9 
+$ 
+290.1 
+$ 
+205.1 
+$ 
+101.8 
+52 
+% 
+35 
+% 
+Realized price 
+Oil (per Bbl) 
+$ 
+91.19 
+$ 
+85.45 
+$ 
+88.23 
+$ 
+5.74 
+$ 
+(2.78 
+) 
+7 
+% 
+(3 
+)% 
+Gas (per Mcf) 
+$ 
+3.93 
+$ 
+2.98 
+$ 
+4.32 
+$ 
+0.95 
+$ 
+(1.34 
+) 
+32 
+% 
+(31 
+)% 
+NGLs (per Bbl) 
+$ 
+35.95 
+$ 
+37.61 
+$ 
+53.32 
+$ 
+(1.66 
+) 
+$ 
+(15.71 
+) 
+(4 
+)% 
+(29 
+)% 
+Per BOE 
+$ 
+45.50 
+$ 
+40.39 
+$ 
+47.10 
+$ 
+5.11 
+$ 
+(6.71 
+) 
+13 
+% 
+(14 
+)% 
+Per BOE data 
+Production costs: 
+Lease operating expense 
+$ 
+4.82 
+$ 
+4.93 
+$ 
+5.30 
+$ 
+(0.11 
+) 
+$ 
+(0.37 
+) 
+(2 
+)% 
+(7 
+)% 
+Transportation costs 
+$ 
+5.34 
+$ 
+3.81 
+$ 
+3.05 
+$ 
+1.53 
+$ 
+0.76 
+40 
+% 
+25 
+% 
+Production taxes 
+$ 
+2.19 
+$ 
+2.00 
+$ 
+1.90 
+$ 
+0.19 
+$ 
+0.10 
+10 
+% 
+5 
+% 
+General and administrative 
+$ 
+3.09 
+$ 
+3.28 
+$ 
+4.19 
+$ 
+(0.19 
+) 
+$ 
+(0.91 
+) 
+(6 
+)% 
+(22 
+)% 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion expense 
+$ 
+17.02 
+$ 
+19.95 
+$ 
+18.07 
+$ 
+(2.93 
+) 
+$ 
+1.88 
+(15 
+)% 
+10 
+% 
+Derivative cash settlement (2) 
+$ 
+(0.42 
+) 
+$ 
+(1.32 
+) 
+$ 
+1.64 
+$ 
+0.90 
+$ 
+(2.96 
+) 
+(68 
+)% 
+(180 
+)% 
+Earnings per share information 
+Basic net income (loss) per common share 
+$ 
+2.57 
+$ 
+(0.83 
+) 
+$ 
+3.38 
+$ 
+3.40 
+$ 
+(4.21 
+) 
+410 
+% 
+(125 
+)% 
+Diluted net income (loss) per common share 
+$ 
+2.51 
+$ 
+(0.83 
+) 
+$ 
+3.19 
+$ 
+3.34 
+$ 
+(4.02 
+) 
+402 
+% 
+(126 
+)% 
+Basic weighted-average common shares outstanding (in thousands) 
+66,615 
+65,138 
+63,755 
+1,477 
+1,383 
+2 
+% 
+2 
+% 
+Diluted weighted-average common shares outstanding (in thousands) 
+67,998 
+65,138 
+67,564 
+2,860 
+(2,426 
+) 
+4 
+% 
+(4 
+)% 
+67 
+(1) Amounts and percentage changes may not recalculate due to rounding. 
+(2) Derivative cash settlements are included within the realized hedge gain (loss) and derivative gain line items in the accompanying statements of operations. 
+We present per BOE information because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis. Average daily production for the year ended December 31, 2013 , increased 33 percent compared to the same period in 2012 , driven by continued development of our Eagle Ford shale assets. 
+Changes in production volumes, revenues, and costs reflect the highly volatile nature of our industry. Our realized price on a per BOE basis for the year ended December 31, 2013 , increased 13 percent compared to the same period in 2012 due to improved oil and gas prices. 
+Lease operating expenses (“LOE”) on a per BOE basis for the year ended December 31, 2013 , decreased two percent compared to the same period in 2012 . Overall, LOE costs increased; however, production increased at a faster rate, thereby reducing LOE on a per BOE basis. We expect LOE on a per BOE basis to increase in 2014 due to an increase in ad valorem taxes primarily in our Eagle Ford shale program. 
+Transportation costs on a per BOE basis for the year ended December 31, 2013 , increased 40 percent compared to the same period in 2012 . Our Eagle Ford shale program has meaningfully higher transportation expense per unit of production compared to our other regions. Ongoing development of the Eagle Ford shale program has resulted in these assets becoming a larger portion of our total production, thereby increasing company-wide transportation expense per BOE over time. The run-rate of our per unit transportation cost in the Eagle Ford shale program increased throughout 2013 due to incremental compression charges and increased variable fuel costs associated with higher natural gas prices. Additionally, our transportation arrangements have changed over the years presented to contracts that have more favorable terms for product prices but also include higher transportation fees. We anticipate we will recognize fluctuations in our per unit Eagle Ford shale transportation run-rate over time. In 2014, we expect transportation costs per BOE to increase as Eagle Ford shale production continues to grow and constitutes a larger portion of our production mix. 
+Production taxes on a per BOE basis for the year ended December 31, 2013 , increased 10 percent compared to the same period in 2012 . This increase is a result of State of Oklahoma incentive tax rebates recorded in 2012, which decreased the 2012 BOE rate. Additionally, we received smaller incentive tax rebates on newer wells drilled in our South Texas & Gulf Coast region in 2013. We generally expect production tax expense to trend with oil, gas, and NGL revenues, however, we expect production tax expense as a percentage of revenues to slightly increase as a result of lower production tax incentives. 
+General and administrative expense on a per BOE basis for the year ended December 31, 2013 , decreased six percent compared to the same period in 2012 , as production increased at a faster rate than our general and administrative expense. A portion of our general and administrative expense is linked to our profitability and cash flow, which are driven in large part by the realized commodity prices we receive for our production. The Net Profits Plan and a portion of our short-term incentive compensation correlate with net cash flows and therefore are subject to variability. In 2014, we expect general and administrative expense on a per BOE basis will decrease, as we anticipate production will continue to increase at a faster rate than our increase in absolute general and administrative expense. 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion ( “DD&A”) expense, for the year ended December 31, 2013 , decreased 15 percent , on a per BOE basis, compared to the same period in 2012 . Our DD&A rate can fluctuate as a result of impairments, divestitures, and changes in the mix of our production and the underlying proved reserve volumes. Our DD&A rate has fallen largely as a result of lower finding and development costs, as well as through the utilization of our carry arrangement with Mitsui, which has allowed us to add reserves without incurring capital costs. Please refer to Note 12 - Acquisition and Development 
+68 
+Agreement in Part II, Item 8 of this report for additional discussion on the Mitsui transaction. Additionally, we closed our Anadarko Basin divestiture at the end of 2013. These assets were classified as held for sale at the beginning of the third quarter, and therefore, not depleted for substantially all of the last half of 2013 . We expect DD&A on a per BOE basis to be lower in 2014 due to lower anticipated finding and development costs and the sale of our Anadarko Basin assets at the end of 2013. These impacts will be slightly offset as we begin paying our portion of capital on our outside operated Eagle Ford assets as a result of our remaining carry amount with Mitsui being exhausted in early 2014. 
+Please refer to Comparison of Financial Results and Trends between 2013 and 2012 for additional discussion on oil, gas, and NGL production expense, DD&A, and general and administrative expense. 
+Please refer to the section Earnings per Share in Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of this report for additional discussion on the types of shares included in our basic and diluted net income (loss) per common share calculations. We recorded a net loss for the year ended December 31, 2012 . Consequently, our in-the-money stock options, unvested RSUs, and contingent PSUs were anti-dilutive for the year ended December 31, 2012 , resulting in an increase in the diluted weighted-average common shares outstanding between the two periods. 
+Comparison of Financial Results and Trends between 2013 and 2012 
+Oil, gas, and NGL production. The following table presents the regional changes in our production and oil, gas, and NGL production revenues and production costs between the years ended December 31, 2013 , and 2012 : 
+Average Net Daily Production Added (Lost) 
+Oil, Gas & NGL Revenue Added 
+Production Costs Increase (Decrease) 
+(MBOE/d) 
+(in millions) 
+(in millions) 
+South Texas & Gulf Coast 
+33.4 
+$ 
+515.5 
+$ 
+159.2 
+Rocky Mountain 
+3.4 
+136.6 
+28.7 
+Permian 
+1.4 
+51.6 
+19.4 
+Mid-Continent 
+(5.5 
+) 
+22.0 
+(2.2 
+) 
+Total 
+32.7 
+$ 
+725.7 
+$ 
+205.1 
+The largest regional production increase occurred in our South Texas & Gulf Coast region as a result of drilling activity in our Eagle Ford shale program. Production in our Eagle Ford shale program continues to increase and we expect it to continue to do so through 2014. The increase in oil and gas prices caused an increase in oil, gas, and NGL production revenue in our Mid-Continent region between the years ended December 31, 2013, and 2012, despite a decrease in production volumes attributable to base decline. 
+The following table summarizes the realized prices we received in 2013 and 2012 , before the effects of derivative cash settlements: 
+For the Years Ended December 31, 
+2013 
+2012 
+Realized oil price ($/Bbl) 
+$ 
+91.19 
+$ 
+85.45 
+Realized gas price ($/Mcf) 
+$ 
+3.93 
+$ 
+2.98 
+Realized NGL price ($/Bbl) 
+$ 
+35.95 
+$ 
+37.61 
+Realized equivalent price ($/BOE) 
+$ 
+45.50 
+$ 
+40.39 
+69 
+A 32 percent increase in production on an equivalent basis combined with a 13 percent increase in realized price per BOE resulted in a 49 percent increase in revenue between the two periods. Based on current levels of drilling and completion activity, we expect production volumes to continue to increase through 2014 on a retained properties basis. We also expect our realized prices to trend with commodity prices. 
+Realized hedge (loss) gain. We recorded a net realized hedge loss of $1.8 million for the year ended December 31, 2013 , compared with a net realized hedge gain of $3.9 million for the same period in 2012 . These amounts are comprised of realized cash settlements on commodity derivative contracts that were designated as cash flow hedges and were previously recorded in accumulated other comprehensive income (loss) (“AOCIL”). During 2013 , all gains and losses associated with commodity derivative contracts that had previously been designated as cash flow hedges were reclassified into earnings from AOCIL. Our realized oil, gas, and NGL hedge gains and losses are a function of commodity prices at the time of settlement compared with the respective derivative contract prices. 
+Gain (loss) on divestiture activity. We recorded a net gain on divestiture activity of $28.0 million for the year ended December 31, 2013 , compared with a net loss of $27.0 million for the comparable period of 2012 . The net gain on divestiture activity for the year ended December 31, 2013 , is largely due to gains recorded on the divestiture of certain assets in our Mid-Continent and Rocky Mountain regions slightly offset by a loss recorded on the divestiture of non-strategic assets in our Permian region. The net loss for the year ended December 31, 2012 , was due to an unsuccessful property sale effort and the corresponding write-down of those assets held for sale to their fair value. This loss was partially offset by a net gain on completed divestitures. We will continue to evaluate our portfolio to determine whether there are non-strategic properties we could divest. Please refer to Note 3 - Divestitures and Assets Held for Sale in Part II, Item 8 of this report for additional discussion. 
+Marketed gas system revenue and expense. Marketed gas system revenue increased to $60.0 million for the year ended December 31, 2013 , compared with $52.8 million for the comparable period of 2012 , as a result of an increase in gas prices. Concurrent with the increase in marketed gas system revenue, marketed gas system expense increased to $57.6 million for the year ended December 31, 2013 , from $47.6 million for the comparable period of 2012 . The decrease in our net margin is due to an increase in gathering fees paid to third parties, which went into effect in the second half of 2012. We expect that marketed gas system revenue and expense will decrease in 2014 as a result of our Anadarko Basin divestiture, although we expect our margin to be consistent with the margin realized in 2013. Further, we expect marketed gas revenue and expense to continue to correlate with changes in production on retained properties and our realized gas price. 
+Oil, gas, and NGL production expense. Total production costs increased $205.1 million , or 52 percent , to $597.0 million for the year ended December 31, 2013 , compared with $391.9 million in 2012 , primarily due to a 32 percent increase in production volumes on a per BOE basis, as well as an overall increase in transportation costs in our South Texas & Gulf Coast region. Please refer to our caption A year-to-year overview of selected production and financial information, including trends above for discussion of production costs on a per BOE basis. 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A expense increased 13 percent to $822.9 million in 2013 compared with $727.9 million in 2012 , as a result of the continued development of our Eagle Ford and Bakken/Three Forks assets and the associated growth in our production, partially offset by the sale of our Anadarko Basin properties that were classified as held for sale at the beginning of the third quarter of 2013. Please refer to our caption A year-to-year overview of selected production and financial information, including trends above for discussion of DD&A expense on a per BOE basis. 
+70 
+Exploration. The components of exploration expense are summarized as follows: 
+For the Years Ended December 31, 
+2013 
+2012 
+Summary of Exploration Expense 
+(in millions) 
+Geological and geophysical expenses 
+$ 
+4.3 
+$ 
+13.6 
+Exploratory dry hole 
+5.8 
+20.9 
+Overhead and other expenses 
+64.0 
+55.7 
+Total 
+$ 
+74.1 
+$ 
+90.2 
+Exploration expense for 2013 decreased 18 percent compared with the same period in 2012 as a result of decreased geological and geophysical expenses (“G&G”) due to a large seismic study conducted in the first quarter of 2012 and fewer exploratory dry holes expensed in 2013 , partially offset by an increase in exploration overhead in 2013 mainly due to an increase in performance-based compensation. An exploratory project resulting in non-commercial quantities of oil, gas, or NGLs is deemed an exploratory dry hole and impacts the amount of exploration expense we record. We currently expect to expand our exploration program in 2014, which will create increased potential for exploratory dry holes. 
+Impairment of proved properties. We recorded impairment of proved properties expense of $172.6 million for the year ended December 31, 2013 . The impairments in 2013 were a result of negative engineering revisions on our Mississippian limestone assets in our Permian region at the end of the year, the commencement of a plugging and abandonment program of dry gas assets in the Olmos interval in our South Texas & Gulf Coast region, and our decision to no longer pursue the development of certain under-performing assets during the year. We recorded impairment of proved properties expense of $208.9 million for the comparable period in 2012 related to write-downs of our Wolfberry assets in our Permian region due to downward engineering revisions, as well as write-downs of our Haynesville shale assets due to low natural gas prices. Future crude oil, natural gas, and NGL price declines, downward engineering revisions, or unsuccessful exploration efforts may result in proved property impairments. 
+Abandonment and impairment of unproved properties. We recorded abandonment and impairment of unproved properties expense of $46.1 million for the year ended December 31, 2013 , the majority of which related to acreage we no longer intend to develop in our Permian region. We recorded $16.3 million of abandonment and impairment of unproved properties expense for the comparable period in 2012 , the majority of which related to acreage we no longer intended to develop in our Rocky Mountain and Mid-Continent regions. Abandonment and impairment of unproved properties is more likely occur in periods of low commodity prices, which negatively impact operating cash flows available for exploration and development, as well as anticipated economic performance. 
+General and administrative. General and administrative expense increased to $149.6 million for the year ended December 31, 2013 , compared with $119.8 million for the same period in 2012 . The increase is due to an increase in performance-based compensation that reflects we exceeded our performance metrics when compared to the prior year, as well as an increase in employee headcount during 2013 , which resulted in increased base compensation, benefits, and general corporate office expenses. These were slightly offset by an increase in COPAS overhead reimbursement as a result of an increase in operated well count. Please refer to our caption A year-to-year overview of selected production and financial information, including trends above for discussion of general and administrative costs on a per BOE basis. 
+71 
+Change in Net Profits Plan liability. This non-cash expense generally relates to the change in the estimated value of the associated liability between the reporting periods. For 2013 , we recorded a non-cash benefit of $21.8 million compared to a non-cash benefit of $28.9 million in 2012 . The change in our liability is subject to estimation and may change dramatically from period to period based on assumptions used for production rates, reserve quantities, commodity pricing, discount rates, and production costs. We expect the change in our Net Profits Plan liability to correlate with fluctuations in commodity prices. 
+Derivative gain. We recognized a derivative gain of $3.1 million for the year ended December 31, 2013 , and a gain of $55.6 million for the same period in 2012 . These amounts include the change in fair value of commodity derivative contracts and cash settlement gains or losses. For the year ended December 31, 2013, we recognized a net gain on cash settlements, which was offset largely by a decrease in the fair value of our gas commodity derivative contracts as strip prices increased. Please refer to Note 10 - Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion. 
+Other operating expense. Other operating expense was $30.1 million in 2013 compared with $7.0 million in 2012 . In 2013 , other operating expense included $23.1 million of expense related to an agreed clarification concerning royalty payment provisions of various leases on certain South Texas & Gulf Coast acreage. 
+Income tax benefit (expense). We recorded income tax expense of $107.7 million for 2013 compared to income tax benefit of $29.3 million for 2012 , resulting in effective tax rates of 38.6 percent and 35.0 percent , respectively. The 2013 rate increase resulted primarily from the Anadarko Basin divestiture that closed at the end of the year, which caused a shift in anticipated recognition of future state tax benefits from a state with a higher applicable state rate to states with lower applicable rates. A combination of lower enacted state income tax rates during the year and a shift between states of our anticipated future apportioned income caused a decrease in our overall state rate which partially offset the increase. Other factors impacting our effective tax rate between tax years include decreased impact for valuation allowances, a decreased impact in benefit from the research and development (“R&D”) credit, and to a much lesser extent, net decreases resulting from the differing effects of percentage depletion and other permanent differences. Our current income tax expense in 2013 was $2.1 million compared with $370,000 in 2012 , which is attributable to increasing activity in the state of Texas and effects of permanent differences associated with the Texas Margin Tax. 
+Although federal legislation was passed extending the R&D credit for the tax years 2012 and 2013, we are awaiting the outcome of our IRS appeal for R&D credits claimed during the 2007 through 2010 tax years to determine whether we can efficiently commit the additional resources necessary for engaging a study to calculate a credit for those and future years. As of the filing date of this report, the R&D credit has not been extended for the 2014 tax year. Even without recording the cumulative effect of a R&D credit in 2014, we anticipate our normalized tax rate will be lower in 2014. 
+Comparison of Financial Results between 2012 and 2011 
+Effective January 1, 2012, we combined our former ArkLaTex region with our Mid-Continent region, based in Tulsa, Oklahoma, for operational and reporting purposes. 
+Oil, gas and NGL production. The following table presents the regional changes in our production and oil, gas, and NGL production revenues and production costs between the years ended December 31, 2012 and 2011 : 
+72 
+Average Net Daily Production Added (Lost) 
+Oil, Gas & NGL Revenue Added (Lost) 
+Production Costs Increase 
+(MBOE/d) 
+(in millions) 
+(in millions) 
+South Texas & Gulf Coast 
+19.5 
+$ 
+137.0 
+$ 
+68.9 
+Rocky Mountain 
+4.6 
+113.1 
+26.1 
+Permian 
+(0.1 
+) 
+(16.5 
+) 
+4.5 
+Mid-Continent 
+(1.8 
+) 
+(92.1 
+) 
+2.3 
+Total 
+22.2 
+$ 
+141.5 
+$ 
+101.8 
+The largest regional production increase occurred in our South Texas & Gulf Coast region as a result of drilling activity in our Eagle Ford shale program. We also saw an increase in production in our Rocky Mountain region as a result of strong production performance from wells drilled in our Bakken/Three Forks program in late 2011 and throughout 2012 . 
+The following table summarizes the average realized prices we received in 2012 and 2011 , before the effects of derivative cash settlements: 
+For the Years Ended December 31, 
+2012 
+2011 
+Realized oil price ($/Bbl) 
+$ 
+85.45 
+$ 
+88.23 
+Realized gas price ($/Mcf) 
+$ 
+2.98 
+$ 
+4.32 
+Realized NGL price ($/Bbl) 
+$ 
+37.61 
+$ 
+53.32 
+Realized equivalent price ($/BOE) 
+$ 
+40.39 
+$ 
+47.10 
+A 29 percent increase in production on an equivalent basis combined with a 14 percent decrease in realized price per BOE resulted in an 11 percent increase in revenue between the two periods. 
+Realized hedge (loss) gain. We recorded a net realized hedge gain of $3.9 million for the year ended December 31, 2012 , compared with a net realized hedge loss of $20.7 million for the same period in 2011 . Please refer to Comparison of Financial Results and Trends between 2013 and 2012 above for additional discussion on this financial statement line item. 
+Gain (loss) on divestiture activity. We recorded a net loss on divestiture activity of $27.0 million for the year ended December 31, 2012 , due largely to a loss on unsuccessful property sale efforts and the write-down of certain assets held for sale to their fair value. We recorded a net gain of $220.7 million for the comparable period of 2011 , related to the divestitures of oil and gas properties located in our South Texas & Gulf Coast, Rocky Mountain, and Mid-Continent regions. 
+Marketed gas system revenue and expense. Marketed gas system revenue decreased to $52.8 million for the year ended December 31, 2012 , compared with $69.9 million for the comparable period of 2011 , as a result of lower production in the Mid-Continent region and declining gas prices. Concurrent with the decrease in marketed gas system revenue, marketed gas system expense decreased to $47.6 million for the year ended December 31, 2012 , from $64.2 million for the comparable period of 2011 . There was no significant change in our net margin. 
+Oil and gas production expense. Total production costs increased $101.8 million , or 35 percent , to $391.9 million for the year ended December 31, 2012 , compared with $290.1 million in 2011 , primarily due to a 29 percent increase in net production volumes on an equivalent basis. 
+73 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A expense increased 42 percent to $727.9 million in 2012 , compared with $511.1 million in 2011 , due to an increase in our depreciable asset base as a result of continued development of our Eagle Ford and Bakken/Three Forks assets and the associated growth of our production. 
+Exploration. The components of exploration expense are summarized as follows: 
+For the Years Ended December 31, 
+2012 
+2011 
+Summary of Exploration Expense 
+(in millions) 
+Geological and geophysical expenses 
+$ 
+13.6 
+$ 
+7.3 
+Exploratory dry hole 
+20.9 
+0.3 
+Overhead and other expenses 
+55.7 
+45.9 
+Total 
+$ 
+90.2 
+$ 
+53.5 
+Exploration expense for 2012 increased 69 percent compared with the same period in 2011 as a result of wells categorized as exploratory being classified as dry during the year, as well as an increase in exploration overhead and G&G expenses. The increase in G&G expenses was due to a large seismic study conducted in the first quarter of 2012 , while the increase in overhead and other expenses was due to an increase in our exploration efforts. 
+Impairment of proved properties. We recorded impairment of proved properties expense of $208.9 million for the year ended December 31, 2012 . The impairments were a result of write-downs of our Wolfberry assets in our Permian region due to downward engineering revisions, as well as write-downs of our Haynesville shale assets due to low natural gas prices. We recorded impairment of proved properties expense of $219.0 million for the comparable period in 2011 , related to legacy assets located in our Mid-Continent region as a result of depressed natural gas prices. 
+Abandonment and impairment of unproved properties. We recorded abandonment and impairment of unproved properties expense of $16.3 million for the year ended December 31, 2012 , the majority of which related to acreage we no longer intend to develop in our Rocky Mountain and Mid-Continent regions. We recorded $7.4 million of abandonment and impairment of unproved properties expense for the comparable period in 2011 , primarily associated with lease expirations in our Mid-Continent region. 
+General and administrative. General and administrative expense increased slightly to $119.8 million for the year ended December 31, 2012 , compared with $118.5 million for the same period in 2011 . The change is due to an increase in employee headcount in 2012 , which resulted in an increase to base compensation, benefits, and general corporate office expenses incurred. These were mostly offset by an increase in COPAS overhead reimbursement as a result of an increase in operated well count, as well as an overall decrease in accruals for cash bonus that reflect less success at reaching performance metrics when compared with the prior year. 
+Change in Net Profits Plan liability. For 2012 , we recorded a non-cash benefit of $28.9 million compared to a non-cash benefit of $25.5 million in 2011 . These non-cash benefits are directly related to the change in the estimated value of the associated liability between the reporting periods. Please refer to Note 11 - Fair Value Measurements in Part II, Item 8 of this report for the impact a direct payment made to cash-out several pools had on our change in the Net Profits Plan liability in 2011 . 
+74 
+Derivative gain. We recognized a derivative gain of $55.6 million in 2012 compared to a gain of $37.1 million for the same period in 2011 . Declining commodity prices in both periods resulted in favorable derivative positions and settlements. The 2011 amount includes gains resulting from unrealized changes in fair value on commodity derivative contracts of $62.8 million and realized cash settlement losses on derivatives for which unrealized changes in fair value were not previously recorded in other comprehensive loss of $25.7 million. Please refer to Note 10 - Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion. 
+Other operating expense. Other operating expense was $7.0 million in 2012 compared with $17.6 million in 2011 . The decrease is a result of commissions and legal costs incurred in 2011 associated with our Acquisition and Development Agreement with Mitsui, as well as legal costs incurred related to the arbitration proceedings involving Anadarko E&P Company, LP during the second half of 2011 . Please refer to Note 12 - Acquisition and Development Agreement, in Part II, Item 8 of this report for additional discussion of our Acquisition and Development Agreement. 
+Income tax benefit (expense). We recorded an income tax benefit of $29.3 million for 2012 compared to an expense of $123.6 million for 2011 , resulting in effective tax rates of 35.0 percent and 36.5 percent , respectively. The net decrease in the rate reflects differences in the effects of individual components of our tax rate between years. Comparable valuation allowance amounts recorded on state net operating losses and charitable contributions in each of the two years had the effect of increasing the 2011 rate of expense while decreasing the 2012 benefit rate. The impacts from these two items were mostly offset by the effect from recognized R&D credit benefits. Other 2012 net decreases in the effective rate resulted from changes in the mix of the highest marginal state tax rates, the differing effects from percentage depletion and other permanent differences. The current income tax expense in 2012 was $370,000 compared with the income tax benefit of $204,000 in 2011 , which included a federal carryback amount. 
+Overview of Liquidity and Capital Resources 
+We believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future. We continue to manage the duration and level of our drilling and completion service commitments in order to provide flexibility to reduce activity and capital expenditures in periods of prolonged commodity price decline. 
+Sources of cash 
+We currently expect our 2014 capital program to be funded by cash flows from operations and proceeds from divestitures that closed during the fourth quarter of 2013 , with any shortfall to be funded by borrowings under our credit facility. Although we anticipate that cash flows from these sources will be sufficient to fund our expected 2014 capital program, we may also elect to access the capital markets, depending on prevailing market conditions. The divestiture of oil and gas properties is also a potential source of funding and we will continue to evaluate our portfolio to identify potential divestiture candidates. 
+Our primary sources of liquidity are the cash flows provided by our operating activities, borrowings under our credit facility, proceeds received from divestitures of properties, and other financing alternatives, including accessing capital markets. From time to time, we may enter into carrying cost funding and sharing arrangements with third parties for particular exploration and/or development programs. All of our sources of liquidity can be impacted by the general condition of the broader economy and by fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and our industry. We have no control over market prices for oil, gas, or NGLs, although we are able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. Historically, decreases in commodity prices have limited our industry’s access to capital markets. The borrowing base under our credit facility could be reduced as a result of lower commodity prices, divestitures of proved properties, or newly issued debt. See Credit Facility below for a discussion of the amendment and extension to our credit facility during the second quarter of 2013. 
+75 
+In the second quarter of 2013, we issued $500.0 million in aggregate principal amount of 2024 Notes and used the net proceeds to reduce outstanding amounts under our credit facility. In late 2011, we consummated our Acquisition and Development Agreement with Mitsui pursuant to which Mitsui funds, or carries, 90 percent of certain drilling and completion costs attributable to our remaining interest in our non-operated Eagle Ford shale acreage until $680.0 million has been expended on our behalf. Of the original $680.0 million carry amount, $573.8 million had been spent as of December 31, 2013 . The remaining carry is expected to be realized in early 2014. Please refer to Note 12 - Acquisition and Development Agreement in Part II, Item 8 of this report for additional discussion. 
+Proposals for reform of the United States Internal Revenue Code and discussions regarding funding the federal government budget include eliminating or reducing current tax deductions for intangible drilling costs, depreciation of equipment acquisition costs, the domestic production activities deduction, and percentage depletion. Legislation modifying or eliminating these deductions would be expected to reduce net operating cash flows over time, thereby reducing funding available for our exploration and development capital programs and those of our peers in the industry. If enacted, these funding reductions could have a significant adverse effect on drilling in the United States for a number of years. 
+Credit facility 
+During the second quarter of 2013, we and our lenders entered into our Fifth Amended and Restated Credit Agreement, which replaced our previous credit facility. The credit facility has a maximum loan amount of $2.5 billion , current aggregate lender commitments of $1.3 billion , and a maturity date of April 12, 2018 . The borrowing base under the credit facility as of the filing date of this report is $2.2 billion and is subject to regular semi-annual re-determinations. We believe the current commitment amount is sufficient to meet our anticipated liquidity and operating needs. No individual bank participating in our credit facility represents more than 10 percent of the lending commitments under the credit facility. Please refer to Note 5 - Long-term Debt in Part II, Item 8 of this report for additional discussion as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under our credit facility as of February 12, 2014 , December 31, 2013 , and December 31, 2012 . 
+We are subject to customary covenants under our credit facility, including limitations on dividend payments and requirements to maintain certain financial ratios, which include debt to EBITDAX, as defined by our credit agreement as the ratio of debt to 12-month trailing EBITDAX, of less than 4.0 and an adjusted current ratio, as defined by our credit agreement, of no less than 1.0. Please refer to the caption Non-GAAP Financial Measures below for our definition of EBITDAX. As of December 31, 2013 , our debt to EBITDAX ratio and adjusted current ratio were 1.1 and 3.1 , respectively. As of the filing date of this report, we are in compliance with all financial and non-financial covenants under our credit facility. 
+Our daily weighted-average credit facility debt balance was approximately $192.4 million and $171.8 million for the years ended December 31, 2013 , and 2012 , respectively. We used the proceeds from our 2024 Notes to reduce our credit facility balance at the end of the second quarter of 2013. Our average credit facility balance was lower throughout 2012 as a result of the use of proceeds from our 2021 Notes, issued at the end of 2011, and our 2023 Notes, issued at the end of the second quarter of 2012, to pay down our credit facility balance. Cash flows provided by our operating activities, proceeds received from divestitures of properties, and the amount of our capital expenditures also impact the amount we have borrowed under our credit facility. 
+Weighted-average interest rates 
+Our weighted-average interest rates include both paid and accrued interest payments, cash fees on the unused portion of the credit facility’s aggregate commitment amount, letter of credit fees, and amortization of deferred financing costs. Additionally, our 2012 weighted-average interest rate includes amortization of the debt discount related to our 3.50% Senior Convertible Notes due 2027 (the “3.50% Senior Convertible Notes”). Our weighted-average borrowing rate is calculated using only our paid and accrued interest . 
+76 
+The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the years ended December 31, 2013 , 2012 , and 2011 . 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+Weighted-average interest rate 
+6.3 
+% 
+6.4 
+% 
+8.5 
+% 
+Weighted-average borrowing rate 
+5.7 
+% 
+5.5 
+% 
+5.2 
+% 
+Our weighted-average interest rates and weighted average borrowing rates for the years ended December 31, 2013, 2012, and 2011, have been impacted by the issuance of the 2019 Notes in the first quarter of 2011, the issuance of the 2021 Notes in the fourth quarter of 2011, the settlement of our 3.50% Senior Convertible Notes in the second quarter of 2012, the issuance of the 2023 Notes in the second quarter of 2012, and the issuance of the 2024 Notes in the second quarter of 2013. Each of these events impacted the average balance on our revolving credit facility, the average interest rate on our non-bank debt, as well as the fees paid on the unused portion of our aggregate commitment. 
+Uses of cash 
+We use cash for the acquisition, exploration, and development of oil and gas properties and for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the exploration and development of oil and gas properties are the primary use of our capital resources. During 2013 , we spent $1.6 billion for exploration and development capital activities and proved and unproved oil and gas property acquisitions. These amounts differ from the cost incurred amounts, which are accrual-based and include asset retirement obligation, G&G, and exploration overhead amounts. 
+The amount and allocation of future capital expenditures will depend upon a number of factors, including the number and size of available acquisition and drilling opportunities, our cash flows from operating, investing, and financing activities, and our ability to assimilate acquisitions and execute our drilling program. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, and the timing and results of our operated and non-operated development and exploratory activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget to assess changes in current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. 
+We may from time to time repurchase certain amounts of our outstanding debt securities for cash and/or through exchanges for other securities. Such repurchases or exchanges may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or exchanges will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. 
+As of the filing date of this report, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility, the indentures governing our Senior Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors reviews this program as part of the allocation of our capital. During 2013 , we did not repurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares. 
+77 
+During 2013 , we paid $6.7 million in dividends to our stockholders, which constitutes a dividend of $0.10 per share. Our intention is to continue to make dividend payments for the foreseeable future, subject to our future earnings, our financial condition, credit facility and other covenants, and other factors which could arise. Payment of future dividends remains at the discretion of our Board of Directors. 
+The following table presents changes in cash flows between the years ended December 31, 2013 , 2012 , and 2011 , for our operating, investing, and financing activities. The analysis following the table should be read in conjunction with our statements of cash flows in Part II, Item 8 of this report. 
+For the Years Ended 
+December 31, 
+Amount of Changes Between 
+Percent of Change Between 
+2013 
+2012 
+2011 
+2013/2012 
+2012/2011 
+2013/2012 
+2012/2011 
+(in millions) 
+Net cash provided by operating activities 
+$ 
+1,338.5 
+$ 
+922.0 
+$ 
+760.5 
+$ 
+416.5 
+$ 
+161.5 
+45 
+% 
+21 
+% 
+Net cash used in investing activities 
+$ 
+(1,192.9 
+) 
+$ 
+(1,457.3 
+) 
+$ 
+(1,264.9 
+) 
+$ 
+264.4 
+$ 
+(192.4 
+) 
+(18 
+)% 
+15 
+% 
+Net cash provided by financing activities 
+$ 
+130.7 
+$ 
+422.1 
+$ 
+618.5 
+$ 
+(291.4 
+) 
+$ 
+(196.4 
+) 
+(69 
+)% 
+(32 
+)% 
+Analysis of cash flow changes between 2013 and 2012 
+Operating activities. Cash received from oil, gas, and NGL production revenues, including derivative cash settlements, increased $652.6 million , or 43 percent , to $2.2 billion for the year ended December 31, 2013 , compared with the same period in 2012 . This increase was due to an increase in production volumes and an increase in our adjusted realized price. Cash paid for lease operating expenses in 2013 increased $54.5 million from 2012 due to increased production. Cash paid for interest, net of capitalized interest, during 2013 increased $19.4 million compared with the same period in 2012 due to interest paid on our 2023 Notes in the first and third quarters of 2013 , offset partially by interest no longer paid on the 3.50% Senior Convertible Notes that we settled in April 2012. 
+Investing activities. Net proceeds from the sale of oil and gas properties in 2013 increased $369.5 million compared to the same period in 2012 due largely to the sale of our Anadarko Basin assets in the fourth quarter of 2013. Capital expenditures in 2013 , including costs to acquire proved and unproved oil and gas properties, increased $101.5 million , or seven percent , compared with the same period in 2012 . This increase is primarily the result of our completed acquisition of proved and unproved properties in our Rocky Mountain region in the second quarter of 2013 . 
+Financing activities. We received $490.2 million of net proceeds from the issuance of our 2024 Notes in 2013 , compared with $392.1 million of net proceeds from the issuance of our 2023 Notes in 2012 . These proceeds were used to reduce our outstanding credit facility balance. We had net payments under our credit facility of $340.0 million during the year ended December 31, 2013 , compared with net borrowings of $340.0 million during the same period in 2012 . During the second quarter of 2012 , we paid $287.5 million to settle our 3.50% Senior Convertible Notes. 
+Analysis of cash flow changes between 2012 and 2011 
+Operating activities. Cash received from oil, gas, and NGL production revenues, including derivative cash settlements, increased $256.5 million, or 21 percent, to $1.5 billion for the year ended December 31, 2012 , compared with the same period in 2011 . This increase was due to an increase in production volumes and favorable derivative settlements resulting from declining commodity prices throughout the year. Cash paid for lease operating expenses in 2012 increased $28.4 million compared with 2011 due to increased production and higher service costs caused by increased demand for those services. Cash paid for interest, net of capitalized interest, during 2012 
+78 
+increased $29.2 million compared with the same period in 2011 due to interest payments on our 2019 Notes and 2021 Notes, as well as an increase in interest payments under our credit facility arising from an increase in our weighted average outstanding balance for the year. 
+Investing activities. Capital expenditures in 2012 decreased $125.3 million , or eight percent , compared with the same period in 2011 . This decrease was a result of being carried for substantially all of our drilling and completion costs in our outside operated Eagle Ford program. Net proceeds from the sale of oil and gas properties decreased $309.1 million between the two periods due to a decrease in divestiture activity in 2012 . 
+Financing activities. During 2012 , we paid $287.5 million to settle our 3.50% Senior Convertible Notes. We received $392.1 million of net proceeds from the issuance of our 2023 Notes in 2012 , compared with $684.2 million of proceeds from the issuance of our 2019 Notes and 2021 Notes in 2011 . We had net borrowings under our credit facility of $340.0 million during 2012 , compared with net repayments of $48.0 million during 2011 . 
+Interest Rate Risk 
+We are exposed to market risk due to the floating interest rate on our revolving credit facility. Our credit agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes affect the credit facility’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of the credit facility that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Notes, but can impact their fair market values. As of December 31, 2013 , our fixed-rate debt outstanding totaled $1.6 billion . As of December 31, 2013 , we had no floating-rate debt outstanding, thus we had no exposure to market risk related to floating interest rates at that date. 
+Commodity Price Risk 
+The prices we receive for our oil, gas, and NGL production heavily impacts our revenue, overall profitability, access to capital and future rate of growth. Oil, gas, and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, gas, and NGLs have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Based on our 2013 production, a 10 percent decrease in our average realized price received for oil, gas, and NGLs would have reduced our oil, gas, and NGL production revenues by $127.1 million , $58.6 million , and $34.2 million , respectively. 
+79 
+The fair values of our commodity derivative contracts are largely determined by estimates of the forward curves of the relevant price indices. At December 31, 2013 , a 10 percent increase and 10 percent decrease in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by the following amounts: 
+10% Increase 
+10% Decrease 
+(in millions) 
+Gain/(loss): 
+Oil derivatives 
+$ 
+(151.0 
+) 
+$ 
+144.7 
+Gas derivatives 
+$ 
+(103.6 
+) 
+$ 
+103.7 
+NGL derivatives 
+$ 
+(15.5 
+) 
+$ 
+15.5 
+We enter into commodity derivative contracts in order to reduce the impact of fluctuations in commodity prices. Please refer to Note 10 – Derivative Financial Instruments of Part II, Item 8 of this report for additional information about our oil, gas, and NGL derivative contracts . 
+Schedule of Contractual Obligations 
+The following table summarizes our contractual obligations at December 31, 2013 , for the periods specified (in millions): 
+Contractual Obligations 
+Total 
+Less than 1 year 
+1-3 years 
+3-5 years 
+More than 5 years 
+Long-term debt (1) 
+$ 
+1,600.0 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+1,600.0 
+Interest payments (2) 
+843.9 
+105.7 
+203.6 
+200.1 
+334.5 
+Delivery commitments (3) 
+1,070.9 
+112.6 
+263.8 
+247.0 
+447.5 
+Operating leases and contracts (3) 
+142.7 
+66.5 
+27.8 
+14.0 
+34.4 
+Derivative liability (4) 
+31.0 
+26.4 
+4.5 
+0.1 
+— 
+Net Profits Plan (5) 
+59.4 
+14.3 
+21.5 
+16.8 
+6.8 
+Asset retirement obligations (6) 
+121.2 
+25.8 
+9.4 
+5.3 
+80.7 
+Other (7) 
+21.5 
+4.5 
+10.6 
+6.0 
+0.4 
+Total 
+$ 
+3,890.6 
+$ 
+355.8 
+$ 
+541.2 
+$ 
+489.3 
+$ 
+2,504.3 
+(1) Long-term debt consists of our Senior Notes and the outstanding balance under our long-term revolving credit facility, and assumes no principal repayment until the due dates of the instruments. The actual payments under our revolving credit facility may vary significantly. 
+(2) Interest payments on our Senior Notes are estimated assuming no principal repayment until the due dates of the instruments. No interest payments have been estimated on our credit facility due to its zero balance as of December 31, 2013 . However, commitment fees paid on the unused portion of the aggregate commitment amount have been estimated through the credit facility maturity date of April 12, 2018 , and included in the table above. 
+(3) Please refer to Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional discussion regarding our operating leases, contracts, and gathering, processing, and transportation through-put commitments. 
+80 
+(4) Amount shown represents only the liability portion of the marked-to-market value of our commodity derivatives based on future market prices at December 31, 2013 , and excludes estimated oil, gas, and NGL commodity derivative receipts. This amount varies from the liability amounts presented on the accompanying balance sheets, as those amounts are presented at fair value, which considers time value, volatility, and the risk of non-performance for us and for our counterparties. The ultimate settlement amounts under our derivative contracts are unknown, as they are subject to continuing market risk and commodity price volatility. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion regarding our derivative contracts. 
+(5) Amount shown represents undiscounted forecasted payments for the Net Profits Plan for the next six years. Payments are expected to gradually decrease for the years beyond what are shown in this table and are not included due to these payments being highly variable, as outlined below. The amount recorded on the accompanying balance sheets reflects all future Net Profits Plan payments and the impact of discounting, and therefore differs from the amounts disclosed in this table. The variability in the amount of payments will be a direct reflection of commodity prices, production rates, capital expenditures, and operating costs in future periods. Predicting the timing and amounts of payments associated with this liability is contingent upon estimates of appropriate discount factors, adjusting for risk and time value, and upon a number of factors we cannot control. Please refer to Note 7 – Compensation Plans and Note 11 - Fair Value Measurements in Part II, Item 8 of this report for additional discussion regarding our Net Profits Plan liability. 
+(6) 
+Amount shown represents estimated future discounted abandonment costs. These obligations are recorded as liabilities on our accompanying balance sheet as of December 31, 2013. The ultimate settlement of these obligations is unknown and can be impacted by federal and state regulations, as well as economic factors and therefore the actual timing of abandonment costs may vary significantly. Please refer to Note 9 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion regarding our asset retirement obligations. 
+(7) The majority of the amount shown relates to the unfunded portion of our estimated pension liability of $18.6 million , for which we have estimated the timing of future payments based on historical annual contribution amounts. We are expected to make contributions to the Pension Plan in 2014 of $4.3 million . 
+In addition to the amounts in the above table, we have committed to pay our portion of the development of infrastructure in our outside operated Eagle Ford shale program. The system owners unanimously approved budgeted capital expenditures for 2014, of which we are committed to pay approximately $33.0 million for the upcoming year. 
+Off-balance Sheet Arrangements 
+As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of December 31, 2013 , we have not been involved in any unconsolidated special purpose entity transactions. 
+We evaluate our transactions to determine if any variable interest entities exist. If it is determined that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. As of December 31, 2013 , all variable interest entities have been consolidated. 
+81 
+Critical Accounting Policies and Estimates 
+Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our assumptions and estimates on historical experience and various other sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we calculate due to changes in circumstances, global economics and politics, and general business conditions. A summary of our significant accounting policies is detailed in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report. We have outlined below those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment. 
+Oil and gas reserve quantities. Our estimated reserve quantities and future net cash flows are critical to the understanding of the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our financial statements, including the calculations of depletion and impairment of proved oil and gas properties and the estimate of our Net Profits Plan liability. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure calculations require a 10 percent discount rate to be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves, including using independent reserve engineering consultants. We expect that periodic reserve estimates will change in the future as additional information becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves each year-end. For purposes of depletion and impairment, reserve quantities are adjusted in accordance with GAAP for the impact of additions and dispositions. Changes in depletion or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period the reserve estimates change. Please refer to Supplemental Oil and Gas Information in Part II, Item 8 of this report. 
+The following table presents information about reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves. 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+MMBOE 
+MMBOE 
+MMBOE 
+Change 
+Change 
+Change 
+Revisions resulting from price changes 
+0.6 
+(12.1 
+) 
+(4.2 
+) 
+Revisions resulting from performance (1) 
+4.4 
+(15.3 
+) 
+6.1 
+Total 
+5.0 
+(27.4 
+) 
+1.9 
+(1) Performance revisions include the removal of proved undeveloped reserves that are no longer in our development plan within five years. 2011 includes the impact of our conversion to three stream production reporting. 
+As previously noted, commodity prices are volatile, and estimates of reserves are inherently imprecise. Consequently, we expect to continue experiencing these types of changes. Please refer to additional reserves discussion above under Overview of the Company. 
+82 
+The following table reflects the estimated MMBOE change and percentage change to our total reported reserve volumes from the described hypothetical changes: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+MMBOE 
+Percentage 
+MMBOE 
+Percentage 
+MMBOE 
+Percentage 
+Change 
+Change 
+Change 
+Change 
+Change 
+Change 
+10% decrease in SEC pricing 
+(9.8 
+) 
+(2 
+)% 
+(11.2 
+) 
+(4 
+)% 
+(3.7 
+) 
+(2 
+)% 
+10% decrease in proved undeveloped reserves 
+(22.0 
+) 
+(5 
+)% 
+(12.7 
+) 
+(4 
+)% 
+(6.9 
+) 
+(3 
+)% 
+The table above solely reflects the impact of a 10 percent decrease in SEC pricing or decrease in proved undeveloped reserves and does not include additional impacts to our proved reserves that may result from our internal intent to drill hurdles. Additional reserve information can be found in the reserve table and discussion included in Items 1 and 2 of Part I of this report, and in Supplemental Oil and Gas Information of Part II, Item 8 of this report. 
+Successful efforts method of accounting. GAAP provides for two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method. Both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more detailed description is included in Note 1 - Summary of Significant Accounting Policies of Part II, Item 8 of this report. 
+Revenue recognition. Our revenue recognition policy is significant because revenue is a key component of our results of operations and our forward-looking statements contained in our analysis of liquidity and capital resources. We derive our revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized when our production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a purchaser. At the end of each month, we make estimates of the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our properties, their historical performance, NYMEX, local spot market, and OPIS prices, and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are recorded in the month payment is received. A 10 percent change in our year end revenue accrual would have impacted net income before tax by approximately $23 million in 2013 . 
+Change in Net Profits Plan Liability. We record the estimated liability of future payments for our Net Profits Plan. The estimated liability is calculated based on a number of assumptions, including estimates of proved reserves, estimated future capital, present value discount factors, pricing assumptions, and overall market conditions. Please refer to Note 11 - Fair Value Measurements in Part II, Item 8 of this report for additional discussion . 
+Asset retirement obligations. We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells projected into the future based on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates, and determine what credit-adjusted risk-free discount rate to use. The impact to the accompanying statements of operations from these estimates is reflected in our depreciation, depletion, and amortization calculations and occurs over the remaining life of our respective oil and gas properties. Please refer to Note 9 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion. 
+83 
+Impairment of oil and gas properties. Our proved oil and gas properties are recorded at cost. We evaluate our proved properties for impairment when events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates. 
+Unproved oil and gas properties are assessed periodically for impairment on a lease-by-lease basis based on the remaining lease terms, drilling results, commodity price outlook, and future capital allocations. An impairment allowance is provided on unproven property when we determine that the property will not be developed or the carrying value will not be realized. Please refer to Impairment of Proved and Unproved Properties in Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of this report for impairment results. 
+Derivatives and Hedging. We periodically enter into commodity derivative contracts to manage our exposure to oil, gas and NGL price volatility. The accounting treatment for the change in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is designated as a cash flow hedge. Prior to January 1, 2011, we designated our commodity derivative contracts as cash flow hedges, for which unrealized changes in fair value were recorded to AOCIL, to the extent the hedges were effective. As of January 1, 2011, we elected to de-designate all of our commodity derivative contracts that had been previously designated as cash flow hedges at December 31, 2010. As a result, subsequent to December 31, 2010, we recognize all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in AOCIL. The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, whether or not the forecasted hedged transaction will occur, option pricing models, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. 
+Income taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not. Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations. A one percent change in our effective tax rate would have changed our calculated income tax expense by approximately $2.8 million for the year ended December 31, 2013 . 
+Accounting Matters 
+Please refer to the section entitled Recently Issued Accounting Standards under Note 1 – Summary of Significant Accounting Policies for additional information on the recent adoption of new authoritative accounting guidance in Part II, Item 8 of this report. 
+84 
+Environmental 
+We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes and we are unable to predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital expenditures, liquidity, and results of operations. 
+Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. For additional information about hydraulic fracturing and related environmental matters, see Risk Factors – Risks Related to Our Business – Proposed federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. 
+Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other ‘‘greenhouse gases’’ present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011. 
+In June 2013, President Obama announced a Climate Action Plan designed to further reduce greenhouse gas emissions and prepare the nation for the physical effects that may occur as a result of climate change. The Plan targets methane reductions from the oil and gas sector as part of a comprehensive interagency methane strategy. In addition, President Obama directed the EPA to issue stringent carbon standards for new fossil fuel-fired power plants. The EPA proposed new source performance standards in September 2013, which would require carbon capture and sequestration for coal-fired boilers and combined cycle technology for natural gas-fired boilers. The EPA has stated that it intends to propose greenhouse gas standards for existing fossil fuel-fired power plants by June 2014, finalize the standards by June 2015, and require plans by states to adopt the standards by 2016. 
+In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. 
+The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition, and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, 
+85 
+floods, and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. 
+In terms of opportunities, the regulation of greenhouse gas emissions and the introduction of alternative incentives, such as enhanced oil recovery, carbon sequestration, and low carbon fuel standards, could benefit us in a variety of ways. For example, although federal regulation and climate change legislation could reduce the overall demand for the oil and natural gas that we produce, the relative demand for natural gas may increase because the burning of natural gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources, such as wind or solar power become more prevalent, natural gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel standards, natural gas may become a more attractive transportation fuel. Approximately 51 and 55 percent of our production on an BOE basis in 2013 and 2012 , respectively, was natural gas. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and natural gas reservoirs, could also benefit us through the potential to obtain greenhouse gas emission allowances or offsets from or government incentives for the sequestration of carbon dioxide. 
+Non-GAAP Financial Measures 
+EBITDAX represents income (loss) before interest expense, interest income, income taxes, depreciation, depletion, amortization, and accretion, exploration expense, property impairments, non-cash stock compensation expense, derivative gains and losses net of cash settlements, change in the Net Profits Plan liability, and gains and losses on divestitures. EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally one-time in nature or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that is presented because we believe that it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to a financial covenant under our credit facility based on our debt to EBITDAX ratio. In addition, EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or profitability or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies. 
+86 
+The following table provides reconciliations of our net income (loss) and net cash provided by operating activities to EBITDAX for the periods presented: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Net income (loss) (GAAP) 
+$ 
+170,935 
+$ 
+(54,249 
+) 
+$ 
+215,416 
+Interest expense 
+89,711 
+63,720 
+45,849 
+Interest income 
+(67 
+) 
+(220 
+) 
+(466 
+) 
+Income tax expense (benefit) 
+107,676 
+(29,268 
+) 
+123,585 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion 
+822,872 
+727,877 
+511,103 
+Exploration 
+65,888 
+81,809 
+46,776 
+Impairment of proved properties 
+172,641 
+208,923 
+219,037 
+Abandonment and impairment of unproved properties 
+46,105 
+16,342 
+7,367 
+Stock-based compensation expense (1) 
+32,347 
+30,185 
+26,824 
+Derivative gain 
+(3,080 
+) 
+(55,630 
+) 
+(37,086 
+) 
+Derivative cash settlement gain (loss) 
+22,062 
+44,264 
+(25,671 
+) 
+Change in Net Profits Plan liability 
+(21,842 
+) 
+(28,904 
+) 
+(25,477 
+) 
+(Gain) loss on divestiture activity 
+(27,974 
+) 
+27,018 
+(220,676 
+) 
+EBITDAX (Non-GAAP) 
+1,477,274 
+1,031,867 
+886,581 
+Interest expense 
+(89,711 
+) 
+(63,720 
+) 
+(45,849 
+) 
+Interest income 
+67 
+220 
+466 
+Income tax (expense) benefit 
+(107,676 
+) 
+29,268 
+(123,585 
+) 
+Exploration 
+(65,888 
+) 
+(81,809 
+) 
+(46,776 
+) 
+Exploratory dry hole expense 
+5,846 
+20,861 
+277 
+Amortization of debt discount and deferred financing costs 
+5,390 
+6,769 
+18,299 
+Deferred income taxes 
+105,555 
+(29,638 
+) 
+123,789 
+Plugging and abandonment 
+(9,946 
+) 
+(2,856 
+) 
+(5,849 
+) 
+Other 
+2,775 
+527 
+(6,027 
+) 
+Changes in current assets and liabilities 
+14,828 
+10,480 
+(40,794 
+) 
+Net cash provided by operating activities (GAAP) 
+$ 
+1,338,514 
+$ 
+921,969 
+$ 
+760,532 
+(1) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration. 
+ITEM 7A. 
+QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+The information required by this item is provided under the captions Commodity Price Risk and Interest Rate Risk in Item 7 above, as well as under the section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place under Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report and is incorporated herein by reference. 
+87 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+The Board of Directors and Stockholders of SM Energy Company and subsidiaries 
+We have audited the accompanying consolidated balance sheet of SM Energy Company and subsidiaries as of December 31, 2013 , and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. 
+In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of SM Energy Company and subsidiaries at December 31, 2013 , and the consolidated results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), SM Energy Company’s internal control over financial reporting as of December 31, 2013 , based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 19, 2014 expressed an unqualified opinion thereon. 
+/s/ Ernst & Young LLP 
+Denver, Colorado 
+February 19, 2014 
+88 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Board of Directors and Stockholders of SM Energy Company and Subsidiaries 
+Denver, Colorado 
+We have audited the accompanying consolidated balance sheet of SM Energy Company and subsidiaries (the “Company”) as of December 31, 2012 , and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for the years ended December 31, 2012 , and 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. 
+We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. 
+In our opinion, such 2012 and 2011 consolidated financial statements present fairly, in all material respects, the financial position of SM Energy Company and subsidiaries as of December 31, 2012 , and the results of their operations and their cash flows for the years ended December 31, 2012 , and 2011, in conformity with accounting principles generally accepted in the United States of America. 
+As disclosed in Notes 1 and 10 to the consolidated financial statements, the accompanying 2012 consolidated financial statements give retrospective effect to new disclosure requirements regarding information related to offsetting of derivative assets and liabilities. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 21, 2013 
+(February 19, 2014 as to the disclosures regarding offsetting of derivative assets and liabilities as of December 31, 2012 in Notes 1 and 10) 
+89 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED BALANCE SHEETS 
+(in thousands, except share amounts) 
+December 31, 
+2013 
+2012 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+282,248 
+$ 
+5,926 
+Accounts receivable (note 2) 
+318,371 
+254,805 
+Refundable income taxes 
+4,630 
+3,364 
+Prepaid expenses and other 
+9,944 
+30,017 
+Derivative asset 
+21,559 
+37,873 
+Deferred income taxes 
+10,749 
+8,579 
+Total current assets 
+647,501 
+340,564 
+Property and equipment (successful efforts method): 
+Land 
+1,857 
+1,845 
+Proved oil and gas properties 
+5,637,462 
+5,401,684 
+Less - accumulated depletion, depreciation, and amortization 
+(2,583,698 
+) 
+(2,376,170 
+) 
+Unproved oil and gas properties 
+271,100 
+175,287 
+Wells in progress 
+279,654 
+273,928 
+Materials inventory, at lower of cost or market 
+15,950 
+13,444 
+Oil and gas properties held for sale, net of accumulated depletion, depreciation and amortization of $7,390 in 2013 and $20,676 in 2012 
+19,072 
+33,620 
+Other property and equipment, net of accumulated depreciation of $28,775 in 2013 and $22,442 in 2012 
+218,395 
+153,559 
+Total property and equipment, net 
+3,859,792 
+3,677,197 
+Noncurrent assets: 
+Derivative asset 
+30,951 
+16,466 
+Restricted cash 
+96,713 
+86,773 
+Other noncurrent assets 
+70,208 
+78,529 
+Total other noncurrent assets 
+197,872 
+181,768 
+Total Assets 
+$ 
+4,705,165 
+$ 
+4,199,529 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued expenses (note 2) 
+$ 
+606,751 
+$ 
+525,627 
+Derivative liability 
+26,380 
+8,999 
+Other current liabilities 
+6,000 
+6,920 
+Total current liabilities 
+639,131 
+541,546 
+Noncurrent liabilities: 
+Revolving credit facility 
+— 
+340,000 
+Senior Notes (note 5) 
+1,600,000 
+1,100,000 
+Asset retirement obligation 
+115,659 
+112,912 
+Asset retirement obligation associated with oil and gas properties held for sale 
+3,033 
+1,393 
+Net Profits Plan liability 
+56,985 
+78,827 
+Deferred income taxes 
+650,125 
+537,383 
+Derivative liability 
+4,640 
+6,645 
+Other noncurrent liabilities 
+28,771 
+66,357 
+Total noncurrent liabilities 
+2,459,213 
+2,243,517 
+Commitments and contingencies (note 6) 
+Stockholders' equity: 
+Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 67,078,853 shares in 2013 and 66,245,816 shares in 2012; outstanding, net of treasury shares: 67,056,441 shares in 2013 and 66,195,235 shares in 2012 
+671 
+662 
+Additional paid-in capital 
+257,720 
+233,642 
+Treasury stock, at cost: 22,412 shares in 2013 and 50,581 shares in 2012 
+(823 
+) 
+(1,221 
+) 
+Retained earnings 
+1,354,669 
+1,190,397 
+Accumulated other comprehensive loss 
+(5,416 
+) 
+(9,014 
+) 
+Total stockholders' equity 
+1,606,821 
+1,414,466 
+Total Liabilities and Stockholders' Equity 
+$ 
+4,705,165 
+$ 
+4,199,529 
+The accompanying notes are an integral part of these consolidated financial statements. 
+90 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+(in thousands, except per share amounts) 
+For the Years 
+Ended December 31, 
+2013 
+2012 
+2011 
+Operating revenues: 
+Oil, gas, and NGL production revenue 
+$ 
+2,199,550 
+$ 
+1,473,868 
+$ 
+1,332,392 
+Realized hedge (loss) gain 
+(1,777 
+) 
+3,866 
+(20,707 
+) 
+Gain (loss) on divestiture activity 
+27,974 
+(27,018 
+) 
+220,676 
+Marketed gas system revenue 
+60,039 
+52,808 
+69,898 
+Other operating revenues 
+7,588 
+1,578 
+1,059 
+Total operating revenues and other income 
+2,293,374 
+1,505,102 
+1,603,318 
+Operating expenses: 
+Oil, gas, and NGL production expense 
+597,045 
+391,872 
+290,111 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion 
+822,872 
+727,877 
+511,103 
+Exploration 
+74,104 
+90,248 
+53,537 
+Impairment of proved properties 
+172,641 
+208,923 
+219,037 
+Abandonment and impairment of unproved properties 
+46,105 
+16,342 
+7,367 
+General and administrative 
+149,551 
+119,815 
+118,526 
+Change in Net Profits Plan liability 
+(21,842 
+) 
+(28,904 
+) 
+(25,477 
+) 
+Derivative gain 
+(3,080 
+) 
+(55,630 
+) 
+(37,086 
+) 
+Marketed gas system expense 
+57,647 
+47,583 
+64,249 
+Other operating expenses 
+30,076 
+6,993 
+17,567 
+Total operating expenses 
+1,925,119 
+1,525,119 
+1,218,934 
+Income (loss) from operations 
+368,255 
+(20,017 
+) 
+384,384 
+Nonoperating income (expense): 
+Interest income 
+67 
+220 
+466 
+Interest expense 
+(89,711 
+) 
+(63,720 
+) 
+(45,849 
+) 
+Income (loss) before income taxes 
+278,611 
+(83,517 
+) 
+339,001 
+Income tax (expense) benefit 
+(107,676 
+) 
+29,268 
+(123,585 
+) 
+Net income (loss) 
+$ 
+170,935 
+$ 
+(54,249 
+) 
+$ 
+215,416 
+Basic weighted-average common shares outstanding 
+66,615 
+65,138 
+63,755 
+Diluted weighted-average common shares outstanding 
+67,998 
+65,138 
+67,564 
+Basic net income (loss) per common share 
+$ 
+2.57 
+$ 
+(0.83 
+) 
+$ 
+3.38 
+Diluted net income (loss) per common share 
+$ 
+2.51 
+$ 
+(0.83 
+) 
+$ 
+3.19 
+The accompanying notes are an integral part of these consolidated financial statements. 
+91 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) 
+(in thousands) 
+For the Years 
+Ended December 31, 
+2013 
+2012 
+2011 
+Net income (loss) 
+$ 
+170,935 
+$ 
+(54,249 
+) 
+$ 
+215,416 
+Other comprehensive income (loss), net of tax: 
+Reclassification to earnings (1) 
+1,115 
+(2,264 
+) 
+12,997 
+Pension liability adjustment (2) 
+2,483 
+(2,470 
+) 
+(1,795 
+) 
+Total other comprehensive income (loss), net of tax 
+3,598 
+(4,734 
+) 
+11,202 
+Total comprehensive income (loss) 
+$ 
+174,533 
+$ 
+(58,983 
+) 
+$ 
+226,618 
+(1) Reclassification from accumulated other comprehensive income related to de-designated hedges. Refer to Note 10 - Derivative Financial Instruments for further information. 
+(2) Pension amounts are reclassified to General and administrative expense on the Company's consolidated statements of operations. The net of tax effect of the reclassification was approximately $768,000 in 2013. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+92 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 
+(in thousands, except share amounts) 
+Additional Paid-in Capital 
+Accumulated Other Comprehensive Loss 
+Total Stockholders’ Equity 
+Common Stock 
+Treasury Stock 
+Retained Earnings 
+Shares 
+Amount 
+Shares 
+Amount 
+Balances, January 1, 2011 
+63,412,800 
+$ 
+634 
+$ 
+191,674 
+(102,635 
+) 
+$ 
+(423 
+) 
+$ 
+1,042,123 
+$ 
+(15,482 
+) 
+$ 
+1,218,526 
+Net income 
+— 
+— 
+— 
+— 
+— 
+215,416 
+— 
+215,416 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+— 
+— 
+11,202 
+11,202 
+Cash dividends, $ 0.10 per share 
+— 
+— 
+— 
+— 
+— 
+(6,382 
+) 
+— 
+(6,382 
+) 
+Issuance of common stock under Employee Stock Purchase Plan 
+41,358 
+— 
+2,300 
+— 
+— 
+— 
+— 
+2,300 
+Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings 
+278,773 
+3 
+(9,976 
+) 
+— 
+— 
+— 
+— 
+(9,973 
+) 
+Issuance of common stock upon stock option exercises 
+412,551 
+4 
+5,023 
+— 
+— 
+— 
+— 
+5,027 
+Stock-based compensation expense 
+— 
+— 
+27,945 
+21,568 
+(1,121 
+) 
+— 
+— 
+26,824 
+Balances, December 31, 2011 
+64,145,482 
+$ 
+641 
+$ 
+216,966 
+(81,067 
+) 
+$ 
+(1,544 
+) 
+$ 
+1,251,157 
+$ 
+(4,280 
+) 
+$ 
+1,462,940 
+Net loss 
+— 
+— 
+— 
+— 
+— 
+(54,249 
+) 
+— 
+(54,249 
+) 
+Other comprehensive loss 
+— 
+— 
+— 
+— 
+— 
+— 
+(4,734 
+) 
+(4,734 
+) 
+Cash dividends, $ 0.10 per share 
+— 
+— 
+— 
+— 
+— 
+(6,511 
+) 
+— 
+(6,511 
+) 
+Issuance of common stock under Employee Stock Purchase Plan 
+66,485 
+1 
+2,775 
+— 
+— 
+— 
+— 
+2,776 
+Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings 
+929,375 
+9 
+(21,631 
+) 
+— 
+— 
+— 
+— 
+(21,622 
+) 
+Issuance of common stock upon stock option exercises 
+240,368 
+2 
+3,038 
+— 
+— 
+— 
+— 
+3,040 
+Conversion of 3.50% Senior Convertible Notes to common stock, including income tax benefit of conversion 
+864,106 
+9 
+2,632 
+— 
+— 
+— 
+— 
+2,641 
+Stock-based compensation expense 
+— 
+— 
+29,862 
+30,486 
+323 
+— 
+— 
+30,185 
+Balances, December 31, 2012 
+66,245,816 
+$ 
+662 
+$ 
+233,642 
+(50,581 
+) 
+$ 
+(1,221 
+) 
+$ 
+1,190,397 
+$ 
+(9,014 
+) 
+$ 
+1,414,466 
+Net income 
+— 
+— 
+— 
+— 
+— 
+170,935 
+— 
+170,935 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+— 
+— 
+3,598 
+3,598 
+Cash dividends, $ 0.10 per share 
+— 
+— 
+— 
+— 
+— 
+(6,663 
+) 
+— 
+(6,663 
+) 
+Issuance of common stock under Employee Stock Purchase Plan 
+77,427 
+1 
+3,671 
+— 
+— 
+— 
+— 
+3,672 
+Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings 
+526,852 
+5 
+(16,225 
+) 
+— 
+— 
+— 
+— 
+(16,220 
+) 
+Issuance of common stock upon stock option exercises 
+228,758 
+3 
+3,183 
+— 
+— 
+— 
+— 
+3,186 
+Stock-based compensation expense 
+— 
+— 
+31,949 
+28,169 
+398 
+— 
+— 
+32,347 
+Other income tax benefit 
+— 
+— 
+1,500 
+— 
+— 
+— 
+— 
+1,500 
+Balances, December 31, 2013 
+67,078,853 
+$ 
+671 
+$ 
+257,720 
+(22,412 
+) 
+$ 
+(823 
+) 
+$ 
+1,354,669 
+$ 
+(5,416 
+) 
+$ 
+1,606,821 
+The accompanying notes are an integral part of these consolidated financial statements. 
+93 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+(in thousands) 
+For the Years Ended 
+December 31, 
+2013 
+2012 
+2011 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+170,935 
+$ 
+(54,249 
+) 
+$ 
+215,416 
+Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
+(Gain) loss on divestiture activity 
+(27,974 
+) 
+27,018 
+(220,676 
+) 
+Depletion, depreciation, amortization, and asset retirement obligation liability accretion 
+822,872 
+727,877 
+511,103 
+Exploratory dry hole expense 
+5,846 
+20,861 
+277 
+Impairment of proved properties 
+172,641 
+208,923 
+219,037 
+Abandonment and impairment of unproved properties 
+46,105 
+16,342 
+7,367 
+Stock-based compensation expense 
+32,347 
+30,185 
+26,824 
+Change in Net Profits Plan liability 
+(21,842 
+) 
+(28,904 
+) 
+(25,477 
+) 
+Derivative gain 
+(3,080 
+) 
+(55,630 
+) 
+(37,086 
+) 
+Derivative cash settlement gain (loss) 
+22,062 
+44,264 
+(25,671 
+) 
+Amortization of debt discount and deferred financing costs 
+5,390 
+6,769 
+18,299 
+Deferred income taxes 
+105,555 
+(29,638 
+) 
+123,789 
+Plugging and abandonment 
+(9,946 
+) 
+(2,856 
+) 
+(5,849 
+) 
+Other 
+2,775 
+527 
+(6,027 
+) 
+Changes in current assets and liabilities: 
+Accounts receivable 
+(78,494 
+) 
+(21,389 
+) 
+(41,998 
+) 
+Refundable income taxes 
+(1,266 
+) 
+2,217 
+2,901 
+Prepaid expenses and other 
+1,364 
+(1,484 
+) 
+16,376 
+Accounts payable and accrued expenses 
+93,224 
+31,136 
+(18,073 
+) 
+Net cash provided by operating activities 
+1,338,514 
+921,969 
+760,532 
+Cash flows from investing activities: 
+Net proceeds from sale of oil and gas properties 
+424,849 
+55,375 
+364,522 
+Capital expenditures 
+(1,553,536 
+) 
+(1,507,828 
+) 
+(1,633,093 
+) 
+Acquisition of proved and unproved oil and gas properties 
+(61,603 
+) 
+(5,773 
+) 
+— 
+Receipts from restricted cash related to 1031 exchange 
+(1,754 
+) 
+— 
+— 
+Other 
+(859 
+) 
+893 
+3,661 
+Net cash used in investing activities 
+(1,192,903 
+) 
+(1,457,333 
+) 
+(1,264,910 
+) 
+Cash flows from financing activities: 
+Proceeds from credit facility 
+1,203,000 
+1,609,000 
+322,000 
+Repayment of credit facility 
+(1,543,000 
+) 
+(1,269,000 
+) 
+(370,000 
+) 
+Debt issuance costs related to credit facility 
+(3,444 
+) 
+— 
+(8,719 
+) 
+Net proceeds from Senior Notes 
+490,185 
+392,138 
+684,242 
+Repayment of 3.50% Senior Convertible Notes 
+— 
+(287,500 
+) 
+— 
+Proceeds from sale of common stock 
+6,858 
+5,816 
+7,327 
+Dividends paid 
+(6,663 
+) 
+(6,511 
+) 
+(6,382 
+) 
+Net share settlement from issuance of stock awards 
+(16,220 
+) 
+(21,622 
+) 
+(9,973 
+) 
+Other 
+(5 
+) 
+(225 
+) 
+— 
+Net cash provided by financing activities 
+130,711 
+422,096 
+618,495 
+Net change in cash and cash equivalents 
+276,322 
+(113,268 
+) 
+114,117 
+Cash and cash equivalents at beginning of period 
+5,926 
+119,194 
+5,077 
+Cash and cash equivalents at end of period 
+$ 
+282,248 
+$ 
+5,926 
+$ 
+119,194 
+The accompanying notes are an integral part of these consolidated financial statements. 
+94 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) 
+Supplemental schedule of additional cash flow information and non-cash activities: 
+For the Years Ended 
+December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Cash paid for interest, net of capitalized interest 
+$ 
+(70,702 
+) 
+$ 
+(51,328 
+) 
+$ 
+(22,133 
+) 
+Net cash refunded for income taxes 
+$ 
+204 
+$ 
+1,389 
+$ 
+4,046 
+As of December 31, 2013 , 2012 , and 2011 , $217.8 million , $262.8 million , and $214.8 million , respectively, of accrued capital expenditures were included in accounts payable and accrued expenses in the Company's consolidated balance sheets. These oil and gas property additions are reflected in cash used in investing activities in the periods during which the payables are settled. 
+During the third quarter of 2013, the Company closed an exchange of properties in its Rocky Mountain region with a fair value of $25.0 million . The insignificant amount of cash consideration paid at closing for purchase price adjustments is reflected in the acquisition of proved and unproved oil and gas properties line item in the consolidated statements of cash flows. 
+95 
+SM ENERGY COMPANY AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+Note 1 – Summary of Significant Accounting Policies 
+Description of Operations 
+SM Energy is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil and condensate, gas, and NGLs in onshore North America, with a current focus on oil and liquids-rich resource plays. 
+Basis of Presentation 
+The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Subsidiaries that the Company does not control are accounted for using the equity or cost methods as appropriate. Equity method investments are included in other noncurrent assets in the accompanying consolidated balance sheets (“accompanying balance sheets”). Intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2013 , through the filing date of this report. Certain prior period amounts have been reclassified to conform to the current period presentation on the accompanying balance sheets and accompanying consolidated statements of cash flows (“accompanying statements of cash flows”). The Company’s Senior Notes are combined and presented as a single line item within the accompanying balance sheets in the current year whereas they were individually presented in prior periods. The Company's total derivative gain is now presented on the accompanying statements of cash flows in cash flows from operating activities with an additional line item to adjust for the cash settlement portion. 
+Use of Estimates in the Preparation of Financial Statements 
+The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization expense, impairment of proved properties, asset retirement obligations, and the Net Profits Interest Bonus Plan (“Net Profits Plan”) liability, each of which represents a significant component of the accompanying consolidated financial statements. 
+Cash and Cash Equivalents 
+The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. 
+Restricted Cash 
+The Company’s restricted cash balance mainly consists of cash payments that are contractually restricted to be used solely for development of long-term capital assets pursuant to the Company’s Acquisition and Development Agreement with Mitsui and accordingly are classified as non-current assets. Please refer to Note 12 - Acquisition and Development Agreement for additional information. 
+96 
+Accounts Receivable 
+The Company’s accounts receivable consist mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months, and the Company has had minimal bad debts. 
+Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. As of December 31, 2013 and 2012 , the Company had no allowance for doubtful accounts recorded. 
+Concentration of Credit Risk and Major Customers 
+The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to regular review. During 2013 , the Company had three major customers, Regency Gas Services LLC , Anadarko, and Plains Marketing LP , which accounted for approximately 26 percent , 16 percent , and 12 percent , respectively, of total oil, gas, and NGL production revenue. During the third quarter of 2013, the Company entered into various marketing agreements with Anadarko whereby the Company is subject to certain gathering, transportation, and processing through-put commitments for up to 10 years pursuant to each contract. While Anadarko is the first purchaser under these contracts, the Company also shares the risk of non-performance by Anadarko’s counterparty purchasers. Several of Anadarko’s counterparty purchasers under these contracts are also direct purchasers of products produced by the Company. During 2012 , the Company had two major customers, Regency Gas Services LLC and Plains Marketing LP , which accounted for approximately 21 percent and 13 percent , respectively, of total production revenue. During 2011 , the Company had one major customer, Regency Gas Services LLC , which accounted for approximately 18 percent of total production revenue. 
+The Company currently uses 10 separate counterparties for its oil, gas, and NGL commodity derivatives, all of which are participating lenders in the Company’s credit facility. Three counterparties were downgraded during 2013 , but all maintain investment grade ratings. Our lowest rated counterparty carries credit ratings of BBB- and Baa2, by Standard & Poor’s and Moody’s, respectively. Per the terms of our agreement with that counterparty, the Company requires cash collateral to be posted when its portfolio of trades with that counterparty is in an overall asset position. 
+The Company has accounts in the following locations with a national bank: Denver, Colorado ; Houston, Texas ; Midland, Texas ; and Billings, Montana . The Company has accounts with a local bank in Tulsa, Oklahoma. As a result of the Anadarko Basin divestiture closing at the end of 2013, the Company had a large cash balance at December 31, 2013 , which was invested in money market funds among various financial institutions. This is in line with the Company’s policy is to invest in highly-rated instruments and to limit the amount of credit exposure at each individual institution. 
+Oil and Gas Producing Activities 
+The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in cash flows from investing activities as 
+97 
+part of capital expenditures within the accompanying statements of cash flows. The costs of development wells are capitalized whether those wells are successful or unsuccessful. 
+DD&A of capitalized costs related to proved oil and gas properties is calculated on a pool-by-pool basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. As of December 31, 2013 , and 2012 , the estimated salvage value of the Company's equipment was $57.5 million and $64.4 million , respectively. 
+Materials Inventory 
+The Company’s materials inventory is primarily comprised of tubular goods to be used in future drilling operations. Materials inventory is valued at the lower of cost or market and totaled $16.0 million and $13.4 million at December 31, 2013 , and 2012 , respectively. There were no materials inventory write-downs for the years ended December 31, 2013 , 2012 , or 2011 . 
+Assets Held for Sale 
+Any properties held for sale as of the balance sheet date have been classified as assets held for sale and are separately presented on the accompanying balance sheets at the lower of net book value or fair value less the cost to sell. The asset retirement obligation liabilities related to such properties have been reclassified to asset retirement obligations associated with oil and gas properties held for sale in the accompanying balance sheets. For additional discussion on assets held for sale, please refer to Note 3 – Divestitures and Assets Held for Sale . 
+Other Property and Equipment 
+Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from three to thirty years , or the unit of output method where appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts. 
+Intangible Assets 
+As of December 31, 2013 , and 2012 , the Company had $10.8 million of intangible assets consisting of acquired water rights, which are included as other noncurrent assets in the accompanying balance sheets. All intangible assets with indefinite lives are evaluated for impairment annually or if impairment indicators arise. 
+Internal-Use Software Development Costs 
+The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2013, the Company has capitalized approximately $11.2 million related to the ongoing development and implementation of accounting and operational software. 
+98 
+Derivative Financial Instruments 
+The Company seeks to manage or reduce commodity price risk on production by entering into derivative contracts. The Company seeks to minimize its basis risk and indexes its oil derivative contracts to NYMEX or Argus LLS prices, its NGL derivative contracts to OPIS prices, and the majority of its gas derivative contracts to various regional index prices associated with pipelines in proximity to the Company’s areas of gas production. For additional discussion on derivatives, please see Note 10 – Derivative Financial Instruments . 
+Net Profits Plan 
+The Company records the estimated fair value of expected future payments made under the Net Profits Plan as a noncurrent liability in the accompanying balance sheets. The underlying assumptions used in the calculation of the estimated liability include estimates of production, proved reserves, recurring and workover lease operating expense, transportation, production and ad valorem tax rates, present value discount factors, pricing assumptions, and overall market conditions. The estimates used in calculating the long-term liability are adjusted from period-to-period based on the most current information attributable to the underlying assumptions. Changes in the estimated liability of future payments associated with the Net Profits Plan are recorded as increases or decreases to expense in the current period as a separate line item in the accompanying consolidated statements of operations (“accompanying statements of operations”), as these changes are considered changes in estimates. 
+The distribution amounts due to participants and payable in each period under the Net Profits Plan as cash compensation related to periodic operations are recognized as compensation expense and are included within general and administrative expense and exploration expense in the accompanying statements of operations. The corresponding current liability is included in accounts payable and accrued expenses in the accompanying balance sheets. This treatment provides for a consistent matching of cash expense with net cash flows from the oil and gas properties in each respective pool of the Net Profits Plan. For additional discussion, please refer to the heading Net Profits Plan in Note 7 – Compensation Plans and Note 11 – Fair Value Measurements . 
+Asset Retirement Obligations 
+The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. For additional discussion, please refer to Note 9 – Asset Retirement Obligations . 
+Revenue Recognition 
+The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized when the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses knowledge of its properties and historical performance, NYMEX, OPIS, and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates. 
+The Company uses the sales method of accounting for gas revenue whereby sales revenue is recognized on all gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. An asset or liability is recognized to the extent that there is an imbalance in excess of the remaining gas reserves on the underlying properties. 
+99 
+Impairment of Proved and Unproved Properties 
+Proved oil and gas property costs are evaluated for impairment and reduced to fair value, which is based on expected future discounted cash flows, when there is an indication that the carrying costs may not be recoverable. Expected future cash flows are calculated on all developed proved reserves and risk adjusted proved undeveloped, probable, and possible reserves using a discount rate and price forecasts that management believes are representative of current market conditions. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. An impairment is recorded on unproved property when the Company determines that either the property will not be developed or the carrying value is not realizable. 
+The Company recorded $172.6 million , $208.9 million , and $219.0 million , of proved property impairments for the years ended December 31, 2013 , 2012 , and 2011 , respectively. The impairments in 2013 resulted from the write-down of certain Mississippian limestone assets in the Company’s Permian region due to negative engineering revisions, write-downs related to Olmos interval, dry gas assets in the South Texas & Gulf Coast region as a result of a plugging and abandonment program, and write-downs of certain underperforming assets due to the Company’s decision to no longer pursue the development of those assets. The impairments in 2012 were a result of the Company’s write-down of Wolfberry assets in its Permian region due to negative engineering revisions and the Company’s Haynesville shale assets as a result of low natural gas prices. The impairments in 2011 were related to the Company’s James Lime, Cotton Valley, and Haynesville shale assets as a result of significantly lower natural gas prices at the end of 2011 . 
+For the years ended December 31, 2013 , 2012 , and 2011 , the Company recorded expense related to the abandonment and impairment of unproved properties of $46.1 million , $16.3 million , and $7.4 million , respectively. The Company's abandonment and impairment of unproved properties in 2013 was mostly related to acreage the Company no longer intends to develop in its Permian region. The Company’s abandonment and impairment of unproved properties in 2012 related to acreage that the Company no longer intended to develop in its Rocky Mountain region. 
+Sales of Proved and Unproved Properties 
+The partial sale of proved properties within an existing field is accounted for as normal retirement and no gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. 
+The partial sale of unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to the ultimate recovery of the cost applicable to the interest retained. A gain on divestiture activity is recognized to the extent that the sales price exceeds the carrying amount of the unproved property. A gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of unproved property. For additional discussion, please refer to Note 3 – Divestitures and Assets Held for Sale . 
+Stock-Based Compensation 
+At December 31, 2013 , the Company had stock-based employee compensation plans that included RSUs, PSUs, restricted stock awards, and stock options issued to employees and non-employee directors, as more fully described in Note 7 - Compensation Plans. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant. 
+100 
+Income Taxes 
+The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. 
+Earnings per Share 
+Basic net income (loss) per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company. 
+Diluted net income (loss) per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of in-the-money outstanding stock options, unvested RSUs, contingent PSUs, and shares into which the 3.50% Senior Convertible Notes were convertible. When there is a loss from continuing operations, as was the case for the year ended December 31, 2012, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share. 
+PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 – Compensation Plans under the heading Performance Share Units Under the Equity Incentive Compensation Plan . 
+The Company called for redemption of its 3.50% Senior Convertible Notes on April 2, 2012, after which the majority of the holders of the outstanding 3.50% Senior Convertible Notes elected to convert their notes. The Company issued 864,106 common shares upon conversion, and these shares were included in the calculation of basic weighted-average common shares outstanding for the year ended December 31, 2012 and all subsequent years the shares remained outstanding. Please refer to Note 5 - Long-term Debt for additional discussion. Prior to calling the 3.50% Senior Convertible Notes for redemption, the Company’s notes had a net-share settlement right giving the Company the option to irrevocably elect, by notice to the trustee under the indenture for the notes, to settle the Company’s obligation, in the event that holders of the notes elected to convert all or a portion of their notes, by delivering cash in an amount equal to each $1,000 principal amount of notes surrendered for conversion and, if applicable, at the Company’s option, shares of common stock or cash, or any combination of common stock and cash, for the amount of conversion value in excess of the principal amount. Prior to the settlement of the Company’s 3.50% Senior Convertible Notes, potentially dilutive shares associated with the conversion feature were accounted for using the treasury stock method when shares of the Company’s common stock traded at an average closing price that exceeded the $54.42 conversion price. Shares of the Company’s common stock traded at an average closing price exceeding the conversion price and were included on an adjusted weighted basis for the portion of the year ended December 31, 2012 , for which they were outstanding. Shares of the Company’s common stock traded at an average closing price exceeding the $54.42 conversion price for the year ended December 31, 2011, making the 3.50% Senior Convertible Notes dilutive for that period. 
+The treasury stock method is used to measure the dilutive impact of in-the-money stock options, unvested RSUs, contingent PSUs, and the 3.50% Senior Convertible Notes. 
+101 
+The following table details the weighted-average dilutive and anti-dilutive securities related to stock options, RSUs, PSUs, and the 3.50% Senior Convertible Notes for the years presented: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Dilutive 
+1,383 
+— 
+3,809 
+Anti-dilutive 
+— 
+2,102 
+— 
+The following table sets forth the calculations of basic and diluted earnings per share: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands, except per share amounts) 
+Net income (loss) 
+$ 
+170,935 
+$ 
+(54,249 
+) 
+$ 
+215,416 
+Basic weighted-average common shares outstanding 
+66,615 
+65,138 
+63,755 
+Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs 
+1,383 
+— 
+2,592 
+Add: dilutive effect of 3.50% Senior Convertible Notes 
+— 
+— 
+1,217 
+Diluted weighted-average common shares outstanding 
+67,998 
+65,138 
+67,564 
+Basic net income (loss) per common share 
+$ 
+2.57 
+$ 
+(0.83 
+) 
+$ 
+3.38 
+Diluted net income (loss) per common share 
+$ 
+2.51 
+$ 
+(0.83 
+) 
+$ 
+3.19 
+Comprehensive Income (Loss) 
+Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss). 
+The changes in the balances of components comprising other comprehensive income (loss) are presented in the following table: 
+Derivative Reclassification to Earnings 
+Pension Liability Adjustments 
+(in thousands) 
+For the year ended December 31, 2011 
+Before tax income (loss) 
+$ 
+20,707 
+$ 
+(2,779 
+) 
+Tax benefit (expense) 
+(7,710 
+) 
+984 
+Income (loss), net of tax 
+$ 
+12,997 
+$ 
+(1,795 
+) 
+For the year ended December 31, 2012 
+Before tax loss 
+$ 
+(3,865 
+) 
+$ 
+(3,909 
+) 
+Tax benefit 
+1,601 
+1,439 
+Loss, net of tax 
+$ 
+(2,264 
+) 
+$ 
+(2,470 
+) 
+For the year ended December 31, 2013 
+Before tax income 
+$ 
+1,777 
+$ 
+4,005 
+Tax expense 
+(662 
+) 
+(1,522 
+) 
+Income, net of tax 
+$ 
+1,115 
+$ 
+2,483 
+102 
+Fair Value of Financial Instruments 
+The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had no borrowings outstanding under its credit facility as of December 31, 2013 . The Company had $340.0 million of outstanding loans under its credit facility as of December 31, 2012 . The Company’s Senior Notes are recorded at cost and the respective fair values are disclosed in Note 11 - Fair Value Measurements. The Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. 
+Industry Segment and Geographic Information 
+The Company operates exclusively in the exploration and production segment of the oil and gas industry and all of the Company’s operations are conducted entirely within the United States. The Company reports as a single industry segment. The Company’s gas marketing function provides mostly internal services and acts as the first purchaser of natural gas and natural gas liquids produced by the Company in certain cases. The Company considers its marketing function as ancillary to its oil and gas producing activities. The amount of income these operations generate from marketing gas produced by third parties is not material to the Company’s results of operations, and segmentation of such activity would not provide a better understanding of the Company’s performance. However, gross revenue and expense related to marketing activities for gas produced by third parties are presented in the marketed gas system revenue and marketed gas system expense line items in the accompanying statements of operations. 
+Off-Balance Sheet Arrangements 
+The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. The Company has not been involved in any unconsolidated SPE transactions. 
+The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that SM Energy is the primary beneficiary of a variable interest entity, that entity is consolidated into SM Energy. As of December 31, 2013 , all variable interest entities have been consolidated. 
+Recently Issued Accounting Standards 
+On January 1, 2013, the Company adopted new authoritative accounting guidance issued by the Financial Accounting Standards Board (“FASB”), which enhanced disclosures by requiring an entity to disclose information about netting arrangements, including rights of offset, to enable users of its financial statements to understand the effect of those arrangements on its financial position and provided clarification as to the specific instruments that should be considered in these disclosures. These pronouncements were issued to facilitate comparison between financial statements prepared on the basis of GAAP and International Financial Reporting Standards. These disclosures are effective for annual and interim reporting periods beginning on or after January 1, 2013, and are to be applied retrospectively for all comparative periods presented. The impact of retrospectively adopting these pronouncements did not have a material impact on the Company’s consolidated financial statements, but did impact the Company’s disclosures. See Note 10 - Derivative Financial Instruments for tabular presentation of the Company’s gross and net derivative positions. 
+103 
+On January 1, 2013, the Company adopted the presentation requirements of new authoritative accounting guidance issued by the FASB in February 2013. The purpose of the guidance was to improve the reporting of reclassifications out of accumulated other comprehensive income (loss) (“AOCIL”) by requiring entities to report the effect of significant reclassifications out of AOCIL into current year income within the respective line items in net income. The presentation of those amounts may be on the face of the financial statements or in the notes thereto. This amendment was effective prospectively for periods beginning after December 15, 2012, and the Company's financial statements and disclosures were not significantly impacted. 
+In February 2013, the FASB issued new authoritative accounting guidance related to the recognition and measurement of obligations arising from joint and several liability arrangements. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2013 and is to be applied retrospectively. Based on its evaluation, the Company determined this guidance does not currently impact the Company’s financial statements and disclosures. 
+In July 2013, the FASB issued new authoritative accounting guidance related to the reporting of unrecognized tax benefits when a net operating loss carryforward, similar tax loss, or tax credit carryforward exists. The guidance states an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carry-forward, a similar tax loss, or a tax credit carry-forward, with certain exceptions. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2013, and is to be applied prospectively to all unrecognized tax benefits that exist at the effective date. The Company elected to early adopt this guidance in December 2013, which does not significantly affect the Company's financial statements and related disclosures. 
+There are no new significant accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of December 31, 2013 . 
+104 
+Note 2 – Accounts Receivable and Accounts Payable and Accrued Expenses 
+Accounts receivable are comprised of the following: 
+As of December 31, 
+2013 
+2012 
+(in thousands) 
+Accrued oil, gas, and NGL production revenue 
+$ 
+228,169 
+$ 
+160,568 
+Amounts due from joint interest owners 
+37,517 
+42,740 
+Acquisition and Development Agreement receivable 
+— 
+19,931 
+State severance tax refunds 
+29,213 
+17,237 
+Other 
+23,472 
+14,329 
+Total accounts receivable 
+$ 
+318,371 
+$ 
+254,805 
+Accounts payable and accrued expenses are comprised of the following: 
+As of December 31, 
+2013 
+2012 
+(in thousands) 
+Accrued capital expenditures 
+$ 
+217,820 
+$ 
+243,611 
+Revenue and severance tax payable 
+87,852 
+65,494 
+Accrued lease operating expense 
+29,296 
+28,037 
+Accrued property taxes 
+10,401 
+9,478 
+Joint owner advances 
+96,636 
+69,639 
+Accrued compensation 
+71,466 
+35,607 
+Accrued interest 
+40,027 
+25,027 
+Other 
+53,253 
+48,734 
+Total accounts payable and accrued expenses 
+$ 
+606,751 
+$ 
+525,627 
+Note 3 – Divestitures and Assets Held for Sale 
+2013 Divestiture Activity 
+• 
+Mid-Continent Divestitures. In December 2013, the Company divested of certain non-strategic assets located in its Mid-Continent region, with the largest transaction being the sale of the Company’s Anadarko Basin assets. Total cash proceeds received at closing (referred throughout this report as “divestiture proceeds”) were $370.3 million . The estimated net gain on these divestitures is $29.2 million . These divestitures are subject to normal post-closing adjustments and are expected to be finalized during the first half of 2014. A portion of one transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”). 
+• 
+Rocky Mountain Divestitures . During 2013, the Company divested of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were $56.3 million . The estimated net gain on these divestitures is $10.1 million . These divestitures are subject to normal post-closing adjustments and are expected to be finalized during the first half of 2014. 
+• 
+Permian Divestiture . In December 2013, the Company divested of certain non-strategic assets located in its Permian region. Total divestiture proceeds were $14.5 million . The estimated net loss on this divestiture is $6.5 million . This divestiture is subject to normal post-closing adjustments and is expected to be finalized during the first half of 2014. 
+105 
+The Company recorded an immaterial write-down to fair value less estimated costs to sale for assets that were held for sale as of December 31, 2013, which was reflected in the gain (loss) on divestiture activity line item in the accompanying statements of operations. See section Assets Held for Sale below for further discussion. 
+2012 Divestiture Activity 
+In 2012, the Company divested of various non-strategic properties located in its Rocky Mountain and 
+Mid-Continent regions. Final divestiture proceeds, after the transactions post-closed in 2013, were $57.9 million and the final net gain on these divestitures was $7.4 million . 
+During 2012, the Company reclassified a portion of the assets previously held for sale to assets held and used, as the assets were no longer being actively marketed. The assets were measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any DD&A that would have been recognized had the assets been continuously held and used, or the fair value of the assets at the date they no longer met the criteria as held for sale. As a result of this measurement, the Company recognized $1.7 million of DD&A expense and a $33.9 million loss on unsuccessful sale of properties, which is included in gain (loss) on divestiture activity in the accompanying statements of operations. 
+2011 Divestiture Activity 
+• 
+Eagle Ford Shale Divestiture. In August 2011, the Company divested of certain operated Eagle Ford shale assets located in its South Texas & Gulf Coast region. This divestiture was comprised of the Company’s entire operated acreage in LaSalle County, Texas, as well as an immaterial adjacent block of its operated acreage in Dimmit County, Texas. Total divestiture proceeds were $230.7 million . The final gain on this divestiture was $193.8 million . Please refer to Note 12 - Acquisition and Development Agreement for information on additional Eagle Ford activity in 2011. 
+• 
+Mid-Continent Divestiture. In June 2011, the Company divested of certain non-strategic assets located in its Mid-Continent region. Total divestiture proceeds were $35.8 million . The final gain on this divestiture was $28.5 million . 
+• 
+Rocky Mountain Divestiture. In January 2011, the Company divested of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were $45.5 million . The final gain on this divestiture was $27.2 million . 
+Assets Held for Sale 
+Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less costs to sell. Subsequent changes to the estimated fair value less the costs to sell will impact the measurement of assets held for sale for which fair value less costs to sell is determined to be less than the carrying value of the assets. 
+A s of December 31, 2013 , the accompanying balance sheets present $19.1 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense. A corresponding asset retirement obligation liability of $3.0 million is separately presented. The assets held for sale include the Company’s Marcellus shale assets located in Pennsylvania and other certain non-strategic assets in exploratory areas, all of which are recorded at the lesser of their carrying values or their respective fair value less estimated costs to sell. Write-downs to fair value less estimated costs to sell are reflected in the gain (loss) on divestiture activity line item in the accompanying statements of operations. 
+106 
+The Company determined that neither these planned nor executed asset sales qualify for discontinued operations accounting under financial statement presentation authoritative guidance. 
+Subsequent to December 31, 2013, the Company began marketing certain non-strategic assets in its Rocky Mountain region. The Company expects the closing of these asset sales will occur in the first half of 2014. These assets were not classified as held for sale as of December 31, 2013. 
+Note 4 – Income Taxes 
+The provision for income taxes consists of the following: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Current portion of income tax expense (benefit) 
+Federal 
+$ 
+— 
+$ 
+— 
+$ 
+(1,757 
+) 
+State 
+2,121 
+370 
+1,553 
+Deferred portion of income tax expense (benefit) 
+105,555 
+(29,638 
+) 
+123,789 
+Total income tax expense (benefit) 
+$ 
+107,676 
+$ 
+(29,268 
+) 
+$ 
+123,585 
+Effective tax rate 
+38.6 
+% 
+35.0 
+% 
+36.5 
+% 
+The Company reduces its income tax payable to reflect employee stock option exercises. There was no excess income tax benefit associated with stock awards in 2013 , 2012 , or 2011 . 
+107 
+The components of the net deferred income tax liabilities are as follows: 
+As of December 31, 
+2013 
+2012 
+(in thousands) 
+Deferred tax liabilities: 
+Oil and gas properties 
+$ 
+768,463 
+$ 
+678,624 
+Derivative asset 
+9,529 
+15,942 
+Other 
+1,245 
+6,443 
+Total deferred tax liabilities 
+779,237 
+701,009 
+Deferred tax assets: 
+Federal and state tax net operating loss carryovers 
+91,788 
+113,522 
+Net Profits Plan liability 
+20,913 
+29,233 
+Stock compensation 
+18,820 
+18,026 
+Other long-term liabilities 
+13,341 
+16,739 
+Total deferred tax assets 
+144,862 
+177,520 
+Valuation allowance 
+(5,001 
+) 
+(5,315 
+) 
+Net deferred tax assets 
+139,861 
+172,205 
+Total net deferred tax liabilities 
+639,376 
+528,804 
+Less: current deferred income tax liabilities 
+(172 
+) 
+(5,442 
+) 
+Add: current deferred income tax assets 
+10,921 
+14,021 
+Non-current net deferred tax liabilities 
+$ 
+650,125 
+$ 
+537,383 
+Current federal income tax refundable 
+$ 
+4,630 
+$ 
+2,511 
+Current state income tax refundable 
+$ 
+— 
+$ 
+853 
+Current state income tax payable 
+$ 
+1,460 
+$ 
+— 
+At December 31, 2013 , the Company estimated its federal net operating loss carryforward at $376.1 million , which includes unrecognized excess income tax benefits associated with stock awards of $126.7 million . The Company expects future excess benefit utilization to be recognized using the with-and-without method. The federal net operating loss carryforward begins to expire in 2031 . The Company has estimated state net operating loss carryforwards of $147.5 million that expire between 2014 and 2034. The Company has federal research and development (“R&D”) credit carryforwards of $5.0 million that expire between 2028 and 2031. The Company’s valuation allowance relates to charitable contribution carryfowards, state net operating loss carryforwards, state tax credits, and state and federal income tax benefit amounts, which the Company anticipates will expire before they can be utilized. The change in the valuation allowance from 2012 to 2013 primarily reflects utilization of Oklahoma net operating losses resulting from the 2013 Anadarko Basin asset divestiture gain offset in part by a change in the Company’s position regarding anticipated utilization of cumulative net operating losses attributed to other states. 
+108 
+Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, percentage depletion, R&D credits, and other permanent differences, as follows: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Federal statutory tax expense (benefit) 
+$ 
+97,514 
+$ 
+(29,231 
+) 
+$ 
+118,652 
+Increase (decrease) in tax resulting from: 
+State tax expense (benefit) (net of federal benefit) 
+9,400 
+(992 
+) 
+6,458 
+Research and development credit 
+— 
+(970 
+) 
+(4,516 
+) 
+Change in valuation allowance 
+(314 
+) 
+1,524 
+1,627 
+Statutory depletion 
+(154 
+) 
+(210 
+) 
+(341 
+) 
+Other 
+1,230 
+611 
+1,705 
+Income tax expense (benefit) 
+$ 
+107,676 
+$ 
+(29,268 
+) 
+$ 
+123,585 
+Acquisitions, divestitures, drilling activity, and basis differentials impacting the prices received for oil, gas, and NGLs affect apportionment of taxable income to the states where the Company owns oil and gas properties. As its apportionment factors change, the Company’s blended state income tax rate changes. This change, when applied to the Company’s total temporary differences, impacts the total income tax reported in the current year and is reflected in state taxes in the table above. Items affecting state apportionment factors are evaluated at the beginning of each year, after completion of the prior year income tax return, and when significant acquisition, divestiture or changes in drilling activity occurs during the year. Significant divestiture activity impacting the Company’s blended state rate occurred during the fourth quarter of 2013. 
+The Company and its subsidiaries file federal income tax returns and various state income tax returns. With certain exceptions, the Company is no longer subject to United States federal or state income tax examinations by these tax authorities for years before 2007. Federal tax law allowing for the calculation of an R&D credit was enacted in 2013, but the Company has not yet commissioned a study to calculate the credit for the 2012 or 2013 tax years. The table above excludes the impact for any credit that would be allowed under the new law in either period. The Internal Revenue Service (“IRS”) initiated an audit in the first quarter of 2012 related to R&D tax credits claimed by the Company for the 2007 through 2010 tax years. On April 23, 2013, the IRS issued a Notice of Proposed Adjustment disallowing $4.6 million of R&D tax credits claimed for open tax years during the audit period. The Company maintains it is entitled to the claimed credits and was notified during December 2013 the case has been received by the IRS Appeals office, but a conference had not been scheduled as of the filing date of this report. In the fourth quarter of 2013, the Company filed a federal net operating loss carryback claim along with other audit adjustments not processed during the 2013 audit, amounting to a $4.0 million refund. 
+On September 13, 2013 the United States Department of the Treasury and IRS issued final and re-proposed tangible property regulations effective for tax years beginning January 1, 2014. The Company has determined it is materially compliant with the requirements of these regulations as of December 31, 2013. 
+The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. Interest expense in the accompanying statements of operations includes a negligible amount associated with income taxes. In 2011, the Company also recorded a negligible amount of penalty expense associated with income taxes as a general and administrative expense. At December 31, 2013, the Company estimates the range of reasonably possible change in 2014 to the table below could be from zero to $1.4 million . 
+109 
+The total amount recorded for unrecognized tax benefits is presented below: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Beginning balance 
+$ 
+2,278 
+$ 
+1,961 
+$ 
+807 
+Additions based on tax positions related to current year 
+— 
+— 
+1,172 
+Additions for tax positions of prior years 
+80 
+317 
+183 
+Reductions for lapse of statute of limitations 
+— 
+— 
+(201 
+) 
+Ending balance 
+$ 
+2,358 
+$ 
+2,278 
+$ 
+1,961 
+Note 5 – Long-term Debt 
+Revolving Credit Facility 
+The Company and its lenders entered into a Fifth Amended and Restated Credit Agreement on April 12, 2013 , which replaced the Company's previous credit facility. The Company incurred approximately $3.4 million in deferred financing costs associated with the amendment and extension of this credit facility. The credit facility has a maximum loan amount of $2.5 billion , current aggregate lender commitments of $1.3 billion , and a maturity date of April 12, 2018 . The initial borrowing base under the credit facility was $1.9 billion . On May 20, 2013 , the Company's borrowing base under the credit facility was automatically reduced, by 25 percent of the aggregate principal amount of the newly-issued 2024 Notes, to $1.775 billion . The borrowing base is subject to regular semi-annual redeterminations. On September 6, 2013 , the lending group redetermined the Company's borrowing base under the credit facility and increased it to $2.2 billion . The borrowing base redetermination process under the credit facility considers the value of the Company's oil and gas properties and other assets, as determined by the bank group. The next scheduled redetermination date is April 1, 2014 . Borrowings under the facility are secured by a large majority of the Company's proved oil and gas properties. 
+The Company must comply with certain financial and non-financial covenants under the terms of its credit facility agreement, including limitations on dividend payments and requirements to maintain certain financial ratios, which include debt to EBITDAX, as defined by our credit agreement as the ratio of debt to 12-month trailing EBITDAX, of less than 4.0 and an adjusted current ratio, as defined by our credit agreement, of no less than 1.0 . The Company was in compliance with all financial and non-financial covenants under the credit facility as of December 31, 2013 , and through the filing date of this report. 
+Interest and commitment fees are accrued based on the borrowing base utilization grid below. Eurodollar loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table below, and Alternate Base Rate (“ABR”) and swingline loans accrue interest at Prime plus the applicable margin from the utilization table below. Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the accompanying statements of operations. 
+Borrowing Base Utilization Grid 
+Borrowing Base Utilization Percentage 
+<25% 
+≥25% <50% 
+≥50% <75% 
+≥75% <90% 
+≥90% 
+Eurodollar Loans 
+1.500 
+% 
+1.750 
+% 
+2.000 
+% 
+2.250 
+% 
+2.500 
+% 
+ABR Loans or Swingline Loans 
+0.500 
+% 
+0.750 
+% 
+1.000 
+% 
+1.250 
+% 
+1.500 
+% 
+Commitment Fee Rate 
+0.375 
+% 
+0.375 
+% 
+0.500 
+% 
+0.500 
+% 
+0.500 
+% 
+110 
+The following table presents the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Company's credit facility as of February 12, 2014 , December 31, 2013 , and December 31, 2012 : 
+As of February 12, 2014 
+As of December 31, 2013 
+As of December 31, 2012 
+(in millions) 
+Credit facility balance 
+$ 
+— 
+$ 
+— 
+$ 
+340.0 
+Letters of credit (1) 
+$ 
+0.8 
+$ 
+0.8 
+$ 
+0.8 
+Available borrowing capacity 
+$ 
+1,299.2 
+$ 
+1,299.2 
+$ 
+659.2 
+(1) Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis. 
+Senior Notes 
+The Senior Notes line on the accompanying balance sheets, as of December 31, 2013 , and 2012 , consisted of the following: 
+As of December 31, 
+2013 
+2012 
+(in thousands) 
+6.625% Senior Notes due 2019 
+$ 
+350,000 
+$ 
+350,000 
+6.50% Senior Notes due 2021 
+350,000 
+350,000 
+6.50% Senior Notes due 2023 
+400,000 
+400,000 
+5.0% Senior Notes due 2024 
+500,000 
+— 
+Total long-term debt 
+$ 
+1,600,000 
+$ 
+1,100,000 
+The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt, and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the Senior Notes. The Company is subject to certain covenants under the indenture governing the Senior Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends; provided, however, that the first $6.5 million of dividends paid each year are not restricted by the restricted payment covenant. The Company was in compliance with all covenants under its Senior Notes as of December 31, 2013 , and through the filing date of this report. 
+2024 Notes 
+On May 20, 2013 , the Company issued $500.0 million in aggregate principal amount of 5.0% Senior Notes due 2024 . The 2024 Notes were issued at par and mature on January 15, 2024 . The Company received net proceeds of $490.2 million after deducting fees of $9.8 million , which are being amortized as deferred financing costs over the life of the 2024 Notes. The net proceeds were used to reduce the Company’s outstanding credit facility balance. 
+Prior to July 15, 2016 , the Company may redeem, on one or more occasions, up to 35 percent of the aggregate principal amount of the 2024 Notes with the net cash proceeds of certain equity offerings at a redemption price of 105% of the principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 2024 Notes, in whole or in part, at any time prior to July 15, 2018 , at a redemption price equal to 100 percent of the principal amount of the 2024 Notes to be redeemed, plus a specified make-whole premium and accrued and unpaid interest to the applicable redemption date. 
+111 
+On or after July 15, 2018 , the Company may also redeem all or, from time to time, a portion of the 2024 Notes at the redemption prices set forth below, during the twelve-month period beginning on July 15 of each applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest: 
+2018 
+102.500 
+% 
+2019 
+101.677 
+% 
+2020 
+100.833 
+% 
+2021 and thereafter 
+100.000 
+% 
+Additionally, on May 20, 2013 , the Company entered into a registration rights agreement that provides holders of the 2024 Notes certain registration rights under the Securities Act. Pursuant to the registration rights agreement, the Company is required to file an exchange offer registration statement with the SEC with respect to its offer to exchange the 2024 Notes for substantially identical notes that are registered under the Securities Act. Under certain circumstances, the Company has agreed to file a shelf registration statement relating to the resale of the 2024 Notes in lieu of a registered exchange offer. If the registration statement related to the exchange offer is not declared effective on or before May 20, 2014 , or if the shelf registration statement, if required, is not declared effective within the time periods specified in the registration rights agreement, the Company has agreed to pay additional interest with respect to the 2024 Notes in an amount not to exceed one percent of the principal amount of the 2024 Notes until the exchange offer is completed or the shelf registration statement is declared effective. 
+2023 Notes 
+On June 29, 2012 , the Company issued $400.0 million in aggregate principal amount of 6.50% Senior Notes due 2023 . The 2023 Notes were issued at par and mature on January 1, 2023 . The Company received net proceeds of $392.1 million after deducting fees of $7.9 million , which are being amortized as deferred financing costs over the life of the 2023 Notes. The net proceeds were used to reduce the Company’s outstanding credit facility balance. 
+Prior to July 1, 2015 , the Company may redeem, on one or more occasions, up to 35 percent of the aggregate principal amount of the 2023 Notes with the net cash proceeds of certain equity offerings at a redemption price of 106.5% of the principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 2023 Notes, in whole or in part, at any time prior to July 1, 2017 , at a redemption price equal to 100 percent of the principal amount of the 2023 Notes to be redeemed, plus a specified make-whole premium and accrued and unpaid interest to the applicable redemption date. 
+On or after July 1, 2017 , the Company may also redeem all or, from time to time, a portion of the 2023 Notes at the redemption prices set forth below, during the twelve-month period beginning on July 1 of each applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest: 
+2017 
+103.250 
+% 
+2018 
+102.167 
+% 
+2019 
+101.083 
+% 
+2020 and thereafter 
+100.000 
+% 
+Additionally, on June 29, 2012 , the Company entered into a registration rights agreement that provides holders of the 2023 Notes certain registration rights under the Securities Act. The Company satisfied its obligations to exchange its outstanding $400.0 million of its 2023 Notes for notes registered under the Securities Act on October 30, 2012 . 
+112 
+2021 Notes 
+On November 8, 2011 , the Company issued $350.0 million in aggregate principal amount of 6.50% Senior Notes due 2021 . The 2021 Notes were issued at par and mature on November 15, 2021 . The Company received net proceeds of $343.1 million after deducting fees of $6.9 million , which are being amortized as deferred financing costs over the life of the 2021 Notes. The net proceeds were used for general corporate purposes and to reduce the Company’s outstanding credit facility balance. 
+Prior to November 15, 2014 , the Company may redeem up to 35 percent of the aggregate principal amount of the 2021 Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.5% of the principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 2021 Notes, in whole or in part, at any time prior to November 15, 2016 , at a redemption price equal to 100% of the principal amount, plus a specified make-whole premium and accrued and unpaid interest . 
+The Company may also redeem all or, from time to time, a portion of the 2021 Notes on or after November 15, 2016 , at the prices set forth below, during the twelve-month period beginning on November 15 of the applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest: 
+2016 
+103.250 
+% 
+2017 
+102.167 
+% 
+2018 
+101.083 
+% 
+2019 and thereafter 
+100.000 
+% 
+Additionally, on November 8, 2011 , the Company entered into a registration rights agreement that provides holders of the 2021 Notes certain registration rights for the 2021 Notes under the Securities Act. The Company satisfied its obligations to exchange its outstanding $350.0 million of its 2021 Notes for notes registered under the Securities Act on March 7, 2012 . 
+2019 Notes 
+On February 7, 2011 , the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2019 . The 2019 Notes were issued at par and mature on February 15, 2019 . The Company received net proceeds of $341.1 million after deducting fees of $8.9 million , which are being amortized as deferred financing costs over the life of the 2019 Notes. The net proceeds were used to repay borrowings under the Company’s credit facility, to fund the Company’s ongoing capital expenditure program, and for general corporate purposes. 
+The Company may redeem the 2019 Notes, in whole or in part, at any time prior to February 15, 2015 , at a redemption price equal to 100% of the principal amount, plus a specified make-whole premium and accrued and unpaid interest . 
+The Company may also redeem all or, from time to time, a portion of the 2019 Notes on or after February 15, 2015 , at the prices set forth below, during the twelve-month period beginning on February 15 of the applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest: 
+2015 
+103.313 
+% 
+2016 
+101.656 
+% 
+2017 and thereafter 
+100.000 
+% 
+113 
+Additionally, on February 7, 2011 , the Company entered into a registration rights agreement that provides holders of the 2019 Notes certain registration rights for the 2019 Notes under the Securities Act. The Company satisfied its obligations to exchange its outstanding $350.0 million of its 2019 Notes for notes registered under the Securities Act on January 11, 2012 . 
+3.50% Senior Convertible Notes 
+On April 2, 2012 , the Company called for redemption all of its outstanding 3.50% Senior Convertible Notes. The call for redemption resulted in holders of $281.3 million aggregate principal amount electing to convert their notes. The Company settled the principal amount of all converted 3.50% Senior Convertible Notes in cash and settled the excess conversion value by issuing 864,106 shares of its common stock. The Company redeemed the remaining $6.2 million of aggregate principal amount of notes that were not converted on the redemption date at par plus accrued interest in cash. The Company used funds borrowed under its credit facility to pay the cash portion of the settlement. 
+Capitalized Interest 
+Capitalized interest costs for the Company for the years ended December 31, 2013 , 2012 , and 2011 , were $11.0 million , $12.1 million , and $10.8 million , respectively. 
+Note 6 – Commitments and Contingencies 
+Commitments 
+The Company has entered into various agreements, which include drilling rig contracts of $65.7 million , gathering, processing, and transportation through-put commitments of $1.1 billion , office leases, including maintenance, of $69.4 million , and other miscellaneous contracts and leases of $7.6 million . The annual minimum payments for the next five years and total minimum lease payments thereafter are presented below: 
+Years Ending December 31, 
+(in thousands) 
+2014 
+$ 
+179,118 
+2015 
+147,119 
+2016 
+144,438 
+2017 
+132,559 
+2018 
+128,418 
+Thereafter 
+481,947 
+Total 
+$ 
+1,213,599 
+The Company has gathering, processing, and transportation through-put commitments with various parties that require delivery of a fixed determinable quantity of product. The aggregate minimum commitment to deliver is 1,807 Bcf of natural gas and 53 MMBbl of oil. These contracts expire at various dates through 2023 and the total amount of the commitment is approximately $1.1 billion . The Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. As of the filing date of this report, the Company does not expect to incur any material shortfalls. 
+The Company leases office space under various operating leases with terms extending as far as May 31, 2024 . During the third quarter of 2013, the Company entered into an office lease with an initial term of 12 years and minimum lease payments of $12.9 million over the term beginning on the commencement date, which is anticipated to be in the second quarter of 2014. Rent expense for 2013 , 2012 , and 2011 , was $5.7 million , $5.4 million , and $3.7 million , respectively. The Company also leases office equipment under various operating leases. 
+114 
+In addition to the amounts in the above table, the Company has committed to pay its portion of the development of infrastructure in its outside operated Eagle Ford shale play. The system owners unanimously approved budgeted costs for 2014, of which the Company is committed to pay approximately $33.0 million for the upcoming year. 
+Contingencies 
+The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such pending litigation and claims will not have a material effect on the results of operations, the financial position, or the cash flows of the Company. 
+On January 27, 2011, Chieftain filed a Class Action Petition against the Company in the District Court of Beaver County, Oklahoma, claiming damages related to royalty valuation on all of the Company's Oklahoma wells. These claims include breach of contract, breach of fiduciary duty, fraud, unjust enrichment, tortious breach of contract, conspiracy, and conversion, based generally on asserted improper deduction of post-production costs. The Company removed this lawsuit to the United States District Court for the Western District of Oklahoma on February 22, 2011. The Company responded to the petition and denied the allegations. The district court did not rule on Chieftain's motion to certify the putative class, and stayed all proceedings until the United States Court of Appeals for the Tenth Circuit issues its rulings on class certification in two similar royalty class action lawsuits. On July 9, 2013, the Tenth Circuit issued its opinions, reversing the trial courts' grant of class certification and remanding the matters to the trial courts for those cases. The district court presiding over the Company's case subsequently lifted its stay, and the Company expects Chieftain to file a new motion for class certification in the first half of 2015. 
+This case involves complex legal issues and uncertainties; a potentially large class of plaintiffs, and a large number of related producing properties, lease agreements and wells; and an alleged class period commencing in 1988 and spanning the entire producing life of the wells. Because the proceedings are in the early stages, with substantive discovery yet to be conducted, the Company is unable to estimate what impact, if any, the action will have on its financial condition, results of operations or cash flows. The Company is still evaluating the claims, but believes that it has properly paid royalties under Oklahoma law and has and will continue to vigorously defend this case. On December 30, 2013, the Company sold a substantial portion of its assets that were subject to this matter, and the buyer assumed any such liabilities related to such properties. 
+In an unrelated matter, as of and for the year ended December 31, 2013, other operating expenses includes $23.1 million related to an agreed clarification concerning royalty payment provisions of various leases on certain South Texas & Gulf Coast acreage. As of December 31, 2013, $9.6 million is included in accounts payable and accrued expenses as $13.5 million was paid in 2013. 
+Note 7 – Compensation Plans 
+Cash Bonus Plan 
+The Company has a cash bonus plan based on a performance measurement framework whereby selected eligible employee participants may be awarded an annual cash bonus. The plan document provides that no participant may receive an annual bonus under the plan of more than 200 percent of his or her base salary. As the plan is currently administered, any awards under the plan are based on Company and regional performance and are then further refined by individual performance. The Company accrues cash bonus expense based upon the Company’s current year performance. Included in general and administrative expense, lease operating expense, and exploration expense in the accompanying statements of operations are $41.8 million , $16.3 million , and $23.9 million of cash bonus expense related to the specific performance years ended December 31, 2013 , 2012 , and 2011 , respectively. 
+115 
+Equity Plan 
+There are several components to the Company’s Equity Plan that are described in this section. Various types of equity awards have been granted by the Company in different periods. 
+As of December 31, 2013 , 3.8 million shares of common stock remained available for grant under the Equity Plan. The issuance of a direct share benefit such as a share of common stock, a stock option, a restricted share, a RSU, or a PSU counts as one share against the number of shares available to be granted under the Equity Plan. Each PSU has the potential to count as two shares against the number of shares available to be granted under the Equity Plan based on the final performance multiplier. Stock options were issued out of the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan, both predecessors to the Equity Plan. 
+Performance Share Units Under the Equity Incentive Compensation Plan 
+The Company grants PSUs to eligible employees as a part of its equity compensation program. The PSU factor is based on the Company’s performance after completion of a three-year performance period. The performance criteria for the PSUs are based on a combination of the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of certain peer companies for the performance period. PSUs are recognized as general and administrative and exploration expense over the vesting period of the award. 
+The fair value of PSUs was measured at the grant date with a stochastic process method using the Geometric Brownian Motion Model (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three-year performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, dividend yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a three-year vesting period, as well as the volatilities and dividend yields for each of the Company’s peers. 
+Total expense recorded for PSUs was $16.8 million , $18.2 million , and $19.7 million for the years ended December 31, 2013 , 2012 , and 2011 , respectively. As of December 31, 2013 , there was $18.8 million of total unrecognized expense related to PSUs, which is being amortized through 2016 . 
+116 
+A summary of the status and activity of non-vested PSUs is presented in the following table: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+PSUs 
+Weighted-Average Grant-Date Fair Value 
+PSUs 
+Weighted-Average Grant-Date Fair Value 
+PSUs 
+Weighted-Average Grant-Date Fair Value 
+Non-vested at beginning of year (1) 
+669,308 
+$ 
+63.91 
+885,894 
+$ 
+57.52 
+1,110,666 
+$ 
+39.48 
+Granted (1) 
+274,831 
+$ 
+64.13 
+314,853 
+$ 
+51.98 
+266,282 
+$ 
+91.45 
+Vested (1) 
+(345,005 
+) 
+$ 
+60.06 
+(493,679 
+) 
+$ 
+44.72 
+(364,172 
+) 
+$ 
+35.74 
+Forfeited (1) 
+(26,665 
+) 
+$ 
+69.74 
+(37,760 
+) 
+$ 
+65.35 
+(126,882 
+) 
+$ 
+33.32 
+Non-vested at end of year (1) 
+572,469 
+$ 
+66.07 
+669,308 
+$ 
+63.91 
+885,894 
+$ 
+57.52 
+(1) 
+The number of awards assumes a one multiplier. The final number of shares of common stock issued may vary depending on the ending three -year performance multiplier, which ranges from zero to two . 
+The fair value of the PSUs granted in 2013 , 2012 , and 2011 was $17.6 million , $16.4 million , and $24.3 million for the 2013 , 2012 , and 2011 grants, respectively. The PSUs granted in 2013 will remain unvested until the third anniversary date of their issuance, at which time they will fully vest. The PSUs granted in 2012 will vest 1/3 on each of the first three anniversary dates of their issuance. PSUs granted prior to 2012 vest 1/7 th , 2/7 ths , and 4/7 ths , respectively, on the first three anniversary dates of their issuances. 
+The total fair value of PSUs that vested during the years ended December 31, 2013 , 2012 , and 2011 was $20.7 million , $22.1 million , and $13.0 million , respectively. 
+During the year ended December 31, 2013 , the Company settled PSUs that were granted in 2010 , and which had earned a 1.725 -times multiplier, by issuing a net 387,461 shares of the Company’s common stock in accordance with the terms of the PSU awards. The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, 200,050 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs for 2013 . 
+During the year ended December 31, 2012, the Company settled PSUs that were granted in 2009, which earned a 2.0 -times multiplier, by issuing a net 812,562 shares of the Company’s common stock in accordance with the terms of the PSU awards. The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, 406,866 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs for 2012. 
+During the year ended December 31, 2011 , the Company settled PSUs that were granted in 2008, and which had earned a 0.8 -times multiplier, by issuing a net 206,468 shares of the Company’s common stock in accordance with the terms of the PSU awards. The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, 98,955 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs for 2011 . 
+117 
+Restricted Stock Units Under the Equity Incentive Compensation Plan 
+The Company grants RSUs to eligible employees as a part of its equity incentive compensation program. Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each RSU represents a right for one share of the Company’s common stock to be delivered upon settlement of the award at the end of a specified period. RSUs are recognized as general and administrative and exploration expense over the vesting period of the award. 
+The total expense associated with RSUs for the years ended December 31, 2013 , 2012 , and 2011 , was $13.1 million , $9.8 million , and $5.3 million , respectively. As of December 31, 2013 , there was $19.3 million of total unrecognized expense related to unvested RSU awards, which is being amortized through 2016 . The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the day of grant. 
+A summary of the status and activity of non-vested RSUs is presented below: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+RSUs 
+Weighted- 
+Average 
+Grant-Date 
+Fair Value 
+Non-vested at beginning of year 
+496,244 
+$ 
+51.81 
+308,877 
+$ 
+44.33 
+333,359 
+$ 
+31.16 
+Granted 
+329,939 
+$ 
+60.01 
+379,332 
+$ 
+49.47 
+98,952 
+$ 
+72.69 
+Vested 
+(207,376 
+) 
+$ 
+49.73 
+(166,672 
+) 
+$ 
+32.72 
+(105,820 
+) 
+$ 
+30.61 
+Forfeited 
+(38,376 
+) 
+$ 
+54.37 
+(25,293 
+) 
+$ 
+51.06 
+(17,614 
+) 
+$ 
+36.80 
+Non-vested at end of year 
+580,431 
+$ 
+57.05 
+496,244 
+$ 
+51.81 
+308,877 
+$ 
+44.33 
+The fair value of RSUs granted in 2013 , 2012 , and 2011 was $19.8 million , $18.8 million , and $7.2 million , respectively. The RSUs granted in 2013 and 2012 will vest 1/3 on each of the first three anniversary dates of the awards. RSUs granted prior to 2012 vest 1/7 th , 2/7 ths , and 4/7 ths , respectively, on the first three anniversary dates of their issuances. 
+The total fair value of RSUs that vested during the years ended December 31, 2013 , 2012 , and 2011 , was $10.3 million , $5.4 million , and $3.2 million , respectively. 
+During the years ended December 31, 2013 , 2012 , and 2011 , the Company settled 207,378 , 166,670 , and 105,820 RSUs, respectively. The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, the Company issued net shares of common stock of 139,391 , 116,813 , and 72,305 for 2013 , 2012 , and 2011 , respectively. The remaining 67,987 , 49,857 , and 33,515 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon the delivery of the shares underlying those RSUs for 2013 , 2012 , and 2011 , respectively. 
+118 
+Stock Option Grants Under the Equity Incentive Compensation Plan 
+The Company has previously granted stock options under the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan. The last issuance of stock options occurred on December 31, 2004. Stock options to purchase shares of the Company’s common stock had been granted to eligible employees and members of the Board of Directors. All options granted under the option plans were granted at exercise prices equal to the respective closing market price of the Company’s underlying common stock on the grant dates. All stock options granted under the option plans are exercisable for a period of up to ten years from the date of grant. As of December 31, 2013 , there was no unrecognized compensation expense related to stock option awards. 
+A summary of activity associated with the Company’s Stock Option Plans during the last three years is presented in the following table: 
+Weighted - 
+Average 
+Aggregate 
+Exercise 
+Intrinsic 
+Shares 
+Price 
+Value 
+For the year ended December 31, 2011 
+Outstanding, start of year 
+920,765 
+$ 
+13.11 
+Exercised 
+(412,551 
+) 
+$ 
+12.19 
+$ 
+24,359,240 
+Forfeited 
+— 
+$ 
+— 
+Outstanding, end of year 
+508,214 
+$ 
+13.86 
+$ 
+30,109,110 
+Vested and exercisable at end of year 
+508,214 
+$ 
+13.86 
+$ 
+30,109,110 
+For the year ended December 31, 2012 
+Outstanding, start of year 
+508,214 
+$ 
+13.86 
+Exercised 
+(240,368 
+) 
+$ 
+12.65 
+$ 
+11,842,575 
+Forfeited 
+— 
+$ 
+— 
+Outstanding, end of year 
+267,846 
+$ 
+14.95 
+$ 
+9,983,177 
+Vested and exercisable at end of year 
+267,846 
+$ 
+14.95 
+$ 
+9,983,177 
+For the year ended December 31, 2013 
+Outstanding, start of year 
+267,846 
+$ 
+14.95 
+Exercised 
+(228,758 
+) 
+$ 
+13.92 
+$ 
+12,326,994 
+Forfeited 
+— 
+$ 
+— 
+Outstanding, end of year 
+39,088 
+$ 
+20.87 
+$ 
+2,432,837 
+Vested and exercisable at end of year 
+39,088 
+$ 
+20.87 
+$ 
+2,432,837 
+A summary of additional information related to options outstanding as of December 31, 2013 , follows: 
+Options Outstanding and Exercisable 
+Number 
+Weighted- 
+Of Options 
+Average 
+Outstanding 
+Remaining 
+Exercise 
+and 
+Contractual 
+Price (1) 
+Exercisable 
+Life (in years) 
+$ 
+20.87 
+39,088 
+1 
+Total 
+39,088 
+(1) Exercise price is equal to the weighted average exercise price. 
+119 
+The fair value of options was measured at the date of grant using the Black-Scholes-Merton option-pricing model. 
+Cash flows resulting from excess tax benefits are classified as part of cash flows from financing activities. Excess tax benefits are realized tax benefits from tax deductions for vested RSUs, settled PSUs, and exercised options in excess of the deferred tax asset attributable to stock compensation costs for such equity awards. The Company recorded no excess tax benefits for the years ended December 31, 2013 , 2012 , and 2011 . Cash received from exercises under all share-based payment arrangements for the years ended December 31, 2013 , 2012 , and 2011 , was $3.2 million , $3.0 million , and $5.0 million , respectively. 
+Director Shares 
+In 2013 , 2012 , and 2011 , the Company issued 28,169 , 30,486 , and 21,568 shares, respectively, of the Company’s common stock held as treasury shares to its non-employee directors pursuant to the Company’s Equity Plan. The Company recorded compensation expense related to these issuances of $1.4 million , $1.3 million , and $1.2 million for the years ended December 31, 2013 , 2012 , and 2011 , respectively. 
+Employee Stock Purchase Plan 
+Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in fair market value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the purchase period. All shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of the IRC. The Company has 1.2 million shares available under the ESPP for issuance as of December 31, 2013 . Shares issued under the ESPP totaled 77,427 in 2013 , 66,485 in 2012 , and 41,358 in 2011 . Total proceeds to the Company for the issuance of these shares were $3.7 million in 2013 , $2.8 million in 2012 , and $2.3 million in 2011 . 
+The fair value of ESPP shares was measured at the date of grant using the Black-Scholes-Merton option-pricing model. Expected volatility was calculated based on the Company’s historical daily common stock price, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with a six month vesting period. 
+The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+Risk free interest rate 
+0.1 
+% 
+0.1 
+% 
+0.2 
+% 
+Dividend yield 
+0.2 
+% 
+0.2 
+% 
+0.2 
+% 
+Volatility factor of the expected market 
+price of the Company’s common stock 
+41.1 
+% 
+47.8 
+% 
+36.3 
+% 
+Expected life (in years) 
+0.5 
+0.5 
+0.5 
+The Company expensed $1.1 million , $948,000 , and $682,000 for the years ended December 31, 2013 , 2012 , and 2011 , respectively, based on the estimated fair value of grants. 
+120 
+401(k) Plan 
+The Company has a defined contribution pension plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute a maximum of 60 percent of their base salaries up to the contribution limits established under the IRC. The Company matches each employee’s contribution up to six percent of the employee’s base salary and may make additional contributions at its discretion. Beginning in 2014, the Company will also match employee contributions up to six percent of the employee's bonus paid pursuant to the Company's cash bonus plan. The Company’s matching contributions to the 401(k) Plan were $4.2 million , $3.5 million , and $2.9 million for the years ended December 31, 2013 , 2012 , and 2011 , respectively. No discretionary contributions were made by the Company to the 401(k) Plan for any of these years. 
+Net Profits Plan 
+Under the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during each year were designated within a specific pool. Key employees recommended by senior management and designated as participants by the Compensation Committee of the Company’s Board of Directors and employed by the Company on the last day of that year became entitled to payments under the Net Profits Plan after the Company has received net cash flows returning 100 percent of all costs associated with that pool. Thereafter, 10 percent of future net cash flows generated by the pool are allocated among the participants and distributed at least annually. The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the Company has recovered 200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the 10 percent level. In December 2007, the Board of Directors discontinued the creation of new pools under the Net Profits Plan. As a result, the 2007 pool was the last Net Profits Plan pool established by the Company. 
+Cash payments made or accrued under the Net Profits Plan that have been recorded as either general and administrative expense or exploration expense are detailed in the table below: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+General and administrative expense 
+$ 
+13,734 
+$ 
+15,565 
+$ 
+19,326 
+Exploration expense 
+1,310 
+1,751 
+2,091 
+Total 
+$ 
+15,044 
+$ 
+17,316 
+$ 
+21,417 
+Additionally, the Company made or accrued cash payments under the Net Profits Plan of $10.3 million , $2.3 million , and $6.3 million for the years ended December 31, 2013 , 2012 , and 2011 , respectively, as a result of divestiture proceeds. The cash payments are accounted for as a reduction in the gain (loss) on divestiture activity line item in the accompanying statements of operations. 
+The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate line item in the accompanying statements of operations. The change in the estimated liability is recorded as a non-cash expense or benefit in the current period. The amount recorded as an expense or benefit associated with the change in the estimated liability is not allocated to general and administrative expense or exploration expense because it is associated with the future net cash flows from oil and gas properties in the respective pools rather than results being realized through current period production. If the Company allocated the change in liability to these specific functional line items, based on the current allocation of actual distributions made by the Company, such expenses or benefits would predominately be allocated to general and administrative expense. The amount that would be allocated to exploration expense is minimal in comparison. Over time, less of the amount distributed relates to prospective exploration efforts as more of the amount distributed is paid to employees that have terminated employment and do not provide ongoing exploration support to the Company. 
+121 
+Note 8 – Pension Benefits 
+The Company has a non-contributory defined benefit pension plan covering substantially all employees who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). 
+Obligations and Funded Status for Both Pension Plans 
+The Company recognizes the funded status, (i.e. the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment to accumulated other comprehensive income, net of tax. The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31. 
+For the Years Ended December 31, 
+2013 
+2012 
+(in thousands) 
+Change in benefit obligation: 
+Projected benefit obligation at beginning of year 
+$ 
+40,237 
+$ 
+29,480 
+Service cost 
+6,291 
+4,934 
+Interest cost 
+1,627 
+1,374 
+Plan amendments 
+— 
+— 
+Actuarial loss (gain) 
+(1,577 
+) 
+5,467 
+Benefits paid 
+(3,293 
+) 
+(1,018 
+) 
+Projected benefit obligation at end of year 
+43,285 
+40,237 
+Change in plan assets: 
+Fair value of plan assets at beginning of year 
+20,254 
+13,940 
+Actual return on plan assets 
+2,726 
+1,952 
+Employer contribution 
+4,971 
+5,380 
+Benefits paid 
+(3,293 
+) 
+(1,018 
+) 
+Fair value of plan assets at end of year 
+24,658 
+20,254 
+Funded status at end of year 
+$ 
+(18,627 
+) 
+$ 
+(19,983 
+) 
+The Company’s underfunded status for the Pension Plans for the years ended December 31, 2013 and 2012 , is $18.6 million and $20.0 million , respectively, and is recognized in the accompanying balance sheets as a portion of other noncurrent liabilities. No plan assets of the Qualified Pension Plan were returned to the Company during the fiscal year ended December 31, 2013 . There are no plan assets in the Nonqualified Pension Plan. The plan was amended in 2011 to increase the vesting percent to 40 percent after attaining two years of service and increasing by 20 percent per year until fully vested. 
+122 
+Information for Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets for Both Plans 
+As of December 31, 
+2013 
+2012 
+(in thousands) 
+Projected benefit obligation 
+$ 
+43,285 
+$ 
+40,237 
+Accumulated benefit obligation 
+$ 
+32,396 
+$ 
+29,437 
+Less: Fair value of plan assets 
+(24,658 
+) 
+(20,254 
+) 
+Underfunded accumulated benefit obligation 
+$ 
+7,738 
+$ 
+9,183 
+Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the interest cost on those liabilities, less the expected return on plan assets. The expected long-term rate of return on plan assets is applied to a calculated value of plan assets that recognizes changes in fair value over a five-year period. This practice is intended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences between actual returns on assets and expected returns based on long-term rate of return assumptions. Amortization of unrecognized net gain or loss resulting from actual experience different from that assumed and from changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of net periodic benefit cost for a year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation and the market-related value of plan assets, then the amortization is the excess divided by the average remaining service period of participating employees expected to receive benefits under the plan. 
+Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated other comprehensive loss as of December 31, 2013 and 2012 , consist of: 
+As of December 31, 
+2013 
+2012 
+(in thousands) 
+Unrecognized actuarial losses 
+$ 
+8,439 
+$ 
+12,427 
+Unrecognized prior service costs 
+136 
+153 
+Unrecognized transition obligation 
+— 
+— 
+Accumulated other comprehensive loss 
+$ 
+8,575 
+$ 
+12,580 
+The estimated net loss that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year is $436,000 . 
+123 
+Pre-tax changes recognized in other comprehensive income (loss) during 2013 , 2012 , and 2011 , were as follows: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Net actuarial gain (loss) 
+$ 
+2,766 
+$ 
+(4,680 
+) 
+$ 
+(3,014 
+) 
+Prior service cost 
+— 
+— 
+(170 
+) 
+Less: Amortization of: 
+Prior service cost 
+(17 
+) 
+(17 
+) 
+— 
+Actuarial loss 
+(1,222 
+) 
+(754 
+) 
+(405 
+) 
+Total other comprehensive income (loss) 
+$ 
+4,005 
+$ 
+(3,909 
+) 
+$ 
+(2,779 
+) 
+Components of Net Periodic Benefit Cost for Both Pension Plans 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Components of net periodic benefit cost: 
+Service cost 
+$ 
+6,291 
+$ 
+4,934 
+$ 
+3,800 
+Interest cost 
+1,627 
+1,374 
+1,184 
+Expected return on plan assets that reduces periodic pension cost 
+(1,538 
+) 
+(1,165 
+) 
+(880 
+) 
+Amortization of prior service cost 
+17 
+17 
+— 
+Amortization of net actuarial loss 
+1,222 
+754 
+405 
+Net periodic benefit cost 
+$ 
+7,619 
+$ 
+5,914 
+$ 
+4,509 
+Gains and losses in excess of 10 percent of the greater of the benefit obligation and the market-related value of assets are amortized over the average remaining service period of active participants. 
+Pension Plan Assumptions 
+Weighted-average assumptions to measure the Company’s projected benefit obligation and net periodic benefit cost are as follows: 
+As of December 31, 
+2013 
+2012 
+2011 
+Projected benefit obligation 
+Discount rate 
+5.0% 
+3.9% 
+4.7% 
+Rate of compensation increase 
+6.2% 
+6.2% 
+6.2% 
+Net periodic benefit cost 
+Discount rate 
+3.9% 
+4.7% 
+5.3% 
+Expected return on plan assets 
+7.5% 
+7.5% 
+7.5% 
+Rate of compensation increase 
+6.2% 
+6.2% 
+6.2% 
+The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans. The policy does not permit the direct investment of plan assets in the Company’s securities. The Qualified Pension Plan's investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term 
+124 
+perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of diversification, assessment of risk, and targeting the optimal expected returns for given levels of risk are applied. 
+The Qualified Pension Plan's investment portfolio contains a diversified blend of investments, which may reflect varying rates of return. The investments are further diversified within each asset classification. This portfolio diversification provides protection against a single security or class of securities having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a periodic basis to maintain the target allocations. The weighted-average asset allocation of the Qualified Pension Plan is as follows: 
+Target 
+As of December 31, 
+Asset Category 
+2014 
+2013 
+2012 
+Equity securities 
+44.0 
+% 
+43.6 
+% 
+42.7 
+% 
+Debt securities 
+33.0 
+% 
+32.2 
+% 
+32.8 
+% 
+Other 
+23.0 
+% 
+24.2 
+% 
+24.5 
+% 
+Total 
+100.0 
+% 
+100.0 
+% 
+100.0 
+% 
+There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in that plan. An expected return on plan assets of 7.5 percent was used to calculate the Company’s obligation under the Qualified Pension Plan for 2013 and 2012 . Factors considered in determining the expected rate of return include the long-term historical rate of return provided by the equity and debt securities markets and input from the investment consultants and trustees managing the plan assets. The difference in investment income using the projected rate of return compared to the actual rates of return for the past two years was not material and is not expected to have a material effect on the accompanying statements of operations or cash flows from operating activities in future years. 
+125 
+Fair Value Assumptions 
+The fair value of the Company’s Qualified Pension Plan assets as of December 31, 2013 , utilizing the fair value hierarchy discussed in Note 11 – Fair Value Measurements is as follows: 
+Fair Value Measurements Using: 
+Actual Asset Allocation 
+Total 
+Level 1 Inputs 
+Level 2 Inputs 
+Level 3 Inputs 
+(in thousands) 
+Cash 
+— 
+% 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Equity Securities 
+Domestic (1) 
+29.9 
+% 
+7,371 
+4,888 
+2,483 
+— 
+International (2) 
+13.7 
+% 
+3,373 
+3,373 
+— 
+— 
+Total Equity Securities 
+43.6 
+% 
+10,744 
+8,261 
+2,483 
+— 
+Fixed Income Securities 
+High-Yield Bonds (3) 
+5.9 
+% 
+1,448 
+1,448 
+— 
+— 
+Core Fixed Income (4) 
+20.3 
+% 
+5,006 
+5,006 
+— 
+— 
+Floating Rate Corp Loans (5) 
+6.0 
+% 
+1,483 
+1,483 
+— 
+— 
+Total Fixed Income Securities 
+32.2 
+% 
+7,937 
+7,937 
+— 
+— 
+Other Securities: 
+Commodities (6) 
+3.8 
+% 
+945 
+945 
+— 
+— 
+Real Estate (7) 
+3.5 
+% 
+859 
+— 
+— 
+859 
+Hedge Fund (8) 
+14.3 
+% 
+3,517 
+955 
+— 
+2,562 
+Collective Investment Trusts (9) 
+2.6 
+% 
+656 
+— 
+656 
+— 
+Total Other Securities 
+24.2 
+% 
+5,977 
+1,900 
+656 
+3,421 
+Total Investments 
+100.0 
+% 
+$ 
+24,658 
+$ 
+18,098 
+$ 
+3,139 
+$ 
+3,421 
+(1) 
+Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of this fund is to approximate the S&P 500 by investing in one or more collective investment funds. 
+(2) 
+International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations. 
+(3) 
+High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis. 
+(4) 
+The objective is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay's Capital Aggregate Bond Index with a modest amount of variability in duration around the index. 
+(5) 
+Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. 
+(6) 
+Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities. 
+(7) 
+The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity. 
+(8) 
+The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies. 
+(9) 
+Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities. 
+126 
+Included below is a summary of the changes in Level 3 plan assets (in thousands): 
+December 31, 2012 
+$ 
+2,384 
+Purchases 
+742 
+Realized gain on assets 
+161 
+Unrealized gain on assets 
+134 
+December 31, 2013 
+$ 
+3,421 
+The fair value of the Company’s pension plan assets as of December 31, 2012 , is as follows: 
+Fair Value Measurements Using: 
+Actual Asset Allocation 
+Total 
+Level 1 Inputs 
+Level 2 Inputs 
+Level 3 Inputs 
+(in thousands) 
+Cash and Money Market Funds 
+3.8 
+% 
+$ 
+778 
+$ 
+778 
+$ 
+— 
+$ 
+— 
+Equity Securities 
+Domestic (1) 
+29.2 
+% 
+5,920 
+5,920 
+— 
+— 
+International (2) 
+13.5 
+% 
+2,740 
+2,740 
+— 
+— 
+Total Equity Securities 
+42.7 
+% 
+8,660 
+8,660 
+— 
+— 
+Fixed Income Securities 
+High-Yield Bonds (3) 
+6.1 
+% 
+1,240 
+1,240 
+— 
+— 
+Core Fixed Income (4) 
+20.8 
+% 
+4,204 
+4,204 
+— 
+— 
+Floating Rate Corp Loans (5) 
+5.9 
+% 
+1,186 
+1,186 
+— 
+— 
+Total Fixed Income Securities 
+32.8 
+% 
+6,630 
+6,630 
+— 
+— 
+Other Securities: 
+Commodities (6) 
+3.3 
+% 
+669 
+669 
+— 
+— 
+Real Estate (7) 
+3.9 
+% 
+783 
+— 
+— 
+783 
+Hedge Fund (8) 
+13.5 
+% 
+2,734 
+1,133 
+— 
+1,601 
+Total Other Securities 
+20.7 
+% 
+4,186 
+1,802 
+— 
+2,384 
+Total Investments 
+100.0 
+% 
+$ 
+20,254 
+$ 
+17,870 
+$ 
+— 
+$ 
+2,384 
+(1) 
+Equity securities of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. 
+(2) 
+International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations. 
+(3) 
+High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis. 
+(4) 
+The objective is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay's Capital Aggregate Bond Index with a modest amount of variability in duration around the index. 
+(5) 
+Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. 
+(6) 
+Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities. 
+(7) 
+The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity. 
+(8) 
+The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies. 
+127 
+Included below is a summary of the changes in Level 3 plan assets (in thousands): 
+December 31, 2011 
+$ 
+— 
+Purchases 
+2,329 
+Investment Returns 
+55 
+December 31, 2012 
+$ 
+2,384 
+Contributions 
+The Company contributed $5.0 million , $5.4 million , and $5.3 million , to the Pension Plans in the years ended December 31, 2013 , 2012 , and 2011 , respectively. The Company is expected to make a $4.3 million contribution to the Pension Plans in 2014 . 
+Benefit Payments 
+The Pension Plans made actual benefit payments of $3.3 million , $1.0 million , and $1.5 million in the years ended December 31, 2013 , 2012 , and 2011 , respectively. Expected benefit payments over the next 10 years are as follows: 
+Years Ending December 31, 
+(in thousands) 
+2014 
+$ 
+2,120 
+2015 
+$ 
+2,837 
+2016 
+$ 
+3,287 
+2017 
+$ 
+3,993 
+2018 
+$ 
+4,407 
+2019 through 2023 
+$ 
+33,031 
+Note 9 – Asset Retirement Obligations 
+The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement obligations is included in the operating section of the Company’s accompanying statements of cash flows. 
+The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s abandonment liabilities range from 5.5 percent to 12 percent . Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives or if federal or state regulators enact new requirements regarding the abandonment of wells. 
+128 
+A reconciliation of the Company’s asset retirement obligation liability is as follows: 
+As of December 31, 
+2013 
+2012 
+(in thousands) 
+Beginning asset retirement obligation 
+$ 
+120,518 
+$ 
+95,906 
+Liabilities incurred 
+18,682 
+13,050 
+Liabilities settled 
+(33,129 
+) 
+(8,101 
+) 
+Accretion expense 
+5,997 
+4,679 
+Revision to estimated cash flows 
+9,118 
+14,984 
+Ending asset retirement obligation 
+$ 
+121,186 
+$ 
+120,518 
+As of December 31, 2013 and 2012 , the Company had $3.0 million and $1.4 million , respectively, of asset retirement obligation associated with the oil and gas properties held for sale included in a separate line item on the Company’s accompanying balance sheets. Additionally, as of December 31, 2013 and 2012 , accounts payable and accrued expenses contain $2.5 million and $6.2 million , respectively, related to the Company’s current asset retirement obligation liability for estimated plugging and abandonment costs associated with platforms that are being relinquished or retired. 
+Note 10 – Derivative Financial Instruments 
+Summary of Oil, Gas, and NGL Derivative Contracts in Place 
+The Company has entered into various commodity derivative contracts to mitigate a portion of the exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. The Company’s derivative contracts in place include swap and collar arrangements for oil, gas, and NGLs. 
+As of December 31, 2013 , the Company has commodity derivative contracts outstanding through the second quarter of 2018 for a total of 18.8 million Bbls of oil production, 265.9 million MMBtu of gas production, and 2.5 million Bbls of NGL production. As of February 12, 2014 , the Company had commodity derivative contracts in place through the second quarter of 2018 for a total of 17.5 million Bbls of oil, 237.9 million MMBtu of gas, and 4.0 million Bbls of NGLs. These volumes are net of scheduled January 2014 settlements, as well as the early settlement of 18.0 million MMBtu of gas swaps and collars in January 2014 due to the divestiture of assets in our Mid-Continent region at the end of 2013 . 
+In a typical commodity swap agreement, if the agreed upon published third-party index price is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar agreements, the Company receives the difference between an agreed upon index and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices. 
+129 
+The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place as of December 31, 2013 : 
+Oil Contracts 
+Oil Swaps 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+(Bbls) 
+(per Bbl) 
+First quarter 2014 
+2,600,000 
+$ 
+96.92 
+Second quarter 2014 
+2,373,000 
+$ 
+94.95 
+Third quarter 2014 
+973,000 
+$ 
+95.25 
+Fourth quarter 2014 
+891,000 
+$ 
+95.16 
+2015 
+2,911,000 
+$ 
+89.06 
+2016 
+2,704,000 
+$ 
+85.19 
+All oil swaps* 
+12,452,000 
+*Oil swaps are comprised of NYMEX WTI ( 97% ) and Argus LLS ( 3% ). 
+Oil Collars 
+Contract Period 
+NYMEX WTI 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+(Bbls) 
+(per Bbl) 
+(per Bbl) 
+First quarter 2014 
+694,000 
+$ 
+80.97 
+$ 
+115.07 
+Second quarter 2014 
+431,000 
+$ 
+85.00 
+$ 
+102.50 
+Third quarter 2014 
+973,000 
+$ 
+85.00 
+$ 
+102.58 
+Fourth quarter 2014 
+923,000 
+$ 
+85.00 
+$ 
+102.63 
+2015 
+3,366,000 
+$ 
+85.00 
+$ 
+94.25 
+All oil collars 
+6,387,000 
+130 
+Natural Gas Contracts 
+Gas Swaps 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+(MMBtu) 
+(per MMBtu) 
+First quarter 2014 
+33,651,000 
+$ 
+4.25 
+Second quarter 2014 
+25,729,000 
+$ 
+3.96 
+Third quarter 2014 
+26,398,000 
+$ 
+4.01 
+Fourth quarter 2014 
+23,965,000 
+$ 
+4.01 
+2015 
+63,317,000 
+$ 
+4.03 
+2016 
+39,014,000 
+$ 
+4.18 
+2017 
+23,430,000 
+$ 
+4.21 
+2018 
+10,200,000 
+$ 
+4.31 
+All gas swaps* 
+245,704,000 
+*Natural gas swaps are comprised of IF El Paso Permian ( 3% ), IF HSC ( 77% ), IF NGPL TXOK ( 3% ), IF NNG Ventura ( 2% ), IF PEPL ( 6% ), IF Reliant N/S ( 8% ), and IF NGPL MidCon ( 1% ). 
+Gas Collars 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Floor 
+Price 
+Weighted- 
+Average 
+Ceiling 
+Price 
+(MMBtu) 
+(per MMBtu) 
+(per MMBtu) 
+First quarter 2014 
+1,540,000 
+$ 
+4.39 
+$ 
+5.58 
+Second quarter 2014 
+4,194,000 
+$ 
+4.38 
+$ 
+5.29 
+2015 
+14,480,000 
+$ 
+3.96 
+$ 
+4.30 
+All gas collars* 
+20,214,000 
+*Natural gas collars are comprised of IF El Paso Permian ( 2% ), IF HSC ( 57% ), IF NGPL TXOK ( 3% ), IF NNG Ventura ( 5% ), IF PEPL ( 7% ), IF Reliant N/S ( 14% ), and IF TETCO STX ( 12% ). 
+131 
+NGL Contracts 
+NGL Swaps 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+(Bbls) 
+(per Bbl) 
+First quarter 2014 
+913,000 
+$ 
+59.72 
+Second quarter 2014 
+565,000 
+$ 
+63.22 
+Third quarter 2014 
+544,000 
+$ 
+62.34 
+Fourth quarter 2014 
+527,000 
+$ 
+61.57 
+All NGL swaps* 
+2,549,000 
+*NGL swaps are comprised of OPIS IsoButane Mt Belv Non TET ( 2% ), OPIS Natural Gasoline Mt Belv Non TET ( 34% ), OPIS NButane Mt Belv Non TET ( 3% ), and OPIS Propane Mt Belv TET ( 61% ). 
+Commodity Derivative Contracts Entered into After December 31, 2013 
+The following tables summarize all commodity derivative contracts entered between January 1, 2014 and February 12, 2014 : 
+Gas Contracts 
+Gas Swaps 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+(MMBtu) 
+(per MMBtu) 
+First quarter 2014 
+261,000 
+$ 
+4.39 
+Second quarter 2014 
+365,000 
+$ 
+3.84 
+Third quarter 2014 
+341,000 
+$ 
+3.89 
+Fourth quarter 2014 
+321,000 
+$ 
+3.97 
+2015 
+1,133,000 
+$ 
+3.72 
+2016 
+69,000 
+$ 
+4.12 
+All gas swaps* 
+2,490,000 
+*Natural gas swaps are comprised of IF NNG Ventura ( 30% ) and IF CIG N System ( 70% ) . 
+132 
+NGL Contracts 
+NGL Swaps 
+Contract Period 
+Volumes 
+Weighted- 
+Average 
+Contract 
+Price 
+(Bbls) 
+(per Bbl) 
+First quarter 2014 
+516,000 
+$ 
+54.85 
+Second quarter 2014 
+531,000 
+$ 
+52.53 
+Third quarter 2014 
+416,000 
+$ 
+52.47 
+Fourth quarter 2014 
+334,000 
+$ 
+52.52 
+All NGL swaps* 
+1,797,000 
+*NGL swaps are comprised of OPIS Natural Gasoline Mt Belv Non TET ( 17% ) and OPIS Propane Mt Belv TET ( 83% ) . 
+Derivative Assets and Liabilities Fair Value 
+The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The fair value of the commodity derivative contracts was a net asset of $21.5 million and $38.7 million at December 31, 2013 and 2012 , respectively. 
+The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: 
+As of December 31, 2013 
+Derivative Assets 
+Derivative Liabilities 
+Balance Sheet 
+Classification 
+Fair Value 
+Balance Sheet 
+Classification 
+Fair Value 
+(in thousands) 
+Commodity Contracts 
+Current assets 
+$ 
+21,559 
+Current liabilities 
+$ 
+26,380 
+Commodity Contracts 
+Noncurrent assets 
+30,951 
+Noncurrent liabilities 
+4,640 
+Derivatives not designated as hedging instruments 
+$ 
+52,510 
+$ 
+31,020 
+As of December 31, 2012 
+Derivative Assets 
+Derivative Liabilities 
+Balance Sheet 
+Classification 
+Fair Value 
+Balance Sheet 
+Classification 
+Fair Value 
+(in thousands) 
+Commodity Contracts 
+Current assets 
+$ 
+37,873 
+Current liabilities 
+$ 
+8,999 
+Commodity Contracts 
+Noncurrent assets 
+16,466 
+Noncurrent liabilities 
+6,645 
+Derivatives not designated as hedging instruments 
+$ 
+54,339 
+$ 
+15,644 
+133 
+Offsetting of Derivative Assets and Liabilities 
+As of December 31, 2013 and 2012 , all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company's accounting policy is to not offset these positions in its accompanying balance sheets. 
+The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company's derivative contracts: 
+Derivative Assets 
+Derivative Liabilities 
+As of December 31, 
+As of December 31, 
+Offsetting of Derivative Assets and Liabilities 
+2013 
+2012 
+2013 
+2012 
+(in thousands) 
+Gross amounts presented in the accompanying balance sheets 
+$ 
+52,510 
+$ 
+54,339 
+$ 
+(31,020 
+) 
+$ 
+(15,644 
+) 
+Amounts not offset in the accompanying balance sheets 
+(30,652 
+) 
+(13,400 
+) 
+30,652 
+13,400 
+Net amounts 
+$ 
+21,858 
+$ 
+40,939 
+$ 
+(368 
+) 
+$ 
+(2,244 
+) 
+Discontinuance of Cash Flow Hedge Accounting 
+Prior to January 1, 2011, the Company designated its commodity derivative contracts as cash flow hedges, for which unrealized changes in fair value were recorded to AOCIL, to the extent the hedges were effective. As of January 1, 2011, the Company elected to de-designate all of its commodity derivative contracts that had been previously designated as cash flow hedges at December 31, 2010. As a result, subsequent to December 31, 2010, the Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in AOCIL. The Company had no derivatives designated as cash flow hedges for the years ended December 31, 2013 , and 2012 . 
+As a result of discontinuing hedge accounting on January 1, 2011, fair values at December 31, 2010, were frozen in AOCIL as of the de-designation date and were reclassified into earnings as the original derivative transactions settled. As of December 31, 2013 , all commodity derivative contracts that had been previously designated as cash flow hedges have settled and have been reclassified into earnings from AOCIL. Please refer to Note 11 - Fair Value Measurements for more information regarding the Company’s derivative instruments, including its valuation techniques. 
+134 
+The following table summarizes the components of derivative (gain) loss presented in the accompanying statements of operations: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Derivative cash settlement (gain) loss: 
+Oil contracts 
+$ 
+15,161 
+$ 
+11,893 
+$ 
+22,633 
+Gas contracts 
+(30,338 
+) 
+(47,270 
+) 
+(10,711 
+) 
+NGL contracts 
+(6,885 
+) 
+(8,887 
+) 
+13,749 
+Total derivative cash settlement (gain) loss (1) 
+(22,062 
+) 
+(44,264 
+) 
+25,671 
+Derivative (gain) loss: 
+Oil contracts 
+(496 
+) 
+(31,981 
+) 
+(3,391 
+) 
+Gas contracts 
+16,285 
+31,777 
+(64,310 
+) 
+NGL contracts 
+3,193 
+(11,162 
+) 
+4,944 
+Total derivative gain (2) 
+$ 
+(3,080 
+) 
+$ 
+(55,630 
+) 
+$ 
+(37,086 
+) 
+(1) 
+Total derivative cash settlement gain (loss) is reported in the derivative cash settlement gain (loss) line item on the consolidated statements of cash flows within net cash provided by operating activities. 
+(2) 
+Total derivative gain is reported in the derivative gain line item on the consolidated statements of cash flows within net cash provided by operating activities. 
+The following table details the effect of derivative instruments on AOCIL and the accompanying statements of operations (net of income tax): 
+Location on 
+Accompanying 
+Statements of 
+Operations 
+For the Years Ended December 31, 
+Derivatives 
+2013 
+2012 
+2011 
+(in thousands) 
+Amount reclassified from AOCIL 
+Commodity Contracts 
+Realized hedge gain (loss) 
+$ 
+1,115 
+$ 
+(2,264 
+) 
+$ 
+12,997 
+The realized net hedge loss for the year ended December 31, 2013 , net hedge gain for the year ended December 31, 2012 , and net hedge loss for the year ended December 31, 2011 , shown net of income tax in the table above, are comprised of realized cash settlements on commodity derivative contracts that were previously designated as cash flow hedges. Realized hedge gains or losses from the settlement of commodity derivatives previously designated as cash flow hedges are reported in the total operating revenues and other income section of the accompanying statements of operations. The Company realized a pre-tax net loss of $1.8 million , a pre-tax net gain of $3.9 million , and a pre-tax net loss of $20.7 million from its commodity derivative contracts for the years ended December 31, 2013 , 2012 , and 2011 , respectively. 
+As noted above, effective January 1, 2011, the Company elected to de-designate all of its commodity derivative contracts that had been previously designated as cash flow hedges. No new gains or losses are deferred in AOCIL at December 31, 2013 , and 2012 , respectively. 
+135 
+Credit Related Contingent Features 
+As of December 31, 2013 , and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility syndicate. The Company’s obligations under its credit facility and derivative contracts are secured by liens on substantially all of the Company’s proved oil and gas properties. 
+Convertible Note Derivative Instrument 
+The contingent interest provision of the 3.50% Senior Convertible Notes was an embedded derivative instrument. The 3.50% Senior Convertible Notes were settled during the second quarter of 2012. Please refer to Note 5 - Long-term Debt for additional discussion. 
+Note 11 – Fair Value Measurements 
+The Company follows fair value measurement authoritative accounting guidance for all assets and liabilities measured at fair value. That authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs: 
+• 
+Level 1 – quoted prices in active markets for identical assets or liabilities 
+• 
+Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable 
+• 
+Level 3 – significant inputs to the valuation model are unobservable 
+The following table is a listing of the Company’s assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of December 31, 2013 : 
+Level 1 
+Level 2 
+Level 3 
+(in thousands) 
+Assets: 
+Derivatives (1) 
+$ 
+— 
+$ 
+52,510 
+$ 
+— 
+Proved oil and gas properties (2) 
+$ 
+— 
+$ 
+— 
+$ 
+62,178 
+Unproved oil and gas properties (2) 
+$ 
+— 
+$ 
+— 
+$ 
+3,280 
+Oil and gas properties held for sale (2) 
+$ 
+— 
+$ 
+— 
+$ 
+650 
+Liabilities: 
+Derivatives (1) 
+$ 
+— 
+$ 
+31,020 
+$ 
+— 
+Net Profits Plan (1) 
+$ 
+— 
+$ 
+— 
+$ 
+56,985 
+(1) This represents a financial asset or liability that is measured at fair value on a recurring basis. 
+(2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. 
+136 
+The following table is a listing of the Company’s assets and liabilities that are measured at fair value and where they were classified within the hierarchy as of December 31, 2012 : 
+Level 1 
+Level 2 
+Level 3 
+(in thousands) 
+Assets: 
+Derivatives (1) 
+$ 
+— 
+$ 
+54,339 
+$ 
+— 
+Proved oil and gas properties (2) 
+$ 
+— 
+$ 
+— 
+$ 
+209,959 
+Unproved oil and gas properties (2) 
+$ 
+— 
+$ 
+— 
+$ 
+42,765 
+Liabilities: 
+Derivatives (1) 
+$ 
+— 
+$ 
+15,644 
+$ 
+— 
+Net Profits Plan (1) 
+$ 
+— 
+$ 
+— 
+$ 
+78,827 
+(1) This represents a financial asset or liability that is measured at fair value on a recurring basis. 
+(2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. 
+Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. 
+Derivatives 
+The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. 
+Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. Currently, one counterparty posts collateral when requested by the Company. In some instances the Company will attempt to novate the trade to a more stable counterparty. 
+Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk and takes into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date. All of the Company’s derivative counterparties are members of the Company’s credit facility bank syndicate. 
+137 
+The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with accounting authoritative guidance and with other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date. 
+Refer to Note 10 - Derivative Financial Instruments for more information regarding the Company’s derivative instruments. 
+Net Profits Plan 
+The Net Profits Plan is a standalone liability for which there is no available market price, principal market, or market participants. The inputs available for this instrument are unobservable and are therefore classified as Level 3 inputs. The Company employs the income valuation technique, which converts expected future cash flow amounts to a single present value amount. This technique uses the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value. There is a direct correlation between realized oil, gas, and NGL commodity prices driving net cash flows and the Net Profits Plan liability. Generally, higher commodity prices result in a larger Net Profits Plan liability and lower commodity prices result in a smaller Net Profits Plan liability. 
+The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool. The calculation of this liability is a significant management estimate. A discount rate of 12 percent is used to calculate this liability, which is intended to represent the Company's best estimate of the present value of expected future payments under the Net Profits Plan. 
+The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions, discount rates, and overall market conditions. The Company regularly assesses the current market environment. The Net Profits Plan liability is determined using price assumptions of five one -year strip prices with the fifth year’s pricing then carried out indefinitely. The average price is adjusted for realized price differentials and to include the effects of the forecasted production covered by derivatives contracts in the relevant periods. The non-cash expense associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the oil, gas, and NGL commodity markets. 
+If the commodity prices used in the calculation changed by five percent , the liability recorded at December 31, 2013 , would differ by approximately $5 million . A one percent increase in the discount rate would decrease the liability by approximately $2 million , whereas a one percent decrease in the discount rate would increase the liability by approximately $2 million . Actual cash payments to be made to participants in future periods are dependent on realized actual production, realized commodity prices, and actual costs associated with the properties in each individual pool of the Net Profits Plan. Consequently, actual cash payments are inherently different from the amounts estimated. 
+No published market quotes exist on which to base the Company’s estimate of fair value of its Net Profits Plan liability. As such, the recorded fair value is based entirely on management estimates that are described within this footnote. While some inputs to the Company’s calculation of fair value of the Net Profits Plan’s future payments are from published sources, others, such as the discount rate and the expected future cash flows, are derived from the Company’s own calculations and estimates. 
+138 
+The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Beginning balance 
+$ 
+78,827 
+$ 
+107,731 
+$ 
+135,850 
+Net increase (decrease) in liability (1) 
+3,527 
+(9,251 
+) 
+2,269 
+Net settlements (1) (2) (3) 
+(25,369 
+) 
+(19,653 
+) 
+(30,388 
+) 
+Transfers in (out) of Level 3 
+— 
+— 
+— 
+Ending balance 
+$ 
+56,985 
+$ 
+78,827 
+$ 
+107,731 
+(1) 
+Net changes in the Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations. 
+(2) 
+Settlements represent cash payments made or accrued under the Net Profits Plan. The amounts in the table include cash payments made or accrued under the Net Profits Plan of $10.3 million , $2.3 million , and $6.3 million relating to divestiture proceeds for the years ended December 31, 2013 , 2012 , and 2011 , respectively. 
+(3) 
+During 2011, the Company elected to cash out several Net Profits Plan pools with a $2.6 million direct payment. As a result, the Company reduced its Net Profits Plan liability by that amount. There was no impact on the accompanying statements of operations for the period ended December 31, 2011, related to these settlements. 
+Long-term Debt 
+The following table reflects the fair value of the Senior Notes measured at fair value using Level 1 inputs based on quoted secondary market trading prices. The Senior Notes were not presented at fair value on the accompanying balance sheets as of December 31, 2013 or 2012 , as they are recorded at historical value. 
+As of December 31, 
+2013 
+2012 
+(in thousands) 
+2019 Notes 
+$ 
+374,290 
+$ 
+371,875 
+2021 Notes 
+$ 
+373,625 
+$ 
+371,070 
+2023 Notes 
+$ 
+422,000 
+$ 
+424,200 
+2024 Notes (1) 
+$ 
+475,315 
+$ 
+— 
+(1) The 2024 Notes were issued on May 20, 2013. 
+The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates. 
+Proved and Unproved Oil and Gas Properties 
+Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the Company’s management. The calculation of the discount rate is based on the best information available and was estimated to be 12 percent as of December 31, 2013 , and 2012 . The Company believes that the discount rate is representative of current market conditions and takes into account estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil 
+139 
+and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. 
+As a result of asset write-downs, the proved oil and gas properties measured at fair value within the accompanying balance sheets totaled $62.2 million and $210.0 million as of December 31, 2013 , and 2012 , respectively. 
+Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, and estimated reserve values. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company utilizes a market approach, which estimates acreage value based on the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. 
+As a result of asset write-downs, unproved oil and gas properties measured at fair value within the accompanying balance sheets totaled $3.3 million as of December 31, 2013 and $42.8 million at December 31, 2012 . 
+Acquisitions of proved and unproved properties are measured at fair value as of the acquisition date using a discounted cash flow model similar to the Company’s approach in measuring the fair value of proved and unproved properties, as discussed in the paragraphs above. Due to the unobservable characteristics of the inputs, the fair value of acquired properties are considered Level 3 within the fair value hierarchy. 
+Materials Inventory 
+Materials inventory is valued at the lower of cost or market. The Company uses Level 2 inputs to measure the fair value of materials inventory, which is primarily comprised of tubular goods. The Company uses third party market quotes and compares the quotes to the book value of the materials inventory. If the book value exceeds the quoted market price, the Company reduces the book value to the market price. The considered factors result in an estimated exit-price. Management believes this approach provides a reasonable and consistent methodology for valuing materials inventory. There were no materials inventory measured at fair value within the accompanying balance sheets at December 31, 2013 and 2012 . 
+Asset Retirement Obligations 
+The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value within the accompanying balance sheets at December 31, 2013 and 2012 . 
+140 
+Note 12 - Acquisition and Development Agreement 
+In June 2011, the Company entered into an Acquisition and Development Agreement with Mitsui. Pursuant to the Acquisition and Development Agreement, the Company agreed to transfer to Mitsui a 12.5 percent working interest in certain non-operated oil and gas assets representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick, and Webb Counties, Texas. As consideration for the oil and gas interests transferred, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs attributable to the Company’s remaining interest in these assets until Mitsui has expended an aggregate $680.0 million on behalf of the Company. Based on the Company’s forecast of the operator’s drilling plans, the carry will be fully utilized in early 2014. The Acquisition and Development Agreement also provided for reimbursement of capital expenditures and other costs, net of revenues, paid by the Company that were attributable to the transferred interest during the period between the effective date and the closing date, which the parties agreed would be applied over the carry period to cover the Company’s remaining 10 percent of drilling and completion costs for the affected acreage. 
+As of December 31, 2013 , the Company held $95.0 million in cash that is contractually restricted for use in the development of assets covered by the Acquisition and Development Agreement. This cash relates to the reimbursement of net costs for the period between the effective date and closing date, as discussed above, as well as an estimate of 90 percent of two months of activity of the Company’s proportionate share of estimated drilling and completion costs. This restricted cash is classified as a noncurrent asset in the accompanying balance sheets. The Company has recorded a corresponding liability equal to the restricted cash balance. The portion of the liability related to development operations expected to occur within the next year is recorded in accounts payable and accrued expenses within the accompanying balance sheets. The portion of the liability related to development operations expected to occur more than one year in the future is recorded in other noncurrent liabilities within the accompanying balance sheets. As the remaining development operations are expected to be completed within the next year, the entire amount is recorded in accounts payable and accrued expenses within the accompanying balance sheets as of December 31, 2013 . There was no net impact on the accompanying statements of cash flows as restricted cash was offset against the corresponding liability in investing activities. There is no direct impact to the accompanying statements of operations as a result of the Acquisition and Development Agreement, with the exception of legal and commission costs associated with the execution of the arrangement which were expensed in 2011. Of the original $680.0 million carry amount, $573.8 million had been spent as of December 31, 2013 . 
+141 
+Note 13 - Suspended Well Costs 
+The following table reflects the net changes in capitalized exploratory well costs during 2013 , 2012 , and 2011 . The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Beginning balance on January 1, 
+$ 
+9,100 
+$ 
+18,600 
+$ 
+35,862 
+Additions to capitalized exploratory well costs pending the determination of proved reserves 
+34,527 
+9,100 
+15,618 
+Reclassifications to wells, facilities, and equipment based on the determination of proved reserves 
+(9,100 
+) 
+(5,865 
+) 
+(32,880 
+) 
+Capitalized exploratory well costs charged to expense 
+— 
+(12,735 
+) 
+— 
+Ending balance at December 31, 
+$ 
+34,527 
+$ 
+9,100 
+$ 
+18,600 
+The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: 
+As of December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Exploratory well costs capitalized for one year or less 
+$ 
+34,527 
+$ 
+9,100 
+$ 
+15,618 
+Exploratory well costs capitalized for more than one year 
+— 
+— 
+2,982 
+Ending balance at December 31, 
+$ 
+34,527 
+$ 
+9,100 
+$ 
+18,600 
+Number of projects with exploratory well costs that have been capitalized more than a year 
+— 
+— 
+2 
+I n the third quarter of 2012, the Company expensed $3.6 million of costs related to two exploratory wells that had been disclosed at December 31, 2011 , as suspended well costs being capitalized for more than one year. 
+142 
+Supplemental Oil and Gas Information (unaudited) 
+Costs Incurred in Oil and Gas Producing Activities 
+Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Development costs (1) 
+$ 
+1,350,116 
+$ 
+1,346,216 
+$ 
+1,320,627 
+Exploration costs 
+168,612 
+220,921 
+177,465 
+Acquisitions 
+Proved properties 
+29,859 
+5,773 
+— 
+Unproved properties (2) 
+172,546 
+114,971 
+55,237 
+Total, including asset retirement obligation (3)(4) 
+$ 
+1,721,133 
+$ 
+1,687,881 
+$ 
+1,553,329 
+(1) 
+Includes facility costs of $49.5 million , $62.2 million , and $112.4 million for the years ended December 31, 2013 , 2012 , and 2011 , respectively. 
+(2) 
+Includes $58.5 million and $3.4 million of unproved properties acquired as part of a proved property acquisition for the years ended December 31, 2013 and 2012 , respectively. The remaining balance relates to leasing activity. 
+(3) 
+Includes capitalized interest of $11.0 million , $12.1 million , and $10.8 million for the years ended December 31, 2013 , 2012 , and 2011 , respectively. 
+(4) 
+Includes amounts relating to estimated asset retirement obligations of $26.8 million , $30.6 million , and $19.3 million for the years ended December 31, 2013 , 2012 , and 2011 , respectively. 
+Oil and Gas Reserve Quantities 
+The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and gas producing activities and SEC rules for oil and gas reporting reserve estimation and disclosure. 
+Proved reserves are the estimated quantities of oil, gas, and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. All of the Company’s estimated proved reserves are located in the United States. 
+143 
+The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period ended December 31, 2013 . The Company engaged Ryder Scott to audit internal engineering estimates for at least 80 percent of the PV-10 value of its estimated proved reserves in each year presented. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. 
+For the Years Ended December 31, 
+2013 (1) 
+2012 (2) 
+2011 (3) 
+Oil 
+Gas 
+NGLs 
+Oil 
+Gas 
+NGLs 
+Oil 
+Gas 
+NGLs 
+(MMBbl) 
+(Bcf) 
+(MMBbl) 
+(MMBbl) 
+(Bcf) 
+(MMBbl) 
+(MMBbl) 
+(Bcf) 
+(MMBbl) 
+Total proved reserves 
+Beginning of year 
+92.2 
+833.4 
+62.3 
+71.7 
+664.0 
+27.5 
+57.4 
+640.0 
+— 
+Revisions of previous estimate 
+(5.2 
+) 
+68.8 
+(1.3 
+) 
+(4.5 
+) 
+(123.3 
+) 
+(2.4 
+) 
+(0.9 
+) 
+(76.7 
+) 
+15.6 
+Discoveries and extensions 
+34.6 
+399.2 
+39.8 
+17.1 
+297.4 
+30.6 
+26.9 
+223.5 
+17.8 
+Infill reserves in an existing proved field 
+21.6 
+118.7 
+13.2 
+19.2 
+125.1 
+12.7 
+2.8 
+14.8 
+0.5 
+Sales of 
+reserves (4) 
+(3.4 
+) 
+(85.1 
+) 
+(0.6 
+) 
+(1.0 
+) 
+(11.0 
+) 
+— 
+(6.4 
+) 
+(37.3 
+) 
+(2.9 
+) 
+Purchases of minerals in place 
+0.7 
+3.6 
+— 
+0.1 
+1.2 
+— 
+— 
+— 
+— 
+Production 
+(13.9 
+) 
+(149.3 
+) 
+(9.5 
+) 
+(10.4 
+) 
+(120.0 
+) 
+(6.1 
+) 
+(8.1 
+) 
+(100.3 
+) 
+(3.5 
+) 
+End of year (5) 
+126.6 
+1,189.3 
+103.9 
+92.2 
+833.4 
+62.3 
+71.7 
+664.0 
+27.5 
+Proved developed reserves 
+Beginning of year 
+58.8 
+483.2 
+27.2 
+50.3 
+451.2 
+15.2 
+46.0 
+411.0 
+— 
+End of year 
+70.2 
+569.2 
+43.8 
+58.8 
+483.2 
+27.2 
+50.3 
+451.2 
+15.2 
+Proved undeveloped reserves 
+Beginning of year 
+33.5 
+350.2 
+35.1 
+21.4 
+212.8 
+12.3 
+11.4 
+229.0 
+— 
+End of year 
+56.3 
+620.1 
+60.2 
+33.5 
+350.2 
+35.1 
+21.4 
+212.8 
+12.3 
+Note: Amounts may not recalculate due to rounding. 
+(1) 
+For the year ended December 31, 2013, of the 5.0 MMBOE upward revision of a previous estimate, 0.6 MMBOE and 4.4 MMBOE relate to price and performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2013, were $96.94 per Bbl, $3.67 per MMBtu, and $40.29 per Bbl for oil, natural gas, and NGLs respectively. These prices were two percent higher, 33 percent higher, and 12 percent lower, respectively, than the prices used in 2012. The Company added 195.5 MMBOE from its drilling program, the majority of which related to activity in the Eagle Ford shale in South Texas and Bakken/Three Forks plays in North Dakota. These additions are included in discoveries and extensions and infill reserves. 
+(2) 
+For the year ended December 31, 2012, of the 27.4 MMBOE downward revision of a previous estimate, 12.1 MMBOE and 15.3 MMBOE relate to price and performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2012, were $94.71 per Bbl, $2.76 per MMBtu, and $45.65 per Bbl for oil, natural gas, and NGLs respectively. These prices were two percent lower, 33 percent lower, and 23 percent lower, respectively, than the prices used in 2011. The Company added 150.0 MMBOE from its drilling program, the majority of which related to activity in the Eagle Ford shale in South Texas. These additions are included in discoveries and extensions and infill reserves. 
+(3) 
+For the year ended December 31, 2011, of the 1.9 MMBOE upward revision of a previous estimate, (4.2) MMBOE and 6.1 MMBOE relate to price and performance revisions, respectively. The prices used in the calculation of proved 
+144 
+reserve estimates as of December 31, 2011, were $96.19 per Bbl and $4.12 per MMBtu, for oil and natural gas respectively. These prices were 21 percent higher and six percent lower, respectively, than the prices used in 2010. The per Bbl price used to estimate proved NGL reserves as of December 31, 2011 was $59.37 . Performance revisions in 2011 resulted in a net 6.1 MMBOE increase in the estimate of proved reserves. This increase includes the impact of the Company's conversion to three stream production, which is partially offset by downward engineering revisions due primarily to the failure of Woodford shale wells in the Company's Mid-Continent region to satisfy internal economic hurdles. The Company added 87.7 MMBOE from its drilling program, the majority of which related to activity in the Eagle Ford shale in South Texas. These additions are included in discoveries and extensions and infill reserves. 
+(4) 
+The Company divested of certain non-core assets during 2013 , 2012 , and 2011 . Please refer to Note 3 - Divestitures and Assets Held for Sale for additional information. 
+(5) 
+For the years ended December 31, 2013 , 2012 , and 2011 , amounts included approximately 12 , 50 , and 29 MBOE respectively, representing the Company’s net underproduced gas balancing position. 
+Standardized Measure of Discounted Future Net Cash Flows 
+The Company computes a standardized measure of future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. Each property the Company operates is also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using the current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10 percent annual discount factor. 
+Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using year-end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by the central administrative office attributable to operating activities. 
+The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the standardized measure: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+Oil (per Bbl) 
+$ 
+90.19 
+$ 
+86.80 
+$ 
+88.00 
+Gas (per Mcf) 
+$ 
+3.99 
+$ 
+3.08 
+$ 
+4.72 
+NGLs (per Bbl) 
+$ 
+35.92 
+$ 
+41.00 
+$ 
+51.95 
+145 
+The following summary sets forth the Company’s future net cash flows relating to proved oil, gas, and NGL reserves based on the standardized measure. 
+As of December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Future cash inflows 
+$ 
+19,895,360 
+$ 
+13,129,243 
+$ 
+10,871,281 
+Future production costs 
+(7,771,747 
+) 
+(5,013,720 
+) 
+(3,786,887 
+) 
+Future development costs 
+(2,891,325 
+) 
+(1,742,978 
+) 
+(1,036,352 
+) 
+Future income taxes 
+(2,722,230 
+) 
+(1,609,397 
+) 
+(1,740,394 
+) 
+Future net cash flows 
+6,510,058 
+4,763,148 
+4,307,648 
+10 percent annual discount 
+(2,500,619 
+) 
+(1,742,134 
+) 
+(1,727,608 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+4,009,439 
+$ 
+3,021,014 
+$ 
+2,580,040 
+The principle sources of changes in the standardized measure of discounted future net cash flows are: 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+(in thousands) 
+Standardized measure, beginning of year 
+$ 
+3,021,014 
+$ 
+2,580,040 
+$ 
+1,666,367 
+Sales of oil, gas, and NGLs produced, net of production costs 
+(1,602,505 
+) 
+(1,081,997 
+) 
+(1,042,281 
+) 
+Net changes in prices and production costs 
+142,199 
+(550,293 
+) 
+454,646 
+Extensions, discoveries and other including infill reserves in an existing proved field, net of related costs 
+2,309,075 
+1,872,810 
+1,816,640 
+Sales of reserves in place 
+(259,031 
+) 
+(41,020 
+) 
+(369,820 
+) 
+Purchase of reserves in place 
+30,771 
+3,785 
+— 
+Development costs incurred during the year 
+581,107 
+163,937 
+49,246 
+Changes in estimated future development costs 
+68,613 
+47,980 
+(31,410 
+) 
+Revisions of previous quantity estimates 
+82,226 
+(452,454 
+) 
+32,992 
+Accretion of discount 
+384,914 
+346,118 
+234,433 
+Net change in income taxes 
+(690,953 
+) 
+53,005 
+(203,169 
+) 
+Changes in timing and other 
+(57,991 
+) 
+79,103 
+(27,604 
+) 
+Standardized measure, end of year 
+$ 
+4,009,439 
+$ 
+3,021,014 
+$ 
+2,580,040 
+146 
+Quarterly Financial Information (unaudited) 
+The Company’s quarterly financial information for fiscal years 2013 and 2012 is as follows (in thousands, except per share amounts): 
+First 
+Second 
+Third 
+Fourth (2) 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+Year Ended December 31, 2013 
+Total operating revenues 
+$ 
+484,180 
+$ 
+559,360 
+$ 
+613,107 
+$ 
+636,727 
+Total operating expenses 
+437,982 
+415,076 
+475,623 
+596,438 
+Income from operations 
+$ 
+46,198 
+$ 
+144,284 
+$ 
+137,484 
+$ 
+40,289 
+Income before income taxes 
+$ 
+27,109 
+$ 
+122,727 
+$ 
+113,024 
+$ 
+15,751 
+Net income 
+$ 
+16,727 
+$ 
+76,522 
+$ 
+70,690 
+$ 
+6,996 
+Basic net income per common share (1) 
+$ 
+0.25 
+$ 
+1.15 
+$ 
+1.06 
+$ 
+0.10 
+Diluted net income per common share (1) 
+$ 
+0.25 
+$ 
+1.13 
+$ 
+1.04 
+$ 
+0.10 
+Dividends declared per common share 
+$ 
+0.05 
+$ 
+— 
+$ 
+0.05 
+$ 
+— 
+Year Ended December 31, 2012 
+Total operating revenues 
+$ 
+377,423 
+$ 
+304,420 
+$ 
+378,951 
+$ 
+444,308 
+Total operating expenses 
+321,198 
+252,029 
+421,787 
+530,105 
+Income (loss) from operations 
+$ 
+56,225 
+$ 
+52,391 
+$ 
+(42,836 
+) 
+$ 
+(85,797 
+) 
+Income (loss) before income taxes 
+$ 
+42,017 
+$ 
+39,684 
+$ 
+(61,072 
+) 
+$ 
+(104,146 
+) 
+Net income (loss) 
+$ 
+26,336 
+$ 
+24,889 
+$ 
+(38,336 
+) 
+$ 
+(67,138 
+) 
+Basic net income (loss) per common share (1) 
+$ 
+0.41 
+$ 
+0.39 
+$ 
+(0.58 
+) 
+$ 
+(1.02 
+) 
+Diluted net income (loss) per common share (1) 
+$ 
+0.39 
+$ 
+0.37 
+$ 
+(0.58 
+) 
+$ 
+(1.02 
+) 
+Dividends declared per common share 
+$ 
+0.05 
+$ 
+— 
+$ 
+0.05 
+$ 
+— 
+(1) Amounts may not sum due to rounding or the impact of quarterly net losses when computing year-to-date dilutive shares. 
+(2) The fourth quarter of 2013 and 2012 included $110.9 million and $170.4 million , respectively, of impairment of proved properties expense. Please refer to the caption Impairment of Proved and Unproved Properties included in Note 1 - Summary of Significant Accounting Policies for additional discussion. 
+147 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+On September 10, 2012, SM Energy's Audit Committee of the Board of Directors approved the engagement of Ernst & Young LLP as the Company's independent registered accounting firm for the year ending December 31, 2013, replacing Deloitte & Touche LLP (“D&T”). 
+The report of D&T on the Company's consolidated financial statements for the years ended December 31, 2012, and 2011, did not contain an adverse or disclaimer opinions, and was not qualified or modified. 
+During the years ended December 31, 2012, and 2011, there were no disagreements with D&T on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, which disagreements, if not resolved to the satisfaction of D&T, would have caused D&T to make reference to the subject matter of the disagreement in its report on the consolidated financial statements for such year. 
+ITEM 9A. CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Controls and Procedures 
+We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. 
+Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant. 
+An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls 
+are effective at a reasonable assurance level. 
+Changes in Internal Control Over Financial Reporting 
+There have been no changes during the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+148 
+Management’s Report on Internal Control over Financial Reporting 
+Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that: 
+(i) 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+(ii) 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+(iii) 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements. 
+Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. 
+Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013 . In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (1992 framework) . 
+Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2013 . 
+The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal controls over financial reporting. That report immediately follows this report. 
+149 
+Report of Independent Registered Public Accounting Firm 
+The Board of Directors and Stockholders of SM Energy Company and subsidiaries 
+We have audited SM Energy Company and subsidiaries’ internal control over financial reporting as of December 31, 2013 , based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). SM Energy Company and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, SM Energy Company and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013 , based on the COSO criteria. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of SM Energy Company and subsidiaries as of December 31, 2013 , and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for the year then ended and our report dated February 19, 2014 expressed an unqualified opinion thereon . 
+/s/ Ernst & Young LLP 
+Denver, Colorado 
+February 19, 2014 
+150 
+ITEM 9B. OTHER INFORMATION 
+None. 
+PART III 
+ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE 
+The information required by this Item concerning SM Energy’s Directors, Executive Officers, and corporate governance is incorporated by reference to the information provided under the captions Proposal 1 - Election of Directors, Executive Officers, and Corporate Governance in SM Energy’s definitive proxy statement for the 2014 annual meeting of stockholders to be filed within 120 days from December 31, 2013 . 
+The information required by this Item concerning compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated by reference to the information provided under the caption Section 16(a) Beneficial Ownership Reporting Compliance in SM Energy’s definitive proxy statement for the 2014 annual meeting of stockholders to be filed within 120 days from December 31, 2013 . 
+ITEM 11. EXECUTIVE COMPENSATION 
+The information required by this Item is incorporated by reference to the information provided under the captions, Executive Compensation and Director Compensation in SM Energy’s definitive proxy statement for the 2014 annual meeting of stockholders to be filed within 120 days from December 31, 2013 . 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The information required by this Item concerning security ownership of certain beneficial owners and management is incorporated by reference to the information provided under the caption Security Ownership of Certain Beneficial Owners and Management in SM Energy’s definitive proxy statement for the 2014 annual meeting of stockholders to be filed within 120 days from December 31, 2013 . 
+151 
+Securities Authorized for Issuance Under Equity Compensation Plans. SM Energy has the Equity Plan under which options and shares of SM Energy common stock are authorized for grant or issuance as compensation to eligible employees, consultants, and members of the Board of Directors. Our stockholders have approved this plan. See Note 7 – Compensation Plans included in Part II, Item 8 of this report for further information about the material terms of our equity compensation plans. The following table is a summary of the shares of common stock authorized for issuance under the equity compensation plans as of December 31, 2013 : 
+(a) 
+(b) 
+(c) 
+Plan category 
+Number of securities to be issued upon exercise of outstanding options, warrants, and rights 
+Weighted-average exercise price of outstanding options, warrants, and rights 
+Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) 
+Equity compensation plans approved by security holders: 
+Equity Incentive Compensation Plan 
+Stock options and incentive stock options (1) 
+39,088 
+$ 
+20.87 
+Restricted stock (1)(3) 
+580,431 
+N/A 
+Performance share units (1)(3)(4) 
+807,406 
+N/A 
+Total for Equity Incentive Compensation Plan 
+1,426,925 
+$ 
+20.87 
+3,813,900 
+Employee Stock Purchase Plan (2) 
+- 
+- 
+1,230,057 
+Equity compensation plans not approved by security holders 
+- 
+- 
+- 
+Total for all plans 
+1,426,925 
+$ 
+20.87 
+5,043,957 
+(1) 
+In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and members of the Board of Directors of SM Energy or any affiliate of SM Energy. The Equity Plan serves as the successor to the St. Mary Land & Exploration Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock Option Plan, the SM Energy Company Restricted Stock Plan, and the SM Energy Company Non-Employee Director Stock Compensation Plan (collectively referred to as the “Predecessor Plans”). All grants of equity are now made under the Equity Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under a Predecessor Plan immediately prior to the effective date of the Equity Plan continues to be governed solely by the terms and conditions of the instruments evidencing such grants or issuances. Our Board of Directors approved amendments to the Equity Plan in 2009, 2010, and 2013 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The awards granted in 2013 , 2012 , and 2011 under the Equity Plan were 632,939 , 724,671 , and 386,802 , respectively. 
+(2) 
+Under the SM Energy Company ESPP, eligible employees may purchase shares of our common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the six-month offering period, and shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. Shares issued under the ESPP totaled 77,427 , 66,485 , and 41,358 in 2013 , 2012 , and 2011 , respectively. 
+(3) 
+RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per share fair value, which is presented in order to provide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per share fair value for the outstanding RSUs and PSUs was $57.05 and $67.74, respectively. Please refer to Note 7 - Compensation Plans for additional discussion. 
+(4) 
+The number of awards vested assumes a one multiplier. The final number of shares issued upon settlement may vary depending on the three -year multiplier determined at the end of the performance period under the Equity Plan, which ranges from zero to two . 
+152 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+The information required by this Item is incorporated by reference to the information provided under the caption Certain Relationships and Related Transactions, and Corporate Governance, in SM Energy’s definitive proxy statement for the 2014 annual meeting of stockholders to be filed within 120 days from December 31, 2013 . 
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+The information required by this Item is incorporated by reference to the information provided under the caption Independent Registered Public Accounting Firm and Audit Committee Preapproval Policy and Procedures in SM Energy’s definitive proxy statement for the 2014 annual meeting of stockholders to be filed within 120 days from December 31, 2013 . 
+153 
+PART IV 
+ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
+(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules: 
+Reports of Independent Registered Public Accounting Firms 
+88 
+Consolidated Balance Sheets 
+90 
+Consolidated Statements of Operations 
+91 
+Consolidated Statements of Comprehensive Income (Loss) 
+92 
+Consolidated Statements of Stockholders’ Equity 
+93 
+Consolidated Statements of Cash Flows 
+94 
+Notes to Consolidated Financial Statements 
+96 
+All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto. 
+(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K: 
+Exhibit 
+Number 
+Description 
+2.1 
+Purchase and Sale Agreement dated June 9, 2011, among SM Energy Company, Statoil Texas Onshore Properties LLC, and Talisman Energy USA Inc. (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 and incorporated herein by reference) 
+2.2 
+Acquisition and Development Agreement dated June 29, 2011 between SM Energy Company and Mitsui E&P Texas LP (filed as Exhibit 2.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 and incorporated herein by reference) 
+2.3 
+First Amendment to Acquisition and Development Agreement dated October 13, 2011 between SM Energy Company and Mitsui E&P Texas (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 and incorporated herein by reference) 
+2.4*†† 
+Purchase and Sale Agreement dated November 4, 2013, among SM Energy Company, EnerVest Energy Institutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., and EnerVest Energy Institutional Fund XIII-WIC, L.P. 
+3.1 
+Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+3.2 
+Amended and Restated By-Laws of SM Energy Company amended effective as of January 1, 2013 (filed as Exhibit 3.1 to the registrant’s Current Report on Form 8-K filed on January 7, 2013, and incorporated herein by reference) 
+4.1 
+Indenture related to the 3.50% Senior Convertible Notes due 2027, dated as of April 4, 2007, between St. Mary Land & Exploration Company and Wells Fargo Bank, National Association, as trustee (including the form of 3.50% Senior Convertible Note due 2027) (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on April 4, 2007 and incorporated herein by reference) 
+4.2 
+Indenture related to the 6.625% Senior Notes due 2019, dated as of February 7, 2011, by and between SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on February 10, 2011, and incorporated herein by reference) 
+154 
+4.3 
+Indenture related to the 6.50% Senior Notes due 2021, dated as of November 8, 2011, by and among SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on November 10, 2011, and incorporated herein by reference) 
+4.4 
+Indenture related to the 6.50% Senior Notes due 2023, dated June 29, 2012, between SM Energy Company, as Issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on July 3, 2012, and incorporated herein by reference) 
+4.5 
+Indenture related to the 5.0% Senior Notes due 2024, dated May 20, 2013, by and between SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant's Current Report on Form 8-K filed on May 20, 2013, and incorporated herein by reference) 
+4.6 
+Registration Rights Agreement, dated May 20, 2013, by and among SM Energy Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities, LLC, and J.P. Morgan Securities LLC, as representatives of several purchasers (filed as Exhibit 4.2 to the registrant's Current Report on Form 8-K filed on May 20, 2013, and incorporated herein by reference) 
+10.1† 
+Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference) 
+10.2† 
+Incentive Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.2 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference) 
+10.3† 
+Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001 and incorporated herein by reference) 
+10.4† 
+Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.9 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein by reference) 
+10.5† 
+Employment Agreement of A.J. Best dated May 1, 2006 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 4, 2006 and incorporated herein by reference) 
+10.6 
+Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement for the benefit of Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference) 
+10.7 
+Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference) 
+10.8† 
+Equity Incentive Compensation Plan as Amended and Restated as of March 26, 2009 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 27, 2009, and incorporated herein by reference) 
+10.9† 
+Equity Incentive Compensation Plan As Amended and Restated as of April 1, 2010 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on June 2, 2010, and incorporated herein by reference) 
+10.10 s 
+SM Energy Company Equity Incentive Compensation Plan, As Amended as of July 30, 2010 (filed as Exhibit 10.7 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.11† 
+Third Amendment to Employee Stock Purchase Plan dated September 23, 2009 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, and incorporated herein by reference) 
+10.12† 
+Fourth Amendment to Employee Stock Purchase Plan dated December 29, 2009 (filed as Exhibit 10.46 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein by reference) 
+155 
+10.13 s 
+Employee Stock Purchase Plan, As Amended and Restated as of July 30, 2010 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.14† 
+Form of Performance Share and Restricted Stock Unit Award Agreement as of July 1, 2010 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.15† 
+Form of Performance Share and Restricted Stock Unit Award Notice as of July 1, 2010 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.16† 
+Form of Non-Employee Director Restricted Stock Award Agreement as of May 27, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference) 
+10.17*** 
+Gas Services Agreement effective as of July 1, 2010 between SM Energy Company and Eagle Ford Gathering LLC (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.18 s 
+Cash Bonus Plan, As Amended on July 30, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.19 s 
+Net Profits Interest Bonus Plan, As Amended by the Board of Directors on July 30, 2010 (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.20 s 
+SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan, As Amended as of July 30, 2010 (filed as Exhibit 10.8 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference) 
+10.21† 
+Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on December 29, 2010, and incorporated herein by reference) 
+10.22† 
+Amendment to A.J. Best Employment Agreement dated December 31, 2010 (filed as Exhibit 10.28 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference) 
+10.23 
+Pension Plan for Employees of SM Energy Company as Amended and Restated as of January 1, 2010 (filed as Exhibit 10.30 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference) 
+10.24+ 
+SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan as Amended as of November 9, 2010 (filed as Exhibit 10.31 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference) 
+10.25 
+Fourth Amended and Restated Credit Agreement dated May 27, 2011 among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.26 
+Gas Gathering Agreement dated May 31, 2011 between Regency Field Services LLC and SM Energy Company (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.27 
+Gathering and Natural Gas Services Agreement effective as of April 1, 2011 between SM Energy Company and ETC Texas Pipeline, Ltd. (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.28 
+Gas Processing Agreement effective as of April 1, 2011 between ETC Texas Pipeline, Ltd. and SM Energy Company (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.29† 
+Employee Stock Purchase Plan, As Amended and Restated as of June 10, 2011 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+156 
+10.30† 
+Form of Performance Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.31† 
+Form of Restricted Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.7 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) 
+10.32† 
+Form of Performance Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference) 
+10.33† 
+Form of Restricted Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference) 
+10.34 
+Amendment No. 1 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2011 (filed as Exhibit 10.41 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and incorporated herein by reference) 
+10.35 
+Amendment No. 2 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2012 (filed as Exhibit 10.42 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and incorporated herein by reference) 
+10.36† 
+Equity Incentive Compensation Plan, As Amended as of May 22, 2013 (filed as Annex A to the registrant’s Schedule 14A filed on April 11, 2013, and incorporated herein by reference) 
+10.37 
+Fifth Amended and Restated Credit Agreement dated April 12, 2013, among SM Energy Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report of Form 8-K filed on April 15, 2013, and incorporated herein by reference) 
+10.38† 
+Form of Performance Stock Unit Award Agreement as of July 31, 2013 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference) 
+10.39† 
+Form of Restricted Stock Unit Award Agreement as of July 31, 2013 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference) 
+10.40† 
+SM Energy Company Non-Qualified Deferred Compensation Plan as of March 10, 2014 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on January 24, 2014, and incorporated herein by reference) 
+10.41*† 
+Cash Bonus Plan, As Amended and Restated as of February 1, 2014 
+10.42*† 
+Summary of Compensation Arrangements for Non-Employee Directors 
+12.1* 
+Computation of Ratio of Earnings to Fixed Charges 
+21.1* 
+Subsidiaries of Registrant 
+23.1* 
+Consent of Ernst & Young LLP 
+23.2* 
+Consent of Deloitte & Touche LLP 
+23.3* 
+Consent of Ryder Scott Company L.P. 
+24.1* 
+Power of Attorney 
+31.1* 
+Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002 
+31.2* 
+Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002 
+32.1** 
+Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002 
+99.1* 
+Ryder Scott Audit Letter 
+101.INS* 
+XBRL Instance Document 
+101.SCH* 
+XBRL Schema Document 
+157 
+101.CAL* 
+XBRL Calculation Linkbase Document 
+101.LAB* 
+XBRL Label Linkbase Document 
+101.PRE* 
+XBRL Presentation Linkbase Document 
+101.DEF* 
+XBRL Taxonomy Extension Definition Linkbase Document 
+* Filed with this Form 10-K. 
+** Furnished with this Form 10-K. 
+*** 
+Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934. 
+†† 
+Confidential Treatment has been requested with respect to portions of the exhibit. Such portions have been redacted and filed separately with the SEC. 
+† 
+Exhibit constitutes a management contract or compensatory plan or agreement. 
+s 
+Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the recent change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the substantive terms and conditions in this document. 
++ 
+Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal Revenue Code. There were no material changes to the substantive terms and conditions in this document. 
+(c) Financial Statement Schedules. See Item 15(a) above. 
+158 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+SM ENERGY COMPANY 
+(Registrant) 
+Date: 
+February 19, 2014 
+By: 
+/s/ ANTHONY J. BEST 
+Anthony J. Best 
+Chief Executive Officer 
+(Principal Executive Officer) 
+GENERAL POWER OF ATTORNEY 
+KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints each of Anthony J. Best and A. Wade Pursell his or her true and lawful attorney-in-fact and agent with full power of substitution and resubstitution, and each with full power to act alone, for the undersigned and in his or her name, place and stead, in any and all capacities, to sign any amendments to this Annual Report on Form 10-K for the fiscal year ended December 31, 2013 , and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorney-in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof. 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signature 
+Title 
+Date 
+/s/ ANTHONY J. BEST 
+Chief Executive Officer and Director 
+February 19, 2014 
+Anthony J. Best 
+(Principal Executive Officer) 
+/s/ A. WADE PURSELL 
+Executive Vice President and Chief Financial Officer 
+February 19, 2014 
+A. Wade Pursell 
+(Principal Financial Officer) 
+/s/ MARK T. SOLOMON 
+Vice President - Controller and Assistant Secretary 
+February 19, 2014 
+Mark T. Solomon 
+(Principal Accounting Officer) 
+159 
+Signature 
+Title 
+Date 
+/s/ WILLIAM D. SULLIVAN 
+Chairman of the Board of Directors 
+February 19, 2014 
+William D. Sullivan 
+/s/ BARBARA M. BAUMANN 
+Director 
+February 19, 2014 
+Barbara M. Baumann 
+/s/ LARRY W. BICKLE 
+Director 
+February 19, 2014 
+Larry W. Bickle 
+/s/ STEPHEN R. BRAND 
+Director 
+February 19, 2014 
+Stephen R. Brand 
+/s/ WILLIAM J. GARDINER 
+Director 
+February 19, 2014 
+William J. Gardiner 
+/s/ LOREN M. LEIKER 
+Director 
+February 19, 2014 
+Loren M. Leiker 
+/s/ JULIO M. QUINTANA 
+Director 
+February 19, 2014 
+Julio M. Quintana 
+/s/ JOHN M. SEIDL 
+Director 
+February 19, 2014 
+John M. Seidl 
+160
\ No newline at end of file
diff --git a/raw/filings/0000893538/2013/0000893538-14-000010/filing_metadata.csv b/raw/filings/0000893538/2013/0000893538-14-000010/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..ca4cf27aea6d5a6e378647e9ef58b78480798bfe
--- /dev/null
+++ b/raw/filings/0000893538/2013/0000893538-14-000010/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000893538,SM,SM Energy Co,10-K,2014-02-19,2013-12-31,2014-02-19T14:11:52.000Z,0000893538-14-000010,sm-20131231x10k.htm,10-K,21352614,1,0,https://www.sec.gov/Archives/edgar/data/893538/000089353814000010/sm-20131231x10k.htm,https://www.sec.gov/Archives/edgar/data/893538/000089353814000010/,2013,2013,1
diff --git a/raw/filings/0000893538/2013/0000893538-14-000010/item1.txt b/raw/filings/0000893538/2013/0000893538-14-000010/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2013/0000893538-14-000010/item13.txt b/raw/filings/0000893538/2013/0000893538-14-000010/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..1c293b97e4f6db79c98bd2fdb3c465d53c7e2a55
--- /dev/null
+++ b/raw/filings/0000893538/2013/0000893538-14-000010/item13.txt
@@ -0,0 +1,3 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+The information required by this Item is incorporated by reference to the information provided under the caption Certain Relationships and Related Transactions, and Corporate Governance, in SM Energy’s definitive proxy statement for the 2014 annual meeting of stockholders to be filed within 120 days from December 31, 2013 .
\ No newline at end of file
diff --git a/raw/filings/0000893538/2013/0000893538-14-000010/item9a.txt b/raw/filings/0000893538/2013/0000893538-14-000010/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..06358448b7c4300d415203493aa21f859f7f9bf4
--- /dev/null
+++ b/raw/filings/0000893538/2013/0000893538-14-000010/item9a.txt
@@ -0,0 +1,34 @@
+ITEM 9A. CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Controls and Procedures 
+We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. 
+Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant. 
+An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls 
+are effective at a reasonable assurance level. 
+Changes in Internal Control Over Financial Reporting 
+There have been no changes during the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+148 
+Management’s Report on Internal Control over Financial Reporting 
+Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that: 
+(i) 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+(ii) 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+(iii) 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements. 
+Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. 
+Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013 . In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (1992 framework) . 
+Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2013 . 
+The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal controls over financial reporting. That report immediately follows this report. 
+149 
+Report of Independent Registered Public Accounting Firm 
+The Board of Directors and Stockholders of SM Energy Company and subsidiaries 
+We have audited SM Energy Company and subsidiaries’ internal control over financial reporting as of December 31, 2013 , based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). SM Energy Company and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, SM Energy Company and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013 , based on the COSO criteria. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of SM Energy Company and subsidiaries as of December 31, 2013 , and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for the year then ended and our report dated February 19, 2014 expressed an unqualified opinion thereon . 
+/s/ Ernst & Young LLP 
+Denver, Colorado 
+February 19, 2014 
+150
\ No newline at end of file
diff --git a/raw/filings/0000893538/2013/0000893538-14-000010/rp_note.txt b/raw/filings/0000893538/2013/0000893538-14-000010/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000893538/2013/0000893538-14-000010/rpt_disclosure.txt b/raw/filings/0000893538/2013/0000893538-14-000010/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..4375a00cf3c1436a1b1dc3c83da28e348e38b2de
--- /dev/null
+++ b/raw/filings/0000893538/2013/0000893538-14-000010/rpt_disclosure.txt
@@ -0,0 +1,40 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+Policies and Procedures on Transactions with Related Persons 
+Our Related Person Transactions Policy sets forth the policies and procedures for the Audit Committee's review of any transaction,
+arrangement, or relationship (including any indebtedness or guarantee of indebtedness) or series of similar transactions, arrangements, or relationships in which (a) we are a participant,
+(b) the aggregate amount involved will or may be expected to exceed $120,000 per annum, and (c) a related person has or will have a direct or indirect material interest. For purposes of
+our Related Person Transactions Policy, a "related person" means (i) any of our directors, executive officers, or nominees for director, (ii) any stockholder that beneficially owns more
+than 5% of our outstanding shares of common stock, and (iii) any immediate family member of any of the foregoing. The Audit Committee approves or ratifies only those transactions that it
+determines in good faith are in, or are not inconsistent with, our best interests and the best interests of our stockholders. 
+In
+determining whether to approve or ratify a transaction with a related person, the Audit Committee takes into account the factors it deems appropriate, which may include, among
+others, the benefits to us, the availability of other sources for comparable products or services, the impact on a director's independence in the event the related person is a director, and the extent
+of the related person's interest in the transaction. The Audit Committee reviews and assesses ongoing relationships with a related person on at least an annual basis to ensure that they are in
+compliance with the policy and remain appropriate. 
+In
+addition, our By-Laws provide that a director, officer, or employee of our company may not pursue for his or her own account a business or investment opportunity that he or she
+learned about through his or her affiliation with us. These restrictions do not apply to the acquisition of less than 1% of the publicly traded stock of another company. 
+Related Person Transactions 
+We recognize that transactions with related persons may raise questions among stockholders regarding whether those transactions are
+consistent with our best interests and the best interests of our stockholders. It is our policy to enter into or ratify such transactions only when the Board, acting through the Audit Committee or as
+otherwise described herein, determines that the transaction in question is in, or is not inconsistent with, our best interests and the best interests of our stockholders. Such transactions include,
+but are not limited to, situations where we may obtain products or services of a nature, quantity or quality, or on other terms, that are not readily available from alternate sources, or when we
+obtain products or services from, or provide products or services to, related persons on an arm's length basis on terms comparable to those obtained from or provided to unrelated third parties or on
+terms comparable to those obtained from or provided to employees generally. The only transaction between our company and a related person since January 1, 2014, involves our relationship with
+Tesco Corporation ("Tesco"). Mr. Quintana was the President, Chief Executive Officer, and a director of Tesco before his retirement in January 2015. Tesco designs, manufactures, and delivers
+technology based solutions for the upstream energy industry, including oilfield drilling and completion technology, services, and equipment. In 2006, we entered into an agreement with Tesco to provide
+equipment and services to us in connection with our drilling and completion operations based on Tesco's industry-recognized ability to supply specific high-quality equipment and services for drilling
+and casing needs, which are particularly well suited for certain of our operations. Under our agreement, 
+12 
+Table of Contents 
+Tesco
+from time to time upon our request, provides equipment or services to us. This agreement continues until canceled by either us or Tesco on 30 days advance written notice. Pursuant to this
+agreement, we are obligated to pay Tesco only for services actually performed or equipment provided. This agreement does not require us to make any other payments to Tesco, nor does it obligate us to
+use Tesco for any services or equipment. Mr. Quintana did not have any direct or indirect interest in the transaction, other than as a result of having served as an executive officer and
+director of Tesco. Mr. Quintana had no input in our selection of Tesco for equipment and services or the terms of our agreement with Tesco. Decisions to use Tesco are made by technical
+professionals supervising the relevant regional activity, based on their assessment of Tesco's equipment and services and related costs in comparison to other providers. In 2014, we paid Tesco
+$1,115,956. The amount we paid Tesco during 2014 for equipment and services represented approximately 8% of the total amount paid by us to all service providers (including Tesco) for similar equipment
+and services during 2014. In accordance with our Related Person Transactions Policy, the Audit Committee reviewed the relationship between us and Tesco and determined that the relationship is in our
+best interests and the best interests of our stockholders. 
+13 
+Table of Contents
\ No newline at end of file
diff --git a/raw/proxies/0001092662/0001092662-09-000053/proxy.txt b/raw/proxies/0001092662/0001092662-09-000053/proxy.txt
new file mode 100644
index 0000000000000000000000000000000000000000..415d7c557c09bd25137347be2f474a4364c59bf2
--- /dev/null
+++ b/raw/proxies/0001092662/0001092662-09-000053/proxy.txt
@@ -0,0 +1,1870 @@
+DEF 14A
+1
+def14_a.htm
+PROXY STATEMENT 2009
+def14_a.htm 
+UNITED
+STATES 
+SECURITIES
+AND EXCHANGE COMMISSION 
+SCHEDULE
+14A INFORMATION 
+Proxy
+Statement Pursuant to Section 14(a) of the Securities Exchange Act of
+1934 
+[Amendment
+No. ____] 
+Filed by
+the Registrant [X] 
+Filed by
+a Party other than the Registrant [_] 
+Check the
+appropriate box: 
+[ ]
+Preliminary Proxy Statement 
+[_]
+Confidential, for Use of the Commission Only (as permitted by Rule
+14a-6(e)(2)) 
+[X]
+Definitive Proxy Statement 
+[_]
+Definitive Additional Materials 
+[_]
+Soliciting Material under ss. 240.14a-12 
+CHEMBIO
+DIAGNOSTICS, INC. 
+---------------------------------------------- 
+(Name of
+Registrant as Specified in Its Charter) 
+Not
+Applicable 
+----------------------------------------------------------------- 
+(Name of
+Person(s) Filing Proxy Statement, if other than the Registrant) 
+Payment
+of Filing Fee (Check the appropriate box): 
+[X] No
+fee required. 
+[_] Fee
+computed on table below per Exchange Act Rules 14a-6(i)(1) and
+0-11. 
+1. 
+Title
+of each class of securities to which transaction
+applies: 
+2. 
+Aggregate
+number of securities to which transaction
+applies: 
+3. 
+Per
+unit price or other underlying value of transaction computed pursuant to
+Exchange Act Rule 0-11 (set forth the amount on which the filing fee is
+calculated and state how it was
+determined): 
+4. 
+Proposed
+maximum aggregate value of
+transaction: 
+5. 
+Total
+fee paid: 
+[_] Fee
+paid previously with preliminary materials. 
+[_] Check
+box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2)
+and identify the filing for which the offsetting fee was paid
+previously. Identify the previous filing by registration statement
+number, or the Form or Schedule and the date of its filing. 
+1. 
+Amount
+Previously Paid: 
+2. 
+Form,
+Schedule or Registration Statement
+No.: 
+3. 
+Filing
+Party: 
+4. 
+Date
+Filed: 
+CHEMBIO
+DIAGNOSTICS, INC. 
+3661
+Horseblock Road 
+Medford,
+NY 11763 
+(631)
+924-1135 
+NOTICE
+OF ANNUAL MEETING OF STOCKHOLDERS 
+To
+be held June 3, 2009 
+The
+Annual Meeting of Stockholders of Chembio Diagnostics, Inc. will be held on June
+3, 2009 at 10:00 am (local time) at Chembio, 3661 Horseblock Road, Medford, New
+York 11763, for the following purposes: 
+1. 
+To
+elect three directors to the Company’s Board of
+Directors; 
+2. 
+To
+consider and vote upon a proposal recommended by the Board of Directors to
+ratify the selection of Parente Randolph, LLC to serve as our certified
+independent accountants for the fiscal year ending December 31,
+2009; 
+3. 
+To,
+in their discretion, vote upon an adjournment or postponement of the
+meeting; and 
+4. To
+transact any other business that properly may come before the Annual
+Meeting. 
+Only the
+stockholders of record as shown on our transfer books at the close of business
+on April 9, 2009 are entitled to notice of, and to vote at, the Annual
+Meeting. Our Annual Report for the fiscal year ended December 31,
+2008 on Form 10-K is being provided to stockholders with this proxy
+statement. The Annual Report is not part of the proxy soliciting
+material. 
+In
+accordance with rules and regulations recently adopted by the SEC, we are
+furnishing proxy materials to our stockholders of record by (i) mailing a
+printed copy of the proxy materials, and (ii) providing Internet access to the
+proxy materials. Both stockholders of record who receive a printed
+copy of proxy materials and stockholders of record who receive a Notice of
+Internet Availability of Proxy Materials will be permitted to access our proxy
+materials on the Internet. In addition, stockholders of record who
+receive a Notice of Internet Availability of Proxy Materials can receive a
+printed copy of the proxy materials by requesting this information from the
+Company. The Notice of Internet Availability of Proxy Materials will
+instruct you as to how you may access and review all of the important
+information contained in the proxy materials. The Notice of Internet
+Availability of Proxy Materials also instructs you as to how you may submit your
+proxy on the Internet. 
+All
+stockholders, regardless of whether they expect to attend the meeting in person,
+are requested to complete, date, sign and return promptly the enclosed form of
+proxy via the Internet or in the accompanying envelope (which requires no
+postage if mailed in the United States), as applicable. The person
+executing the proxy may revoke it by filing with our Secretary an instrument of
+revocation or a duly executed proxy bearing a later date, or by electing to vote
+in person at the Annual Meeting. 
+All stockholders are extended a cordial
+invitation to attend the Annual Meeting. 
+By the
+Board of Directors 
+/s/ Lawrence A.
+Siebert 
+Medford,
+New
+York Lawrence
+A. Siebert 
+April 14,
+2009 President,
+Chief Executive Officer 
+and Chairman of the
+Board 
+PROXY
+STATEMENT 
+CHEMBIO
+DIAGNOSTICS, INC. 
+3661
+Horseblock Road 
+Medford,
+NY 11763 
+(631)
+924-1135 
+ANNUAL
+MEETING OF STOCKHOLDERS 
+To
+be held June 3, 2009 
+SOLICITATION
+AND REVOCATION OF PROXIES 
+This
+proxy statement is provided in connection with the solicitation of proxies by
+and on behalf of the Board of Directors of Chembio Diagnostics, Inc., a Nevada
+corporation (referred to as the “Company” or “Chembio” or “we” or “us”), to be
+voted at the Annual Meeting of Stockholders to be held at 10:00 am (local time)
+on June 3, 2009 at Chembio, 3661 Horseblock Road, Medford, New York 11763, or at
+any adjournment or postponement of the Annual Meeting. We anticipate
+that this proxy statement and the accompanying form of proxy will be first made
+available to stockholders on or about April 20, 2009. 
+In
+accordance with rules and regulations recently adopted by the SEC, we are
+furnishing proxy materials to our stockholders of record by (i) mailing a
+printed copy of the proxy materials, and (ii) providing Internet access to the
+proxy materials. Both stockholders of record who receive a printed
+copy of proxy materials and stockholders of record who receive a Notice of
+Internet Availability of Proxy Materials will be permitted to access our proxy
+materials on the Internet. In addition, stockholders of record who
+receive a Notice of Internet Availability of Proxy Materials can receive a
+printed copy of the proxy materials by requesting this information from the
+Company. The Notice of Internet Availability of Proxy Materials will
+instruct you as to how you may access and review all of the important
+information contained in the proxy materials. The Notice of Internet
+Availability of Proxy Materials also instructs you as to how you may submit your
+proxy on the Internet. 
+A
+stockholder giving a proxy may revoke it at any time before it is exercised by
+delivering written notice of revocation to our Secretary, by substituting a new
+proxy executed at a later date, or by requesting, in person at the Annual
+Meeting, that the proxy be returned. 
+The
+solicitation of proxies is to be made on the Internet and through
+mailings. However, following the initial solicitation, further
+solicitations may be made by telephone or oral communication with
+stockholders. Our officers, directors and employees may solicit
+proxies, but these persons will not receive compensation for that solicitation
+other than their regular compensation as employees. Arrangements also
+will be made with brokerage houses and other custodians, nominees and
+fiduciaries to provide access to the solicitation materials to beneficial owners
+of the shares held of record by those persons. We may reimburse those
+persons for reasonable out-of-pocket expenses incurred by them in so
+doing. We will pay all expenses involved in preparing, assembling and
+mailing this proxy statement and the enclosed material. 
+- 1
+- 
+VOTING
+SECURITIES 
+The close
+of business on April 9, 2009 has been fixed as the record date for the
+determination of holders of record of the Company’s common stock, $0.01 par
+value per share, entitled to notice of and to vote at the Annual
+Meeting. On the record date, 61,944,901 shares of common stock were
+outstanding and eligible to be voted at the Annual Meeting. A
+majority of the issued and outstanding shares of common stock entitled to vote,
+represented either in person or by proxy, constitutes a quorum at any meeting of
+the stockholders. If sufficient votes for approval of the matters to
+be considered at the Annual Meeting have not been received prior to the meeting
+date, we intend to postpone or adjourn the Annual Meeting in order to solicit
+additional votes. The form of proxy we are soliciting requests
+authority for the proxies, in their discretion, to vote the stockholders’ shares
+with respect to a postponement or adjournment of the Annual
+Meeting. At any postponed or adjourned meeting, we will vote any
+proxies received in the same manner described in this proxy statement with
+respect to the original meeting. 
+VOTING
+PROCEDURES 
+Votes at
+the Annual Meeting are counted by an inspector of election appointed by the
+Chairman of the meeting, and you can ensure that your shares are voted at the
+meeting by submitting your proxy card on the Internet, or by completing,
+signing, dating and returning the enclosed proxy form in the envelope
+provided. If a quorum is present, unless a different number of votes
+is required by Nevada law or our Articles Of Incorporation, an affirmative vote
+of a majority of the votes entitled to be cast by those present in person or by
+proxy is required for the approval of the items submitted to shareholders for
+their consideration, except for the election of our directors, for which a
+plurality of the votes cast is required. Abstentions by those present
+at the Annual Meeting are tabulated separately from affirmative and negative
+votes and do not constitute affirmative votes. If a shareholder
+submits his or her proxy card and withholds authority to vote for any or all of
+the items, the votes represented by the proxy card will be deemed to be present
+at the meeting for purposes of determining the presence of a quorum but will not
+be counted as affirmative votes. Shares in the names of brokers that
+are not voted on a particular matter are treated as not present with respect to
+that matter. 
+FORWARD-LOOKING
+STATEMENTS 
+This
+proxy statement includes “forward-looking” statements within the meaning of
+Section 21E of the Securities Exchange Act of 1934. All
+statements other than statements of historical facts included in this proxy
+statement regarding our financial position, business strategy and plans and
+objectives of management for future operations and capital expenditures are
+forward-looking statements. Although we believe that the expectations
+reflected in the forward-looking statements and the assumptions upon which the
+forward-looking statements are based are reasonable, we can give no assurance
+that such expectations and assumptions will prove to have been
+correct. 
+SECURITY
+OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 
+On April
+9, 2009, there were 61,944,901 shares of common stock
+issued and outstanding and eligible to be voted at the Annual
+Meeting. The following table sets forth certain information regarding
+the beneficial ownership of our common stock by each person or entity known by
+us to be the beneficial owner of more than 5% of the outstanding shares of
+common stock, each of our directors and each of our “named executive officers”
+and all of our directors and executive officers as a group as of April 10,
+2009. 
+- 2
+- 
+Name
+and Address of Beneficial Owner 
+Amount
+and Nature of Beneficial Owner 
+Percent
+of Class 
+Siebert,
+Lawrence (1) 
+3661
+Horseblock Road 
+Medford,
+NY 11763 
+6,933,615 
+11.11 
+% 
+Esfandiari,
+Javan (2) 
+3661
+Horseblock Road 
+Medford,
+NY 11763 
+779,580 
+1.25 
+% 
+Larkin,
+Richard (3) 
+3661
+Horseblock Road 
+Medford,
+NY 11763 
+267,672 
+0.43 
+% 
+Ippolito,
+Tom (4) 
+3661
+Horseblock Road 
+Medford,
+NY 11763 
+65,000 
+0.10 
+% 
+Bruce,
+Richard (5) 
+3661
+Horseblock Road 
+Medford,
+NY 11763 
+135,075 
+0.22 
+% 
+Meller,
+Gary (6) 
+3661
+Horseblock Road 
+Medford,
+NY 11763 
+354,300 
+0.57 
+% 
+Davis,
+Katherine L. (7) 
+3661
+Horseblock Road 
+Medford,
+NY 11763 
+75,650 
+0.12 
+% 
+GROUP (8) 
+8,610,892 
+13.53 
+% 
+Vicis
+Capital Master Fund 
+126
+East 56th Street, Tower 56, Suite 700 
+New
+York, NY 10022 
+4,608,707 
+7.44 
+% 
+Millenium
+3 Opportunity Fund, LLC (9) 
+4
+Becker Farm Road 
+Roseland,
+NJ 07068 
+4,006,610 
+6.31 
+% 
+Inverness
+Medical Innovations, Inc. 
+51
+Sawyer Road, Suite 200 
+Waltham,
+MA 02453 
+5,367,840 
+8.67 
+% 
+Crestview
+Capital Master, LLC 
+95
+Revere Drive, Suite A 
+Northbrook,
+IL 60062 
+18,907,432 
+30.52 
+% 
+Beneficial
+ownership is determined in accordance with the Rule 13d-3(a) of the Securities
+Exchange Act of 1934, as amended, and generally includes voting or investment
+power with respect to securities. Except as subject to community
+property laws, where applicable, the person named above has sole voting and
+investment power with respect to all shares of our common stock shown as
+beneficially owned by him. 
+The
+beneficial ownership percent in the table is calculated with respect to the
+number of outstanding shares (61,944,901) of the Company's common stock
+outstanding as of April 10, 2009. Each stockholder's ownership is
+calculated as the number of shares of common stock owned plus the number of
+shares of common stock into which any preferred stock, warrants, options or
+other convertible securities owned by that stockholder can be converted within
+60 days. 
+The term
+“named executive officer” refers to our principal executive officer, our two
+most highly compensated executive officers other than the principal executive
+officer who were serving as executive officers at the end of 2008, and two
+additional individuals for whom disclosure would have been provided but for the
+fact that the individuals were not serving as executive officers of the Company
+at the end of 2008. 
+(1) 
+Includes
+495,000 shares issuable upon exercise of options exercisable within 60
+days. 
+(2) 
+Includes
+562,500 shares issuable upon exercise of options exercisable within 60
+days and 2,007 shares issuable upon exercise of
+warrants. 
+(3) 
+Includes
+212,500 shares issuable upon exercise of options exercisable within 60
+days. 
+(4) 
+Includes
+65,000 shares issuable upon exercise of options exercisable within 60
+days. 
+(5) 
+Includes
+140,000 shares issuable upon exercise of options exercisable within 60
+days. 
+(6) 
+Includes
+159,000 shares issuable upon exercise of options exercisable within 60
+days. Does not include 108,000 shares issuable upon exercise of
+options that are not exercisable within the next 60
+days. 
+(7) 
+Includes
+75,650 shares issuable upon exercise of options exercisable within 60
+days. Does not include 108,000 shares issuable upon exercise of options
+that are not exercisable within the next 60
+days. 
+(8) 
+Includes
+footnotes (1)-(8) 
+(9) 
+Includes
+1,557,376 shares issuable upon exercise of
+warrants. 
+- 3
+- 
+AVAILABLE
+INFORMATION 
+Copies of
+our Annual Report on Form 10-K are being furnished to each stockholder with this
+proxy statement, and are available on the internet pursuant to the instructions
+set forth in the attached “Notice Regarding the Availability of Proxy
+Materials.” Upon written request, we will provide, without charge, a
+copy of our quarterly reports on Form 10-Q for the quarters ended September
+30, 2008 and June 30, 2008 to any stockholder of record, or to any stockholder
+who owns common stock listed in the name of a bank or broker as nominee, at the
+close of business on April 9, 2009. Any request for a copy of these
+reports should be mailed to the Secretary, Chembio Diagnostics, Inc., 3661
+Horseblock Road, Medford, NY 11763. Stockholders may also
+receive copies of these reports by accessing the Company’s website at
+www.chembio.com or by accessing the SEC’s website at www.sec.gov . 
+ITEM
+1. ELECTION OF DIRECTORS 
+At the
+Annual Meeting, the stockholders will elect three directors to serve as our
+Board of Directors. Each director will be elected to hold office
+until the next annual meeting of stockholders and thereafter until his/her
+successor is elected and qualified. The affirmative vote of a
+plurality of the shares voted at the Annual Meeting in person or by proxy is
+required to elect each director. Cumulative voting is not permitted
+in the election of directors. In the absence of instructions to the
+contrary, the person named in the accompanying proxy shall vote the shares
+represented by that proxy for the persons named below as management’s nominees
+for directors. Nominees Siebert, Meller and Davis currently serve as
+directors of the Company. 
+It is not
+anticipated that any of the nominees will become unable or unwilling to accept
+nomination or election, but, if that should occur, the persons named in the
+proxy intend to vote for the election of such other person as the Board of
+Directors may recommend. 
+The
+following table sets forth, with respect to each nominee for director, the
+nominee’s age, positions and offices with the Company, the expiration of the
+nominee’s term as a director and the year in which the nominee first became a
+director. Individual background information concerning each of the
+nominees follows the table. For additional information concerning the
+nominees, including stock ownership and compensation, see “Executive
+Compensation,” “Beneficial Ownership of the Company’s Equity Securities,” and
+“Certain Transactions With Management And Principal Stockholders.” 
+Name 
+Age 
+Position(s)
+and Office(s) with the Company 
+Expiration
+of Term of Director 
+Initial
+Date as Director 
+Lawrence
+A. Siebert 
+52 
+Chief
+Executive Officer, President and Chairman of the Board 
+2009
+Annual Meeting 
+May
+2004 
+Dr.
+Gary Meller 
+59 
+Director 
+2009
+Annual Meeting 
+March
+2005 
+Katherine
+L. Davis 
+52 
+Director 
+2009
+Annual Meeting 
+May
+2007 
+Lawrence A. Siebert
+(52), President,
+Chief Executive Officer and Direc to r. Mr. Siebert was appointed
+President of Chembio
+Diagnostics, Inc. and a
+member of our board of direc to rs upon consummation of the
+merger. Mr. Siebert has been Chairman of Chembio Diagnostic Systems
+Inc. for approximately thirteen years and its President since May
+2002. Mr. Siebert’s background is in private equity and venture
+capital investing. From 1982 to 1991, Mr. Siebert was associated with Stanwich Partners,
+Inc . , which during that period invested in
+middle market manufacturing and distribution companies. From 1992
+to 1999, Mr. Siebert was an investment
+consultant and business broker with Siebert Capital Corp. and Siebert Associates
+LLC, and was a principal inves to r in a privately held test and
+measurement company which was sold in 2002. Mr. Siebert received a JD
+from Case Western Reserve University School of Law in 1981 and a BA with
+Distinction in Economics from the University of Connecticut in 1978. 
+- 4
+- 
+Dr. Gary
+Meller 
+(5 9 ), Direc to r. Dr. Meller was elected
+to our Board of Direc to rs on March 15, 2005, and currently
+serves on the Company’s Audit, Compensation and Nominating and Corporate
+Governance Committees, including as Chairman of the Compensation
+Committee. Dr. Meller has been the president of CommSense Inc., a
+healthcare business development company, since 2001. CommSense Inc.
+works with clients in Europe, Asia, North America, and the Middle East on medical information technology,
+medical records, pharmaceutical product development and financing, health
+services operations and strategy, and new product and new market
+development. From 1999 until 2001 Dr. Meller was the executive vice
+president, North
+America , of NextEd Ltd., a
+leading internet educational services company in the Asia Pacific
+region. Dr. Meller also is a limited partner and a member of the
+Advisory Board of Crestview Capital Master LLC, which is our largest
+s to ckholder. Dr. Meller is a graduate of the University of New
+Mexico School of Medicine and has an MBA from the Harvard Business School . 
+Kathy Davis
+(52), Direc to r. Ms. Davis was elected to the Company’s Board of
+Direc to rs in May 2007, and currently serves on
+the Company’s Audit, Compensation and Nominating And Corporate Governance
+Committees, including as Chairman of each of the Audit Committee and the
+Nominating And Corporate Governance Committee. Ms. Davis is presently
+the owner of Davis Design Group LLC, a company that provides analytical and
+visual to ols for public policy design. 
+Previously she served as the Chief Executive Officer of Global Access Point, a
+start up company with products for data transport, data processing, and data
+s to rage network and hub facilities. 
+From Oc to ber 2003 to January 2005, Ms. Davis was Lieutenant
+Governor of the State of Indiana , and from January 2000 to Oc to ber 2003 was Controller of the City of
+Indianapolis . From 1989 to 2003, Ms. Davis held leadership
+positions with agencies and programs in the State of Indiana including State Budget
+Direc to r, Secretary of Family & Social
+Services Administration, and Deputy Commissioner of Transportation. From 1982
+to 1989 Ms. Davis held increasingly
+senior positions with Cummins Engine, where she managed purchasing, product
+cost, manufacturing, engineering, and assembly of certain engine product
+lines. Ms. Davis also led the startup of and initial investments by a $50
+million Indiana state technology fund, serves on the
+not-for-profit boards of Noble of Indiana, Indiana Museum of African American
+His to ry, University of Evansville Institute
+of Global Enterprise, and Purdue College of Science Dean’s Leadership Council.
+She has a Masters of Business Administration from Harvard Business School and a Bachelor of Science in
+Mechanical Engineering from the Massachusetts Institute of
+Technology. 
+Required
+Vote; Board Recommendation 
+The
+affirmative vote of a plurality of the shares voted at the Annual Meeting in
+person or by proxy is required to elect each director. The Board of
+Directors unanimously recommends that the stockholders vote FOR the election of
+the three nominees listed above. 
+INFORMATION
+REGARDING THE BOARD OF DIRECTORS 
+AND
+EXECUTIVE OFFICERS 
+Other
+Executive Officers 
+The
+following table sets forth with respect to each other executive officer, the
+officer’s age, the officer’s positions and offices with the Company, the
+expiration of his term as an officer and the period during which he has served,
+either the Company or Chembio Diagnostic Systems Inc. 
+Name 
+Age 
+Position
+With Company 
+Initial
+Date as Officer 
+Richard
+J. Larkin 
+52 
+Chief
+Financial Officer 
+2003 
+Javan
+Esfandiari 
+42 
+Director
+of Research & Development 
+2004 
+Richard
+Bruce 
+55 
+Vice
+President, Operations 
+2004 
+Tom
+Ippolito 
+46 
+Vice
+President of Regulatory Affairs, Quality Assurance and Quality
+Control 
+2005 
+- 5
+- 
+Richard J.
+Larkin 
+(52), Chief Financial
+Officer. Mr. Larkin was appointed as Chief Financial Officer of
+Chembio Diagnostics,
+Inc. upon consummation of
+the merger. Mr. Larkin oversees our financial activities and
+information systems. Mr. Larkin has been the Chief Financial Officer
+of Chembio Diagnostic Systems Inc. since September 2003. Prior
+to joining Chembio Diagnostic Systems
+Inc., Mr. Larkin served as CFO at Visual Technology Group from May 2000
+to September 2003, and also led their
+consultancy program that provided hands-on expertise in all aspects of financial
+service, including the initial assessment of client financial reporting
+requirements within an Enterprise Resource Planning (Manufacturing) environment
+through training and implementation. Prior to joining VTG, he served as CFO at
+Protex International Corporation from May 1987 to January 2000. Mr. Larkin
+holds a BBA in Accounting from Dowling College and is a member of the American
+Institute of Certified Public Accountants. 
+Javan
+Esfandiari (42), Executive VP of Research and
+Development. Mr. Esfandiari joined Chembio Diagnostic Systems, Inc,
+in 2000. Mr. Esfandiari co-founded, and became a co-owner of Sinovus
+Biotech AB where he served as Direc to r of Research and Development
+concerning lateral flow technology until Chembio Diagnostic Systems Inc.
+acquired Sinovus Biotech AB in 2000. From 1993 to 1997, Mr. Esfandiari was
+Direc to r of Research and Development with
+On-Site Biotech/National Veterinary Institute, Uppsala , Sweden , which was working in collaboration
+with Sinovus Biotech AB on development of veterinary lateral flow
+technology. Mr. Esfandiari received his B.Sc. in Clinical Chemistry
+and his M. Sc. in Molecular Biology from Lund University , Sweden . He has published articles
+in various veterinary journals and has co-authored articles on tuberculosis
+serology with Dr. Lyashchenko. 
+Richard Bruce
+(55), Vice President,
+Operations. Mr. Bruce was hired in April 2000 as Direc to r of Operations. He is responsible for
+manufacturing, maintenance, inven to ry, shipping, receiving, and warehouse
+operations. Prior to joining Chembio Diagnostic Systems
+Inc., he held direc to r level positions at Wyeth
+Labora to ries from 1984 to 1993. From 1993 to 1998, he held various management
+positions in the Operations department at Biomerieux. From 1998
+to 2000, he held a management position at
+V.I. Technologies. Mr. Bruce has over thirty years of operations
+management experience with Fortune 500 companies in the field of in-vitro
+diagnostics and blood fractionation. Mr. Bruce received his BS in
+Management from National Louis University in 1997. 
+Tom
+Ippoli to (46), VP of Regula to ry Affairs, QA and QC. Mr.
+Ippoli to joined Chembio in June 2005. He has
+over twenty years experience with in vitro diagnostics for infectious diseases,
+protein therapeutics, vaccine development, Process Development,
+Regula to ry Affairs and Quality Management. Over
+the years, Mr. Ippoli to has held Vice President level
+positions at Biospecific Technologies, Corp. from 2000 - 2005, Direc to r level positions in Quality Assurance,
+Quality Control, Process Development and Regula to ry Affairs at United Biomedical, Inc.
+from 1987 - 2000. Mr. Ippoli to is the Course Direc to r for “drug development process” and
+“FDA Regula to ry Process” for the BioScience
+Certificate Program at the New York State University of S to ny Brook, a program he has been a part
+of since its inception in 2003. 
+Each of
+our officers serves at the pleasure of the Board of Directors. There
+are no family relationships among our officers and directors. 
+Certain
+Transactions with Management and Principal Stockholders 
+The
+executive officers of the Company are as follows: Lawrence A. Siebert, president
+and chairman of the board of directors of the Company, Richard J. Larkin, chief
+financial officer of the Company, and Javan Esfandiari, executive vice president
+of Research and Development of the Company. 
+On
+February 15, 2008, the Compensation Committee approved the reduction of the
+exercise price to $0.48 per share of each employee stock option award issued
+under the 1999 Stock Option Plan for which the exercise price was greater than
+$0.48 per share. As a result of this price reduction, the following
+number of employee stock options owned by the Company’s officers and directors
+at that time under the 1999 Stock Option Plan qualified for this price
+reduction: (i) Mr. Siebert: 170,000 options; (ii) Mr. Larkin: 87,500 options;
+(iii) Mr. Esfandiari: 532,500 options; (iv) Mr. Aromando: 100,000 options; (v)
+Mr. Ippolito: 15,000 options; (vi) Mr. Bruce: 90,000 options; (vii) Mr. Carus:
+252,000 options; (viii) Dr. Meller: 252,000 options; and (ix) Ms. Davis: 180,000
+options. 
+- 6
+- 
+In
+addition, on February 15, 2008 the Compensation Committee granted, to certain of
+the Company’s existing officers at that time options to purchase the Company’s
+common stock under the 1999 Stock Option Plan as follows: (i) Mr. Siebert,
+75,000 options; (ii) Mr. Larkin, 75,000 options; (iii) Mr. Esfandiari, 60,000
+options; (iv) Mr. Bruce, 50,000 options; (v) Mr. Ippolito, 50,000 options; and
+(vi) Mr. Aromando, 25,000 options. The exercise price for each of
+these options is $0.22 per share, which was the closing market price for the
+Company’s common stock on February 15, 2008. The options vest on the
+date of the grant, and each option granted will expire and terminate, if not
+exercised sooner, upon the earlier to occur of (a) 30 days after termination of
+the employee’s employment with the Company or (b) the fifth anniversary of the
+date of grant. 
+Avi
+Pelossof, the Company’s Vice President of Sales and Marketing from May 5, 2004
+to January 31, 2007, exercised 100,000 options in December 2006 at $0.60 per
+share, and another 50,000 options in January 2007 at $0.75 per
+share. 
+Robert
+Aromando was the Company’s Executive Vice President of Commercial Operations
+from May 2007 to August 2008. In June 2007 in connection with his
+joining the Company, he was granted options to purchase 100,000 shares of common
+stock at an exercise price of $0.62 per share. These options became
+exercisable one year from the date of grant. As discussed above, on
+February 15, 2008, the exercise price for these options was reduced to
+$0.48. Mr. Aromando left the employ of the Company in August 2008,
+and since then his options have expired. 
+Dr. Gary
+Meller, a non-employee director of the Company, currently serves as a limited
+partner and a member of the Advisory Board of Crestview Capital Master LLC,
+referred to herein as Crestview, which was the lead investor, investing $3
+million, in our Series B Preferred Stock private placement in January 2005, and
+which subsequently invested an additional $1 million in our Series B Preferred
+Stock private placement in March 2006. Crestview also invested $2
+million in our Series C Preferred Stock private placement in September
+2006. Details of these transactions are set forth below. Crestview
+currently is the largest stockholder of the Company, with beneficial ownership
+of approximately 30.5 percent of our common stock. 
+As
+referred to above, in January 2005, for a purchase price of $3 million,
+Crestview acquired 60 shares of our Series B Preferred Stock, and warrants to
+purchase 4,672,130 shares of our common stock at a warrant exercise price of
+$0.61 per share. As described below, in December 2007, these shares
+of Preferred Stock and warrants were exchanged for shares of the Company’s
+common stock. 
+In March
+2006, for a purchase price of $1 million, Crestview acquired 20 shares of Series
+B Preferred Stock with warrants to purchase 1,557,377 shares of common stock at
+a warrant exercise price of $0.61 per share. These shares were issued
+in connection with the Company’s January 2005 private placement as described
+herein. In September 2006, for a purchase price of $2 million, we
+issued 40 shares of Series C Preferred Stock to Crestview together with warrants
+to purchase 625,000 shares of common stock at an exercise price of $1.00 per
+share. 
+In
+January 2007, because of comments from the staff of the SEC concerning the
+Company’s registration statement No. 333-138266 (the “Prospectus”), Crestview
+agreed to reduce the number of its shares of common stock covered by the
+Prospectus to 2,000,000. Crestview also agreed to waive any penalties
+that the Company would otherwise owe Crestview because of the failure to
+register all of Crestview’s shares in the Prospectus. In
+consideration for this waiver, the Company agreed that, upon request by
+Crestview, the Company will file one or more registration statements with the
+SEC in order to register the resale of other shares beneficially owned by
+Crestview. The cost of any such registration statements shall be
+borne by the Company. 
+- 7
+- 
+In
+addition to Crestview’s $2,000,000 investment in the Company’s September 2006
+private placement of Series C Preferred Stock, the Company also received an
+investment of $2,000,000 on that date from Inverness Medical Innovations, Inc.
+(“Inverness”). At that time, a Certificate of Designation for the
+Series C Preferred Stock was filed with the Secretary of State of Nevada
+reflecting the agreed upon conversion price of $0.85 per share of common
+stock. This private placement of Series C Preferred Stock was
+completed on October 5, 2006, and it raised an aggregate of $8,150,000
+(including the $2,000,000 invested by each of Crestview and
+Inverness). During the period between September 29, 2006 and October
+5, 2006, we requested the assistance of Crestview and others in identifying
+prospective investors for us. 
+On
+December 19, 2007 (the “Closing Date”), amendments to the governing documents
+for the Company’s Series A, Series B and Series C Convertible Preferred Stock
+(collectively, the “Preferred Stock”) and for certain warrants and options
+(collectively, the “Non-Employee Warrants”), not including options or warrants
+issued to employees or directors in their capacity as such (these actions
+collectively, the “Plan”), were approved by the Company and the requisite
+percentages of the holders of the Preferred Stock and of the Non-Employee
+Warrants. Subsequent to these amendments, all shares of Preferred
+Stock were converted to common stock and certain of the Non-Employee Warrants
+were exercised, including the following: Mr. Siebert’s 38.74442 shares of Series
+A Preferred Stock were converted into 2,421,526 shares of common stock at $0.48
+per share, his 1.08545 shares of Series B Preferred Stock were converted into
+113,067 shares of common stock at $0.48 per share, and Mr. Siebert purchased
+337,500 shares of common stock through the exercise of warrants at an exercise
+price of $0.40 per share, for a total of $135,000 in cash; Mr. Larkin converted
+.50392 shares of his Series A Preferred Stock into 37,794 shares of common stock
+at $.40 per share, in addition he received 369 shares of common stock as payment
+of dividends on the series A preferred. He also received 3,050 shares
+of common stock through the exercise of warrants at $.40 per share, or a total
+of $1,220 in cash; Inverness’ 40 shares of Series C Preferred Stock were
+converted into 4,166,666 shares of common stock, and Inverness exercised all of
+its Series C Warrants to purchase a total of 625,000 shares of common stock for
+an aggregate purchase price of $250,000; and Crestview’s 82.32274 shares of
+Series B Preferred Stock were converted into 10,290,342 shares of the
+Company’s common stock, Crestview’s 40 shares of Series C Preferred Stock were
+converted into 4,166,666 shares of common stock, Crestview exercised a portion
+of its Series B Warrants to purchase a total of 60,451 shares of common stock
+for an aggregate purchase price of $24,180.40, and Crestview exercised all of
+its Series C Warrants to purchase a total of 625,000 shares of common stock for
+an aggregate purchase price of $250,000. 
+In June
+2008, pursuant to the Plan (see above), Mr. Siebert, exercised 2,205,731
+warrants, on a cashless basis, into 332,940 shares of common stock, Mr. Larkin
+exercised 27,436 warrants, on a cashless basis, into 4,141 shares of common
+stock, and Crestview exercised 6,169,055 warrants, on a cashless basis, into
+931,177 shares of common stock. 
+During
+the quarter ended December 31, 2008, Inverness notified the Company that
+Inverness had entered into a contract with Bio-Rad Laboratories, Inc.
+(“Bio-Rad”) for royalties on Bio-Rad’s patent for the detection of HIV-2
+antibodies. The agreement also provided for Inverness to pay past
+royalties. The agreements between the Company and Inverness provide
+that the Company is to share in this expense and as such Inverness requested it
+be reimbursed for the Company’s share of past royalties. The Company
+negotiated with Inverness that this liability is to be paid from future revenues
+over approximately the next 18 months. In addition Inverness agreed
+to allow Chembio to pay its royalty obligation to Inverness on Chembio’s sales
+to third parties in the same way and over the same period. 
+- 8
+- 
+Director
+Independence 
+Our
+common stock trades on the OTC Bulletin Board. As such, we are not
+currently subject to corporate governance standards of listed companies, which
+require, among other things, that the majority of the board of directors be
+independent. 
+We are
+not currently subject to corporate governance standards defining the
+independence of our directors, and we have chosen to define an “independent”
+director in accordance with the NASDAQ Global Market's requirements for
+independent directors (NASDAQ Marketplace Rule 4200). Under this
+definition, we have determined that Katherine L. Davis currently qualifies as
+independent director. We do not list the “independent” definition we
+use on our Internet website. 
+Section
+16(a) Beneficial Ownership Reporting Compliance 
+Section
+16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”),
+requires the Company’s directors, executive officers and beneficial owners of
+more than 10% of the Company’s common stock to file with the Securities and
+Exchange Commission initial reports of ownership and reports of changes in
+ownership of common stock and other equity securities of the
+Company. The Company believes that during the year ended December 31,
+2008, each person who was an officer, director and beneficial owner of more than
+10% of the Company’s common stock complied with all Section 16(a) filing
+requirements, except for the Form 4 for Former Director James D. Merselis, which
+was due on March 24, 2008, was filed on March 25, 2008. 
+Board
+of Directors and Committees 
+The Board
+of Directors held six meetings during the
+fiscal year ended December 31, 2008 and each director participated in at
+least 75% of those meetings and meetings of the committees on which he/she
+served. Although the Company does not have a formal policy regarding
+attendance by members of the Board of Directors at the Company’s annual meeting
+of stockholders, the Company encourages each director to attend. None
+of the members of the Board of Directors were present at last year’s annual
+meeting. 
+The
+Company’s Audit Committee met four times in 2008 and currently consists of
+Katherine L. Davis (Chairperson) and Dr. Gary Meller. The Board of
+Directors has determined that Ms. Davis is an “audit committee financial
+expert,” as defined under the rules of the SEC. Each of the members
+of the Audit Committee is “independent” as that term is defined in Rule
+4200(a)(15) of the Nasdaq Stock Market. This committee oversees,
+reviews, acts on and reports to our Board of Directors on various auditing and
+accounting matters including: the selection of our independent
+accountants, the scope of our annual audits, fees to be paid to the independent
+accountants, and the performance of our independent accountants. A
+copy of the committee’s charter is available on the Company’s website at
+www.chembio.com. 
+The
+Company’s Compensation Committee met once in 2008 and currently consists of Dr.
+Gary Meller (Chairperson) and Katherine L. Davis. Each of the
+committee’s members is “independent” as that term is defined in Rule 4200(a)(15)
+of the Nasdaq Stock Market. The Compensation Committee establishes
+salaries, incentives and other forms of compensation for officers and
+employees. The Compensation Committee also administers our incentive
+compensation plan. The Compensation Committee’s charter is available
+on the Company’s website at www.chembio.com. The Compensation
+Committee does not currently delegate its authority to any other party, and does
+not currently engage any compensation consultants to determine the amount or
+form of executive and director compensation. Executive officers do
+not play a role in the determination or recommendation of the form or amount of
+any executive compensation paid. 
+The
+Company’s Nominating and Corporate Governance committee met once in 2008 and
+currently consists of Katherine L. Davis (Chairperson) and Dr. Gary
+Meller. Each of the committee’s members is “independent” as that term
+is defined in Rule 4200(a)(15) of the Nasdaq Stock Market. The
+committee (i) identifies individuals qualified to become members of the
+Board of Directors, (ii) recommends director candidates to the Company’s
+Board of Directors, (iii) develops, updates as necessary, and recommends to
+the Company’s Board of Directors corporate governance principles and policies,
+and (iv) monitors compliance with such principles and
+policies. The committee’s charter is available on the Company’s
+website at www.chembio.com. All the nominees for director included in
+this proxy statement were recommended by the Nominating Committee, which is
+comprised entirely of non-management directors. 
+- 9
+- 
+To be
+considered for nomination by the Board at the next annual meeting of
+stockholders, the nominations must be made by stockholders of record entitled to
+vote. Stockholder nominations must be made by notice in writing,
+delivered or mailed by first class U.S. mail, postage prepaid, to the Secretary
+of the Company at the Company’s principal business address, not less than 60
+days nor more than 90 days prior to any meeting of the stockholders at which
+directors are to be elected. Each notice of nomination of directors
+by a stockholder shall set forth the nominee’s name, age, business address, if
+known, residence address of each nominee proposed in that notice, the principal
+occupation or employment of each nominee for the five years preceding the date
+of the notice, the number of shares of the Company’s common stock beneficially
+owned by each nominee and any arrangement, affiliation, association, agreement
+or other relationship of the nominee with any Company stockholder. 
+Stockholders
+wishing to send communications to the Board may contact Lawrence Siebert, our
+CEO, President and Chairman, at the Company’s principal executive office
+address. All such communications shall be shared with the members of
+the Board, or if applicable, a specified committee or director. 
+Audit
+Committee Report 
+This
+report shall not be deemed incorporated by reference by any general statement
+incorporating by reference this Proxy Statement into any filing under the
+Securities Act of 1933 or the Securities Exchange Act of 1934, except to the
+extent that we specifically incorporate this information by reference, and shall
+not otherwise be deemed filed under either of such Acts. 
+The Audit
+Committee oversees the Company’s financial reporting
+process. Management has the primary responsibility for the financial
+statements and the reporting process, including the systems of internal
+controls. In fulfilling its oversight responsibilities, the committee
+reviewed and discussed with management the audited financial statements in the
+Company’s Annual Report on Form 10-K for the year ended December 31, 2008 and
+the unaudited financial statements included in the Quarterly Reports on Form
+10-Q for the first three quarters of the fiscal year ended December 31,
+2008. 
+The
+committee discussed with the independent auditors, who are responsible for
+expressing an opinion on the conformity of audited financial statements with
+generally accepted accounting principles, the auditors’ judgments as to the
+quality, not just the acceptability, of the Company’s accounting principles and
+such other matters as are required to be discussed by the auditors with the
+committee under Statement on Auditing Standard No. 61, as amended. In
+addition, the committee discussed with the independent auditors the auditors’
+independence from management and the Company, including the matters in the
+written disclosures and the letter required by the Independence Standards Board
+Standard No. 1. The committee considered whether the auditors’
+providing services on behalf of the Company other than audit services is
+compatible with maintaining the auditors’ independence. 
+The
+committee discussed with the Company’s independent auditors the overall scope
+and plans for their respective audits. The committee will meet with
+the independent auditors, with and without management present, to discuss the
+results of the auditors’ examinations, their evaluations of the Company’s
+internal controls, and the overall quality of the Company’s financial
+reporting. 
+In
+reliance on the reviews and discussions referred to above, the committee
+approved inclusion of the audited financial statements in
+the Annual Report on Form 10-K for the year ended December 31, 2008 for
+filing with the SEC. 
+The Audit
+Committee 
+Katherine
+Davis (Chairperson) 
+Dr. Gary
+Meller 
+March 18,
+2009 
+- 10
+- 
+EXECUTIVE
+COMPENSATION 
+The
+following table summarizes all compensation recorded by the Company in each of
+the last two completed fiscal years for our principal executive officer, our two
+most highly compensated executive officers other than our principal executive
+officer whose annual compensation exceeded $100,000, and two additional
+individuals for whom disclosure would have been made in this table but for the
+fact that the individual was not serving as an executive officer of our company
+at December 31, 2008. 
+Name
+/ 
+Principal 
+Position 
+Year 
+Salary 1 
+($) 
+Bonus 2 
+($) 
+Option
+Awards 3 
+($) 
+Stock 
+Awards 
+($) 
+All
+Other Compensation 5 
+($) 
+Total 
+($) 
+Lawrence
+A. Siebert 4 
+2008 
+$ 
+265,000 
+$ 
+26,000 
+$ 
+36,695 
+$ 
+- 
+$ 
+8,267 
+$ 
+335,962 
+CEO 
+2007 
+243,135 
+26,000 
+- 
+- 
+9,314 
+278,448 
+Richard
+J. Larkin 
+2008 
+$ 
+163,076 
+$ 
+15,000 
+$ 
+12,193 
+$ 
+- 
+$ 
+1,781 
+$ 
+192,050 
+CFO 
+2007 
+153,654 
+15,000 
+- 
+- 
+1,304 
+169,958 
+Javan
+Esfandiari 
+2008 
+$ 
+215,692 
+$ 
+16,000 
+$ 
+45,297 
+$ 
+28,702 
+$ 
+5,872 
+$ 
+311,564 
+VP-R&D 
+2007 
+171,192 
+21,000 
+99,993 
+89,850 
+5,510 
+387,546 
+Tom
+Ippolito 
+2008 
+$ 
+173,631 
+$ 
+12,000 
+$ 
+8,129 
+$ 
+- 
+$ 
+1,708 
+$ 
+195,467 
+VP-Regulatory 
+2007 
+152,481 
+12,000 
+- 
+381 
+164,862 
+Richard
+Bruce 
+2008 
+$ 
+151,923 
+$ 
+12,000 
+$ 
+8,129 
+$ 
+- 
+$ 
+933 
+$ 
+172,984 
+VP-Operations 
+2007 
+140,654 
+12,000 
+- 
+990 
+153,644 
+1 Salary
+is total base salary. 
+2 Any
+bonus earned was paid on a discretionary basis. 
+3 The
+estimated fair value of any option or common stock granted was determined at the
+date of grant by using the Black-Scholes option pricing model. 
+4 Mr.
+Siebert also serves as a director on the Company’s board of
+directors. Mr. Siebert does not receive any compensation for this
+director role. 
+5 Other
+compensation includes an employer match to 401(K) contributions and a car
+allowances where applicable. 
+- 11
+- 
+Employment
+Agreements 
+Mr.
+Siebert. On
+June 3, 2008, the Company’s Board of Directors approved the Company’s extension
+of the June 15, 2006 employment agreement (the “Employment Agreement”) with
+Lawrence A. Siebert, the Company’s President and Chief Executive Officer, for an
+additional one-year term, effective May 11, 2008. On June 15, 2006,
+Mr. Siebert and the Company entered into an Employment Agreement, effective
+May 10, 2006, which was to terminate on May 10, 2008. Pursuant
+to the Employment Agreement, Mr. Siebert serves as the President and Chief
+Executive Officer of the Company and received an initial salary of $240,000 per
+year, which had been increased to $265,000 per year until Mr. Siebert agreed to
+a 15 percent reduction, to $225,000, effective January 19, 2009. Mr.
+Siebert also is eligible for a bonus of up to 50% of his salary, consisting of
+(i) a bonus of up to 25% of his salary that is at the complete discretion and
+determination of the board of directors, and (ii) a bonus of up to an additional
+25% of his salary that will be determined based upon revenue and earnings
+performance criteria established each year by the board of
+directors. Mr. Siebert is eligible to participate in any profit
+sharing, stock option, retirement plan, medical and/or hospitalization plan,
+and/or other benefit plans except for disability and life insurance that the
+Company may from time to time place in effect for the Company’s executives
+during the term of Mr. Siebert’s employment agreement. If Mr.
+Siebert’s Employment Agreement is terminated by the Company without cause, or if
+Mr. Siebert terminates his Employment Agreement for a reasonable basis,
+including within 12 months of a change in control, the Company is required to
+pay as severance Mr. Siebert’s salary for six months. Mr. Siebert has
+agreed for a period of two years after the termination of his employment with
+the Company not to induce customers, agents, or other sources of distribution of
+the Company’s business under contract or doing business with the Company to
+terminate, reduce, alter, or divert business with or from the
+Company. The terms of the extended May 1, 2008 Employment
+Agreement are identical to the June 15, 2006 Employment Agreement, except that
+under the extended Employment Agreement, Mr. Siebert received additional
+consideration in the form of incentive stock options to purchase 250,000 shares
+of the Company’s common stock exercisable at $0.13 per share, which was the
+closing price of the Company's common stock on June 3, 2008, the date on which
+the agreement was entered into . The incentive stock
+options are immediately exercisable and they expire on June 3,
+2013. 
+Mr. Esfandiari. The Company entered into
+an employment agreement dated April 23, 2007, and to be effective March 5, 2007
+(the "Employment Agreement"), with Mr. Esfandiari to continue as the Company's
+Senior Vice President of Research and Development for an additional term of
+three years. Mr. Esfandiari's salary under the Employment Agreement
+is $185,000 for the first year, $210,000 for the second year, and $235,000 for
+the final year. Mr. Esfandiari is eligible for a cash bonus of up to
+50% of his base salary for each respective year, consisting of (i) a cash bonus
+of up to 37.5% of his calendar year base salary based on the performance of the
+Company's Dual Path Platform Technology, which is directly related to certain
+annual revenue targets budgeted by management of the Company, and (ii) a cash
+bonus of up to 12.5% of his calendar year base salary that is at the complete
+discretion and determination of the board of directors. The Company
+also granted Mr. Esfandiari a stock grant of 200,000 shares of the Company's
+common stock. 100,000 shares vested when the employment agreement was executed,
+50,000 shares vested on the first anniversary date of the Employment Agreement,
+and 50,000 shares vested on the second anniversary of the Employment Agreement.
+In addition, although none were granted, the Employment Agreement provided that
+Mr. Esfandiari could have been granted up to 50,000 shares of the Company's
+common stock for 2007 and 2008 based upon the performance of the Company's Dual
+Path Platform Technology, which is directly related to certain annual revenue
+targets budgeted by management of the Company. Pursuant to the
+Company's 1999 Stock Option Plan, the Company also granted Mr. Esfandiari
+incentive stock options to purchase 300,000 shares of the Company's common
+stock. The price per share of these options is equal to the fair market value of
+the Company's common stock on April 23, 2007, which is the date on which the
+Agreement was entered into. 100,000 shares of the stock options vested when the
+employment agreement was executed, 100,000 shares of the stock options vested on
+the first anniversary of the Employment Agreement, and 100,000 shares of the
+stock options vested on the second anniversary of the Employment
+Agreement. Mr. Esfandiari is eligible to participate in any profit
+sharing, stock option, retirement plan, medical and/or hospitalization plan,
+and/or other benefit plans except for disability and life insurance that the
+Company may from time to time place in effect for the Company’s executives
+during the term of Mr. Esfandiari’s employment agreement. If Mr.
+Esfandiari’s employment agreement is terminated by the Company without cause, or
+if Mr. Esfandiari terminates his employment agreement for a reasonable basis, as
+defined in the Employment Agreement including within 12 months of a change in
+control, the Company is required to pay as severance Mr. Esfandiari’s salary for
+twelve months. 
+Neither
+Mr. Larkin, Mr. Ippolito nor Mr. Bruce has an employment contract with the
+Company. 
+- 12
+- 
+OUTSTANDING
+EQUITY AWARDS AT FISCAL YEAR-END 2008 
+Name 
+Number
+of Securities Underlying Unexcercised Options Excerciseable
+(#) 
+Number
+of Securities Underlying Unexcercised Options Unexcersable 
+(#) 
+Option
+Exercise Price 
+($) 
+Option
+Expiration Date 
+Option
+Vesting Date 
+Number
+of Shares of Stock That Have Not Vest 
+(#) 
+Market
+Value of Shares of Stock That Have Not Vested 
+($) 
+Foot- 
+note 
+Lawrence
+A. Siebert 
+250,000 
+0.13 
+6/3/2013 
+6/3/2008 
+5 
+75,000 
+0.22 
+2/15/2013 
+2/15/2008 
+1 
+10,000 
+0.48 
+12/31/2008 
+4/17/2006 
+3,
+4 
+10,000 
+0.48 
+5/4/2011 
+4/17/2006 
+3,
+4 
+50,000 
+0.48 
+5/28/2011 
+4/17/2006 
+2,
+4 
+50,000 
+0.48 
+5/28/2011 
+1/1/2007 
+2,
+4 
+50,000 
+0.48 
+5/4/2011 
+5/5/2004 
+3,
+4 
+Richard
+J. Larkin 
+75,000 
+0.22 
+2/15/2013 
+2/15/2008 
+1 
+25,000 
+0.48 
+5/17/2010 
+4/17/2006 
+3,
+4 
+25,000 
+0.48 
+5/17/2010 
+1/1/2007 
+3,
+4 
+18,750 
+0.48 
+3/24/2011 
+3/24/2006 
+3,
+4 
+18,750 
+0.48 
+3/24/2011 
+1/1/2007 
+3,
+4 
+50,000 
+0.45 
+9/15/2010 
+5/5/2004 
+3 
+Javan
+Esfandiari 
+60,000 
+0.22 
+2/15/2013 
+2/15/2008 
+1 
+5,000 
+0.48 
+12/31/2008 
+4/17/2006 
+3,
+4 
+25,000 
+0.48 
+5/17/2010 
+4/17/2006 
+3,
+4 
+25,000 
+0.48 
+5/17/2010 
+1/1/2007 
+3,
+4 
+18,750 
+0.48 
+3/24/2011 
+3/24/2006 
+3,
+4 
+18,750 
+0.48 
+3/24/2011 
+1/1/2007 
+3,
+4 
+5,000 
+0.48 
+5/4/2011 
+4/17/2006 
+3,
+4 
+25,000 
+0.48 
+5/28/2011 
+4/17/2006 
+2,
+4 
+25,000 
+0.48 
+5/28/2011 
+4/17/2006 
+2,
+4 
+25,000 
+0.48 
+5/28/2011 
+5/28/2007 
+2,
+4 
+30,000 
+0.48 
+5/4/2011 
+5/5/2004 
+3,
+4 
+100,000 
+0.48 
+4/23/2012 
+4/23/2007 
+2,
+4 
+100,000 
+0.48 
+4/23/2012 
+3/5/2008 
+2,
+4 
+100,000 
+0.48 
+4/23/2012 
+3/5/2009 
+2,
+4 
+50,000 
+5,500 
+5 
+Tom
+Ippolito 
+50,000 
+0.22 
+2/15/2013 
+2/15/2008 
+1 
+15,000 
+0.48 
+3/24/2011 
+3/24/2006 
+3,
+4 
+Richard
+Bruce 
+50,000 
+0.22 
+2/15/2013 
+2/15/2008 
+1 
+5,000 
+0.48 
+12/31/2008 
+4/17/2006 
+3,
+4 
+12,500 
+0.48 
+5/17/2010 
+4/17/2006 
+3,
+4 
+12,500 
+0.48 
+5/17/2010 
+1/1/2007 
+3,
+4 
+12,500 
+0.48 
+3/24/2011 
+3/24/2006 
+3,
+4 
+12,500 
+0.48 
+3/24/2011 
+1/1/2007 
+3,
+4 
+5,000 
+0.48 
+5/4/2011 
+4/17/2006 
+3,
+4 
+10,000 
+0.48 
+5/4/2011 
+5/5/2004 
+3,
+4 
+20,000 
+0.48 
+5/4/2011 
+5/5/2004 
+3,
+4 
+1 These
+options were issued during 2008 as part of the Company’s 1999 Stock Option
+Plan. 
+2
+Stock/Options issued in connection with an employment contract and under the
+1999 Stock Incentive Plan. 
+3 All
+other options shown were issued prior to 2008 as part of the Company's 1999
+Stock Option Plan. 
+4 On
+February 15, 2008, the Company’s Compensation Committee approved the reduction
+of the exercise price to $0.48 per share of each employee stock option award
+issued under the 1999 Stock Option Plan for which the exercise price was greater
+than $0.48 per share. 
+5 Options
+issued in connection with an employment contract and under the 2008 Stock
+Incentive Plan. 
+- 13
+- 
+DIRECTOR
+COMPENSATION 
+Name 
+Fees
+Earned or Paid in Cash 
+($) 1 
+Option
+Awards 
+($) 2 
+Total 
+($) 
+Katherine
+L. Davis 
+$ 
+25,750 
+$ 
+22,987 
+$ 
+48,737 
+Gary
+Meller 
+24,250 
+23,316 
+47,566 
+James
+D. Merselis 
+20,500 
+7,816 
+28,316 
+Al
+Carus 
+14,750 
+23,635 
+38,385 
+1 Fees
+earned or paid in cash represents an annual retainer and fees for meeting
+expenses: (a) Mr. Carus received $9,000 in an annual retainer for the portion of
+the year that he served as a member of the board of directors, a $1,250 annual
+retainer as audit committee chairman and $4,500 in meeting fees paid during
+2008; (b) Mr. Merselis received an $18,000 annual retainer as a
+member of the board of directors, and $2,500 in meeting fees paid during 2008;
+(c) Dr. Meller received an $18,000 annual retainer as a member of the board of
+directors, and $6,250 in meeting fees; (d) Ms. Davis received an $18,000 annual
+retainer as a member of the board of directors, a $1,250 retainer as
+audit committee chairman and $6,500 in meeting fees. 
+2 Each
+outside member of the board of directors is granted an option to purchase
+180,000 shares of the company’s common stock with an exercise price equal to the
+market price on the date of the grant as part of their annual compensation.
+One-fifth of these options are exercisable on the date of grant, one-fifth
+become exercisable on the first anniversary of the date of grant, and additional
+one-fifths become exercisable on the second through fourth anniversary of the
+date of grant. The fair value of options at the date of grant was
+estimated using the Black-Scholes option pricing model. 
+3 Mr.
+Merselis resigned from our Board of Directors on February 9, 2009. 
+4 Mr.
+Carus resigned from our Board of Directors on July 20, 2008. 
+Director
+Compensation 
+All
+non-employee directors are paid an $18,000 annual retainer, semi-annually, and
+once every five years stock options to acquire 180,000 shares of the Company's
+common stock, with an exercise price equal to the market price on the date of
+the grant. Stock options to acquire 36,000 shares become exercisable
+on the date of grant, and options to acquire an additional 36,000 shares become
+exercisable on the date of each of the four succeeding annual meetings of
+stockholders if and to the extent that the non-employee director is reelected as
+a director at each such annual meeting. If a person becomes a member
+of the Board at a time other than at an annual meeting, then that person is
+granted options to purchase that number of shares of common stock that
+is the same percentage of 36,000 that the number of days remaining until
+the one-year anniversary of the most recent annual meeting of stockholders is of
+365. The audit committee chairman is paid an annual retainer of
+$2,500, paid semi-annually. In addition, the non-employee directors
+are paid $1,000 in cash for each board of directors' meeting attended, and paid
+$500 in cash for each telephonic board of directors meeting. The
+non-employee directors who are members of a committee of the board of directors
+are paid $500 in cash for each committee meeting attended, or $750 in cash for
+each committee meeting attended if that non-employee director is the committee
+chairman. The Company and the Board of Directors may change the
+compensation paid to the members of the Board at any time. 
+- 14
+- 
+ITEM
+2. PROPOSAL TO RATIFY THE SELECTION OF PARENTE RANDOLPH,
+LLC 
+AS
+CERTIFIED INDEPENDENT ACCOUNTANTS 
+As
+disclosed in the Company's Amendment No. 2 to Form 8-K/A filed with the SEC on
+March 3, 2009, the practice of Lazar Levine & Felix LLP (“Lazar”) was
+acquired on February 15, 2009 by Parente Randolph, LLC (“Parente”) in a
+transaction pursuant to which Lazar merged its operations into Parente and
+certain of the professional staff and partners of Lazar joined Parente either as
+employees or principals of Parente. On February 19, 2009, as a result
+of this transaction, Lazar resigned from its role as principal auditor of the
+Company’s financial statements. The Company, through and with the
+approval of the Audit Committee of the Company’s Board of Directors, engaged
+Parente of New York, New York as its independent registered public accounting
+firm to serve as the Company's certified independent accountants to audit the
+Company's financial statements for the fiscal year ending December 31,
+2008. 
+Lazar’s
+reports regarding the Company’s financial statements for the fiscal years ended
+December 31, 2007 and 2006 did not contain any adverse opinion or disclaimer of
+opinion and were not qualified or modified as to uncertainty, audit scope or
+accounting principles. During the years ended December 31, 2008 and
+2007, and during the interim period from the end of the most recently completed
+fiscal year through February 19, 2009, the date of resignation, there were no
+disagreements with Lazar on any matter of accounting principles or practices,
+financial statement disclosure or auditing scope or procedures, which
+disagreements, if not resolved to the satisfaction of Lazar would have caused it
+to make reference to such disagreement in its reports. 
+During
+the years ended December 31, 2008 and 2007, and during the interim period from
+the end of the most recently completed fiscal year through February 19, 2009,
+the date of engagement, the Company did not consult with Parente regarding the
+application of accounting principles to a specified transaction, either
+completed or proposed, or the type of audit opinions that might be rendered by
+Parente on the Company’s financial statements. Parente did not
+provide the Company a written report or any oral advice that was an important
+factor considered by the Company in reaching a decision as to any accounting,
+auditing or financial reporting issue. 
+In
+addition, during the years ended December 31, 2008 and 2007, and during the
+interim period from the end of the most recently completed fiscal year through
+February 19, 2009, the date of engagement, the Company did not consult with
+Parente on any matter that was either the subject of a disagreement (as defined
+in Item 304(a)(1)(iv) of Regulation S-K and the related instructions to this
+item) or a reportable event (as described in Item304(a)(1)(v) of Regulation
+S-K). As such none of the required disclosures under Item
+304(a)(2)(ii) apply. 
+It is
+expected that one or more representatives of Parente will be present at the
+Annual Meeting and will be given the opportunity to make a statement and to
+respond to appropriate questions from stockholders. 
+Principal
+Accountant Fees and Services 
+All fees
+discussed below were paid to Lazar Levine & Felix LLP. Remaining
+fees for the December 31, 2008 audit will be paid in 2009 to Parente Randolph,
+LLC. In February 2009, Lazar Levine & Felix LLP merged its
+practice into Parente Randolph, LLC. 
+Audit
+Fees 
+For the
+years ended December 31, 2008 and 2007, the Company’s independent accounting
+firm billed the Company $136,000 and $119,000, respectively, for fees for the
+audit of the Company’s annual financial statements and review of financial
+statements included in the Company’s Forms 10-Q and 10-K. 
+Audit-Related
+Fees 
+For the
+years ended December 31, 2008 and 2007, the independent accounting firm, did not
+provide the Company with any assurance and related services reasonably related
+to the performance of the audit or review of the Company’s financial statements
+that are not reported above under “Audit Fees.” 
+- 15
+- 
+Tax
+Fees 
+For the
+years ended December 31, 2008 and 2007, the independent accounting firm billed
+the Company $13,500 and $10,000, respectively, for professional services for tax
+compliance, tax advice and tax planning. 
+All
+Other Fees 
+For the
+years ended December 31, 2008 and 2007, the independent accounting firm billed
+the Company $2,500 and $8,500 for fees associated with the preparation and
+filing of the Company’s registration statements, responses to SEC comment
+letters and other related matters. 
+Audit
+Committee Pre-Approval Policies 
+The Audit
+Committee approves in advance all audit and non-audit services performed by the independent
+accounting firm. There are no other specific
+policies or procedures relating to the pre-approval of services performed
+by the independent accounting firm. 
+Required
+Vote; Board Recommendation 
+An
+affirmative vote of the majority of shares represented at the Annual Meeting in
+person or by proxy is necessary to ratify the selection of
+auditors. There is no legal requirement for submitting this proposal
+to the stockholders; however, the Board of Directors believes that it is of
+sufficient importance to seek ratification. Whether the proposal is
+approved or defeated, the Board may reconsider its selection of
+Parente. 
+The
+Board of Directors unanimously recommends that the stockholders vote FOR
+ratifying the selection of the certified public accounting firm of Parente
+Randolph, LLC to serve as the Company’s certified independent accountants for
+the fiscal year ending December 31, 2009 or until the Board of Directors, in its
+discretion, replaces them. 
+RESOLUTIONS
+PROPOSED BY INDIVIDUAL STOCKHOLDERS; 
+DISCRETIONARY
+AUTHORITY TO VOTE PROXIES 
+Under
+Rule 14a-8(e) of the Securities Exchange Act of 1934, in order to be considered
+for inclusion in the proxy statement and form of proxy relating to our next
+annual meeting of stockholders following the end of our 2009 fiscal year,
+proposals by individual stockholders must be received by us no later than December 18 , 2009. 
+In
+addition, under Rule 14a-4(c)(1) of the Securities Exchange Act, the proxy
+solicited by the Board of Directors for the next annual meeting of stockholders
+following the end of our 2009 fiscal year will confer discretionary authority on
+any stockholder proposal presented at that meeting unless we are provided with
+notice of that proposal no later than March 2, 2010. 
+OTHER
+BUSINESS 
+The Board
+of Directors is not aware of any other matters that are to be presented at the
+Annual Meeting, and it has not been advised that any other person will present
+any other matters for consideration at the meeting. Nevertheless, if
+other matters should properly come before the Annual Meeting, the stockholders
+present, or the persons, if any, authorized by a valid proxy to vote on their
+behalf, shall vote on such matters in accordance with their
+judgment. 
+* * * *
+* 
+This
+Notice and Proxy statement are sent by order of the Board of
+Directors. 
+Dated: April
+14,
+2009 /s/ Lawrence A.
+Siebert 
+Lawrence A. Siebert, President, Chief
+Executive Officer 
+and Chairman of the
+Board 
+* * * *
+* 
+- 16
+- 
+PROXY PROXY 
+CHEMBIO
+DIAGNOSTICS, INC. 
+For the
+Annual Meeting of Stockholders on June 3, 2009 
+Proxy
+Solicited on Behalf of the Board of Directors 
+The
+undersigned hereby appoints Lawrence A. Siebert, Richard Larkin, or either of
+them, as proxies with full power of substitution to vote all the shares of the
+undersigned with all of the powers which the undersigned would possess if
+personally present at the Annual Meeting of Stockholders of Chembio Diagnostics,
+Inc. (the “Corporation”) to be held at 10:00 a.m. (local time) on June 3, 2009,
+at Chembio, 3661 Horseblock Road, Medford, New York 11763, or any adjournments
+thereof, on the following matters: 
+[X]
+Please mark votes as in this example. 
+1. To
+elect the following three directors: 
+Nominees: Katherine
+L. Davis, Dr. Gary Meller and Lawrence A.
+Siebert. 
+FOR ALL NOMINEES [ ] 
+WITHHELD AUTHORITY FOR ALL NOMINEES [
+] 
+FOR ALL NOMINEES EXCEPT AS NOTED ABOVE
+[ ] 
+2. To
+ratify the selection of Parente Randolph, LLC as the Corporation’s certified
+independent accountants. 
+[ ]
+FOR [
+]
+AGAINST [
+] ABSTAIN 
+3. In
+their discretion, to vote upon an adjournment or postponement of the
+meeting. 
+[ ]
+YES [
+]
+NO [
+] ABSTAIN 
+4. In
+their discretion, to vote upon such other business as may properly come
+before the meeting. 
+[ ]
+YES [
+]
+NO [
+] ABSTAIN 
+(Continued
+and to be signed on the reverse side) 
+PC-1 
+Unless contrary instructions are given,
+the shares represented by this proxy will be voted in favor of Items 1, 2, 3 and
+4. This proxy is solicited on behalf of the Board of Directors of
+Chembio Diagnostics, Inc. 
+EVEN IF
+YOU PLAN TO ATTEND THE MEETING, PLEASE COMPLETE, DATE, SIGN AND RETURN THIS
+PROXY IN THE ACCOMPANYING ENVELOPE. 
+MARK HERE
+FOR ADDRESS CHANGE AND NOTE
+BELOW [
+] 
+Number of voting
+shares: 
+Dated: ____________________________________ 
+Signature: ____________________________________ 
+Signature: ____________________________________ 
+Signature if held
+jointly 
+(Please
+sign exactly as shown on your stock certificate and on the envelope in which
+this proxy was mailed. When signing as partner, corporate officer,
+attorney, executor, administrator, trustee, guardian, etc., give full title as
+such and sign your own name as well. If stock is held jointly, each
+join owner should sign.) 
+PC-2
\ No newline at end of file
diff --git a/raw/proxies/0001092662/0001092662-09-000053/proxy_rpt.txt b/raw/proxies/0001092662/0001092662-09-000053/proxy_rpt.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/proxies/0001092662/0001092662-10-000036/proxy.txt b/raw/proxies/0001092662/0001092662-10-000036/proxy.txt
new file mode 100644
index 0000000000000000000000000000000000000000..b2571402357ffdf004038c55fc5de0f85e26d97b
--- /dev/null
+++ b/raw/proxies/0001092662/0001092662-10-000036/proxy.txt
@@ -0,0 +1,627 @@
+DEF 14A
+1
+proxy_def14a.htm
+2010 PROXY
+proxy_def14a.htm 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+SCHEDULE 14A INFORMATION 
+Proxy Statement Pursuant to Section 14(a) of the Securities Exchange Act of 1934 
+Filed by the Registrant [X] 
+Filed by a Party other than the Registrant [_] 
+Check the appropriate box: 
+[ ] Preliminary Proxy Statement 
+[_] Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2)) 
+[X] Definitive Proxy Statement 
+[_] Definitive Additional Materials 
+[_] Soliciting Material under Rule 14a-12 
+CHEMBIO DIAGNOSTICS, INC. 
+---------------------------------------------- 
+(Name of Registrant as Specified in Its Charter) 
+Not Applicable 
+----------------------------------------------------------------- 
+(Name of Person(s) Filing Proxy Statement, if other than the Registrant) 
+Payment of Filing Fee (Check the appropriate box): 
+[X] No fee required. 
+[_] Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11. 
+1. 
+Title of each class of securities to which transaction applies: 
+2. 
+Aggregate number of securities to which transaction applies: 
+3. 
+Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined): 
+4. 
+Proposed maximum aggregate value of transaction: 
+5. 
+Total fee paid: 
+[_] Fee paid previously with preliminary materials. 
+[_] Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing. 
+1. 
+Amount Previously Paid: 
+2. 
+Form, Schedule or Registration Statement No.: 
+3. 
+Filing Party: 
+4. 
+Date Filed: 
+CHEMBIO DIAGNOSTICS, INC. 
+3661 Horseblock Road 
+Medford, NY 11763 
+(631) 924-1135 
+NOTICE OF ANNUAL MEETING OF STOCKHOLDERS 
+To be held June 2, 2010 
+The Annual Meeting of Stockholders of Chembio Diagnostics, Inc. will be held on June 2, 2010 at 10:30 am (local time) at Chembio, 3661 Horseblock Road, Medford, New York 11763, for the following purposes: 
+1. 
+To elect three directors to the Company’s Board of Directors; 
+2. 
+To consider and vote upon a proposal recommended by the Board of Directors to ratify the selection of ParenteBeard LLC to serve as our certified independent accountants for the fiscal year ending December 31, 2010; 
+3. 
+To, in their discretion, vote upon an adjournment or postponement of the meeting; and 
+4. To transact any other business that properly may come before the Annual Meeting. 
+Only the stockholders of record as shown on our transfer books at the close of business on April 9, 2010 are entitled to notice of, and to vote at, the Annual Meeting. Our Annual Report for the fiscal year ended December 31, 2009 on Form 10-K is being provided to stockholders with this proxy statement. The Annual Report is not part of the proxy soliciting material. 
+All stockholders, regardless of whether they expect to attend the meeting in person, are requested to complete, date, sign and return promptly the enclosed form of proxy via the Internet or in the accompanying envelope (which requires no postage if mailed in the United States), as applicable. The person executing the proxy may revoke it by filing with our Secretary an instrument of revocation or a duly executed proxy bearing a later date, or by electing to vote in person at the Annual Meeting. 
+Important Notice regarding the Availability of Proxy Materials for the Stockholder Meeting to Be Held on June 2, 2010: The Proxy Statement and Annual Report to Stockholders for the fiscal year ended December 31, 2009 are available free of charge at http://phx.corporate-ir.net/phoenix.zhtml?c=121584&p=proxy. 
+All stockholders are extended a cordial invitation to attend the Annual Meeting. 
+By the Board of Directors 
+/s/ Lawrence A. Siebert 
+Medford, New York Lawrence A. Siebert 
+April 16, 2010 Chairman and Chief Executive Officer 
+PROXY STATEMENT 
+CHEMBIO DIAGNOSTICS, INC. 
+3661 Horseblock Road 
+Medford, NY 11763 
+(631) 924-1135 
+ANNUAL MEETING OF STOCKHOLDERS 
+To be held June 2, 2010 
+SOLICITATION AND REVOCATION OF PROXIES 
+This proxy statement is provided in connection with the solicitation of proxies by and on behalf of the Board of Directors of Chembio Diagnostics, Inc., a Nevada corporation (referred to as the “Company” or “Chembio” or “we” or “us”), to be voted at the Annual Meeting of Stockholders to be held at 10:30 am (local time) on June 2, 2010 at Chembio, 3661 Horseblock Road, Medford, New York 11763, or at any adjournment or postponement of the Annual Meeting. We anticipate that this proxy statement and the accompanying form of proxy will be first made available to stockholders on or about April 19, 2010. 
+In accordance with rules and regulations recently adopted by the SEC, we are furnishing proxy materials to our stockholders of record by (i) mailing a printed copy of the proxy materials, and (ii) providing Internet access to the proxy materials at http://phx.corporate-ir.net/phoenix.zhtml?c=121584&p=proxy. Both stockholders of record who receive a printed copy of proxy materials and stockholders of record who receive a Notice of Internet Availability of Proxy Materials will be permitted to access our proxy materials on the Internet. In addition, stockholders of record who receive a Notice of Internet Availability of Proxy Materials can receive a printed copy of the proxy materials by requesting this information from the Company. The Notice of Internet Availability of Proxy Materials will instruct you as to how you may access and review all of the important information contained in the proxy materials. The Notice of Internet Availability of Proxy Materials also instructs you as to how you may submit your proxy on the Internet. 
+A stockholder giving a proxy may revoke it at any time before it is exercised by delivering written notice of revocation to our Secretary, by substituting a new proxy executed at a later date, or by requesting, in person at the Annual Meeting, that the proxy be returned. 
+The solicitation of proxies is to be made on the Internet and through mailings. However, following the initial solicitation, further solicitations may be made by telephone or oral communication with stockholders. Our officers, directors and employees may solicit proxies, but these persons will not receive compensation for that solicitation other than their regular compensation as employees. Arrangements also will be made with brokerage houses and other custodians, nominees and fiduciaries to provide access to the solicitation materials to beneficial owners of the shares held of record by those persons. We may reimburse those persons for reasonable out-of-pocket expenses incurred by them in so doing. We will pay all expenses involved in preparing, assembling and mailing this proxy statement and the enclosed material. 
+VOTING SECURITIES 
+The close of business on April 9, 2010 has been fixed as the record date for the determination of holders of record of the Company’s common stock, $0.01 par value per share, entitled to notice of and to vote at the Annual Meeting. On the record date, 61,996,651 shares of common stock were outstanding and eligible to be voted at the Annual Meeting. A majority of the issued and outstanding shares of common stock entitled to vote, represented either in person or by proxy, constitutes a quorum at any meeting of the stockholders. If sufficient votes for approval of the matters to be considered at the Annual Meeting have not been received prior to the meeting date, we intend to postpone or adjourn the Annual Meeting in order to solicit additional votes. The form of proxy we are soliciting requests authority for the proxies, in their discretion, to vote the stockholders’ shares with respect to a postponement or adjournment of the Annual Meeting. At any postponed or adjourned meeting, we will vote any proxies received in the same manner described in this proxy statement with respect to the original meeting. 
+VOTING PROCEDURES 
+Votes at the Annual Meeting are counted by an inspector of election appointed by the Chairman of the meeting. You can ensure that your shares are voted at the meeting by submitting your proxy card on the Internet, or by completing, signing, dating and returning the enclosed proxy form in the envelope provided. If a quorum is present, unless a different number of votes is required by Nevada law or our Articles Of Incorporation, an affirmative vote of a majority of the votes entitled to be cast by those present in person or by proxy is required for the approval of the items submitted to shareholders for their consideration, except for the election of our directors, for which a plurality of the votes cast is required. Abstentions by those present at the Annual Meeting are tabulated separately from affirmative and negative votes and do not constitute affirmative votes. If a shareholder submits his or her proxy card and withholds authority to vote for any or all of the items, the votes represented by the proxy card will be deemed to be present at the meeting for purposes of determining the presence of a quorum but will not be counted as affirmative votes. Rule 452 of the New York Stock Exchange (NYSE), which governs all brokers, permits brokers to vote their customers’ stock held in street name on routine matters when the brokers have not received voting instructions from their customers. The NYSE does not, however, allow brokers to vote their customers’ stock held in street name on non-routine matters unless they have received voting instructions from their customers. In such cases, the uninstructed shares for which the broker is unable to vote are called broker non-votes. The ratification of the independent auditor is a routine matter on which brokers may vote in their discretion on behalf of customers who have not provided voting instructions. The election of directors is a non-routine matter on which brokers are not allowed to vote unless they have received voting instructions from their customers. Due to recent rule changes by the NYSE, your broker will no longer be allowed to vote your shares on the election of directors without your specific instructions. Shares in the names of brokers that are not voted on a particular matter are treated as not present with respect to that matter. 
+We will announce voting results at the meeting, and we will publish the final results within four business days following the meeting on a Current Report on Form 8-K. 
+FORWARD-LOOKING STATEMENTS 
+This proxy statement includes “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts included in this proxy statement regarding our financial position, business strategy and plans and objectives of management for future operations and capital expenditures are forward-looking statements. Although we believe that the expectations reflected in the forward-looking statements and the assumptions upon which the forward-looking statements are based are reasonable, we can give no assurance that such expectations and assumptions will prove to have been correct. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 
+On April 9, 2010, there were 61,996,651 shares of common stock issued and outstanding and eligible to be voted at the Annual Meeting. The following table sets forth certain information regarding the beneficial ownership of our common stock by each person or entity known by us to be the beneficial owner of more than 5% of the outstanding shares of common stock, each of our directors and each of our “named executive officers” and all of our directors 
+Name and Address of Beneficial Owner 
+Amount and Nature of Beneficial Owner 
+Percent of Class 
+Siebert, Lawrence (1) 
+3661 Horseblock Road 
+Medford, NY 11763 
+7,066,948 
+11.29 
+% 
+Esfandiari, Javan (2) 
+3661 Horseblock Road 
+Medford, NY 11763 
+977,573 
+1.56 
+% 
+Larkin, Richard (3) 
+3661 Horseblock Road 
+Medford, NY 11763 
+359,338 
+0.58 
+% 
+Ippolito, Tom (4) 
+3661 Horseblock Road 
+Medford, NY 11763 
+140,000 
+0.23 
+% 
+Bruce, Richard (5) 
+3661 Horseblock Road 
+Medford, NY 11763 
+210,075 
+0.34 
+% 
+Meller, Gary (6) 
+3661 Horseblock Road 
+Medford, NY 11763 
+609,000 
+0.98 
+% 
+Davis, Katherine L. (7) 
+3661 Horseblock Road 
+Medford, NY 11763 
+225,650 
+0.36 
+% 
+GROUP (8) 
+9,588,584 
+14.85 
+% 
+Inverness Medical Innovations, Inc . 
+51 Sawyer Road, Suite 200 
+Waltham, MA 02453 
+5,367,840 
+8.66 
+% 
+Crestview Capital Offshore Fund, Inc. 
+95 Revere Drive, Suite A 
+Northbrook, IL 60062 
+3,356,040 
+5.41 
+% 
+Beneficial ownership is determined in accordance with the Rule 13d-3(a) of the Securities Exchange Act of 1934, as amended, and generally includes voting or investment power with respect to securities. Except as subject to community property laws, where applicable, the person named above has sole voting and investment power with respect to all shares of our common stock shown as beneficially owned by him. 
+The beneficial ownership percent in the table is calculated with respect to the number of outstanding shares (61,996,651) of the Company's common stock outstanding as of April 9, 2010. Each stockholder's ownership is calculated as the number of shares of common stock owned plus the number of shares of common stock into which any preferred stock, warrants, options or other convertible securities owned by that stockholder can be converted within 60 days. 
+The term “named executive officer” refers to our principal executive officer, our two most highly compensated executive officers other than the principal executive officer who were serving as executive officers at the end of 2009, and two additional individuals for whom disclosure would have been provided but for the fact that the individuals were not serving as executive officers of the Company at the end of 2009. 
+(1) 
+Includes 618,333 shares issuable upon exercise of options exercisable within 60 days. Does not include 266,667 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(2) 
+Includes 757,500 shares issuable upon exercise of options exercisable within 60 days. Does not include 400,000 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(3) 
+Includes 304,166 shares issuable upon exercise of options exercisable within 60 days. Does not include 183,334 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(4) 
+Includes 140,000 shares issuable upon exercise of options exercisable within 60 days. Does not include 150,000 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(5) 
+Includes 210,000 shares issuable upon exercise of options exercisable within 60 days. Does not include 150,000 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(6) 
+Includes 309,000 shares issuable upon exercise of options exercisable within 60 days. Does not include 225,000 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(7) 
+Includes 225,650 shares issuable upon exercise of options exercisable within 60 days. Does not include 225,000 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(8) 
+Includes footnotes (1)-(7) 
+. 
+AVAILABLE INFORMATION 
+Copies of our Annual Report on Form 10-K are being furnished to each stockholder with this proxy statement, and are available on the internet at http://phx.corporate-ir.net/phoenix.zhtml?c=121584&p=proxy pursuant to the instructions set forth in the attached “Notice Regarding the Availability of Proxy Materials.” Upon written request, we will provide, without charge, a copy of our quarterly reports on Form 10-Q for the quarters ended September 30, 2009 and June 30, 2009 to any stockholder of record, or to any stockholder who owns common stock listed in the name of a bank or broker as nominee, at the close of business on April 9, 2010. Any request for a copy of these reports should be mailed to the Secretary, Chembio Diagnostics, Inc., 3661 Horseblock Road, Medford, NY 11763. Stockholders may also receive copies of these reports by accessing the Company’s website at www.chembio.com We file annual, quarterly and current reports, proxy statements and other information in accordance with the Securities Exchange Act of 1934, as amended, with the SEC. You may read and copy any reports, proxy statements or other information filed by us at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. In addition, these materials we file electronically with the SEC are available at the SEC’s website at www.sec.gov. The SEC’s website contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. Information about the operation of the SEC’s public reference facilities may be obtained by calling the SEC at 1-800-SEC-0330. 
+ITEM 1. ELECTION OF DIRECTORS 
+At the Annual Meeting, the stockholders will elect three directors to serve as our Board of Directors. Each director will be elected to hold office until the next annual meeting of stockholders and thereafter until his/her successor is elected and qualified. The affirmative vote of a plurality of the shares voted at the Annual Meeting in person or by proxy is required to elect each director. Cumulative voting is not permitted in the election of directors. In the absence of instructions to the contrary, the person named in the accompanying proxy shall vote the shares represented by that proxy for the persons named below as management’s nominees for directors. Nominees Siebert, Meller and Davis currently serve as directors of the Company. 
+It is not anticipated that any of the nominees will become unable or unwilling to accept nomination or election, but, if that should occur, the persons named in the proxy intend to vote for the election of such other person as the Board of Directors may recommend. 
+The following table sets forth, with respect to each nominee for director, the nominee’s age, positions and offices with the Company, the expiration of the nominee’s term as a director and the year in which the nominee first became a director. Individual background information concerning each of the nominees follows the table. For additional information concerning the nominees, including stock ownership and compensation, see “Executive Compensation,” “Beneficial Ownership of the Company’s Equity Securities”, and “Certain Transactions With Management And Principal Stockholders.” 
+Name 
+Age 
+Position(s) and Office(s) with the Company 
+Expiration of Term of Director 
+Initial Date as Director 
+Lawrence A. Siebert 
+53 
+Chief Executive Officer, President and Chairman of the Board 
+2010 Annual Meeting 
+May 2004 
+Dr. Gary Meller 
+60 
+Director 
+2010 Annual Meeting 
+March 2005 
+Katherine L. Davis 
+53 
+Director 
+2010 Annual Meeting 
+May 2007 
+Lawrence A. Siebert (53), President, Chief Executive Officer and Director. Mr. Siebert was appointed President of Chembio Diagnostics, Inc. and a member of our board of directors upon consummation of the merger. Mr. Siebert has been Chairman of Chembio Diagnostic Systems Inc. for approximately thirteen years and its President since May 2002. Mr. Siebert’s background is in private equity and venture capital investing. From 1982 to 1991, Mr. Siebert was associated with Stanwich Partners, Inc, which during that period invested in middle market manufacturing and distribution companies. From 1992 to 1999, Mr. Siebert was an investment consultant and business broker with Siebert Capital Corp. and Siebert Associates LLC, and was a principal investor in a privately held test and measurement company which was sold in 2002. Mr. Siebert received a JD from Case Western Reserve University School of Law in 1981 and a BA with Distinction in Economics from the University of Connecticut in 1978. Mr. Siebert as president and CEO is an integral part of the Chembio management team. His experience in the rapid test field and financing markets made him an excellent candidate for serving on the board and as its chairman. 
+Dr. Gary Meller (60), Director. Dr. Meller was elected to our Board of Directors on March 15, 2005, and currently serves on the Company’s Audit, Compensation and Nominating and Corporate Governance Committees, including as Chairman of the Compensation Committee. Dr. Meller has been the president of CommSense Inc., a healthcare business development company, since 2001. CommSense Inc. works with clients in Europe, Asia, North America, and the Middle East on medical information technology, medical records, pharmaceutical product development and financing, health services operations and strategy, and new product and new market development. From 1999 until 2001 Dr. Meller was the executive vice president, North America, of NextEd Ltd., a leading internet educational services company in the Asia Pacific region. Dr. Meller also was a limited partner and a member of the Advisory Board of Crestview Capital Master LLC, which was our largest stockholder. Dr. Meller is a graduate of the University of New Mexico School of Medicine and has an MBA from the Harvard Business School. Dr. Meller’s experience in the medical field both domestic and foreign (especially his experience with CommSense Inc.) as well as his financing experience made him an excellent candidate for serving on the board. 
+Kathy Davis (53), Director. Ms. Davis was elected to the Company’s Board of Directors in May 2007, and currently serves on the Company’s Audit, Compensation and Nominating And Corporate Governance Committees, including as Chairman of each of the Audit Committee and the Nominating And Corporate Governance Committee. Since January 2007, Ms. Davis has been the owner of Davis Design Group LLC, a company that provides analytical and visual tools for public policy design. Previously, from February 2005 to December 2006, she served as the Chief Executive Officer of Global Access Point, a start up company with products for data transport, data processing, and data storage network and hub facilities. From October 2003 to January 2005, Ms. Davis was Lieutenant Governor of the State of Indiana, and from January 2000 to October 2003 was Controller of the City of Indianapolis. From 1989 to 2003, Ms. Davis held leadership positions with agencies and programs in the State of Indiana including State Budget Director, Secretary of Family & Social Services Administration, and Deputy Commissioner of Transportation. From 1982 to 1989 Ms. Davis held increasingly senior positions with Cummins Engine, where she managed purchasing, manufacturing, engineering, and assembly of certain engine product lines. Ms. Davis also led the startup of and initial investments by a $50 million Indiana state technology fund, serves on the not-for-profit boards of Noble of Indiana, University of Evansville Institute of Global Enterprise, Purdue College of Science Dean’s Leadership Council and Indiana University School of Public and Environmental Affairs Dean’s Advisory Council. She has a Masters of Business Administration from Harvard Business School and a Bachelor of Science in Mechanical Engineering from the Massachusetts Institute of Technology. Ms. Davis has varied experience in business, political and financial areas made her an excellent candidate for serving on the board. 
+Required Vote; Board Recommendation 
+The affirmative vote of a plurality of the shares voted at the Annual Meeting in person or by proxy is required to elect each director. The Board of Directors unanimously recommends that the stockholders vote FOR the election of the three nominees listed above. 
+INFORMATION REGARDING THE BOARD OF DIRECTORS 
+AND EXECUTIVE OFFICERS 
+Other Executive Officers 
+The following table sets forth with respect to each other executive officer other than Mr. Siebert, the officer’s age, the officer’s positions and offices with the Company, the expiration of his term as an officer and the period during which he has served, either the Company or Chembio Diagnostic Systems Inc. 
+Name 
+Age 
+Position With Company 
+Initial Date as Officer 
+Richard J. Larkin 
+53 
+Chief Financial Officer 
+2003 
+Javan Esfandiari 
+43 
+Director of Research & Development 
+2004 
+Richard Bruce 
+56 
+Vice President, Operations 
+2004 
+Tom Ippolito 
+47 
+Vice President of Regulatory Affairs, Quality Assurance and Quality Control 
+2005 
+Richard J. Larkin (53), Chief Financial Officer. Mr. Larkin was appointed as Chief Financial Officer of Chembio Diagnostics, Inc. upon consummation of the merger. Mr. Larkin oversees our financial activities and information systems. Mr. Larkin has been the Chief Financial Officer of Chembio Diagnostic Systems Inc. since September 2003. Prior to joining Chembio Diagnostic Systems Inc., Mr. Larkin served as CFO at Visual Technology Group from May 2000 to September 2003, and also led their consultancy program that provided hands-on expertise in all aspects of financial service, including the initial assessment of client financial reporting requirements within an Enterprise Resource Planning (Manufacturing) environment through training and implementation. Prior to joining VTG, he served as CFO at Protex International Corporation from May 1987 to January 2000. Mr. Larkin holds a BBA in Accounting from Dowling College and is a member of the American Institute of Certified Public Accountants. 
+Javan Esfandiari (43), Executive VP of Research and Development. Mr. Esfandiari joined Chembio Diagnostic Systems, Inc, in 2000. Mr. Esfandiari co-founded, and became a co-owner of Sinovus Biotech AB where he served as Director of Research and Development concerning lateral flow technology until Chembio Diagnostic Systems Inc. acquired Sinovus Biotech AB in 2000. From 1993 to 1997, Mr. Esfandiari was Director of Research and Development with On-Site Biotech/National Veterinary Institute, Uppsala, Sweden, which was working in collaboration with Sinovus Biotech AB on development of veterinary lateral flow technology. Mr. Esfandiari received his B.Sc. in Clinical Chemistry and his M. Sc. in Molecular Biology from Lund University, Sweden. He has published articles in various veterinary journals and has co-authored articles on tuberculosis serology with Dr. Lyashchenko. 
+Richard Bruce (54), Vice President, Operations. Mr. Bruce was hired in April 2000 as Director of Operations. He is responsible for manufacturing, maintenance, inventory, shipping, receiving, and warehouse operations. Prior to joining Chembio Diagnostic Systems Inc., he held director level positions at Wyeth Laboratories from 1984 to 1993. From 1993 to 1998, he held various management positions in the Operations department at Biomerieux. From 1998 to 2000, he held a management position at V.I. Technologies. Mr. Bruce has over thirty years of operations management experience with Fortune 500 companies in the field of in-vitro diagnostics and blood fractionation. Mr. Bruce received his BS in Management from National Louis University in 1997. 
+Tom Ippolito (47), VP of Regulatory Affairs, QA and QC. Mr. Ippolito joined Chembio in June 2005. He has over twenty years experience with in vitro diagnostics for infectious diseases, protein therapeutics, vaccine development, Process Development, Regulatory Affairs and Quality Management. Over the years, Mr. Ippolito has held Vice President level positions at Biospecific Technologies, Corp. from 2000 - 2005, Director level positions in Quality Assurance, Quality Control, Process Development and Regulatory Affairs at United Biomedical, Inc. from 1987 - 2000. Mr. Ippolito is the Course Director for “drug development process” and “FDA Regulatory Process” for the BioScience Certificate Program at the New York State University of Stony Brook, a program he has been a part of since its inception in 2003. 
+Each of our officers serves at the pleasure of the Board of Directors. There are no family relationships among our officers and directors. 
+Certain Transactions with Management and Principal Stockholders 
+On May 7, 2009, the Compensation Committee of the Company reduced, to $0.13 per share, the exercise price of each outstanding employee option that was issued under the 1999 Equity Incentive Plan (the “1999 Plan”) for which the exercise price was greater than $0.44 per share of the Company’s common stock. There was no other change made to the terms of the stock options other than the reduction in the exercise price. A total of 1,036,750 options were affected. Mr. Siebert, Mr. Esfandiari and Mr. Larkin had options to purchase 160,000, 497,500, and 137,500 shares of common stock, respectively. On May 7, 2009, the last reported sale price for the Company’s common stock was $.13 per share. 
+In addition, on May 7, 2009 in accordance with the terms of the Company’s 2008 Stock Incentive Plan, the Company granted certain employees of the Company, options to purchase an aggregate of 2,925,000 shares of the Company’s common stock. The exercise price for these options is equal to $0.13 per share. The options become exercisable in thirds on the first, second and third anniversaries of the date of the grant. Each option granted will expire and terminate, if not exercised sooner, upon the earlier to occur of (a) 30 days after termination of the employee’s employment with the Company or (b) the fifth anniversary of the date of grant. Mr. Siebert, Mr. Esfandiari and Mr. Larkin received options to purchase common stock of 400,000, 300,000 and 275,000 shares of common stock, respectively. 
+During the quarter ended December 31, 2008, Inverness Medical Innovations, Inc. (“Inverness”) notified the Company that Inverness had entered into a contract with Bio-Rad Laboratories, Inc. (“Bio-Rad”) for royalties on Bio-Rad’s patent for the detection of HIV-2 antibodies. The agreement also provided for Inverness to pay past royalties. On June 25, 2009, the Company and Inverness entered into a letter agreement whereby certain obligations aggregating approximately $1,010,000 as of December 31, 2008 were agreed to be paid by the Company from future revenues. The obligations include the Company’s share under its agreements with Inverness for the amount of HIV-2 royalties that Inverness paid when Inverness entered into an HIV-2 license agreement with Bio-Rad Laboratories, Inc. of approximately $485,000 and royalties owed by Chembio on lateral flow licenses to Inverness of approximately $525,000 as of December 31, 2008. Under the agreement, Inverness will retain an additional 10% of Clearview® HIV 1/2 STAT-PAK® net sales and 5% of Clearview® Complete HIV 1/2 net sales until these obligations are extinguished. The approximate aggregate balance due is $242,000 as of December 31, 2009. 
+Director Independence 
+Our common stock trades on the OTC Bulletin Board. As such, we are not currently subject to corporate governance standards of listed companies, which require, among other things, that the majority of the board of directors be independent. 
+We are not currently subject to corporate governance standards defining the independence of our directors, and we have chosen to define an “independent” director in accordance with the NASDAQ Global Market's requirements for independent directors. Under this definition, we have determined that both Katherine L. Davis and Gary Meller currently qualify as an independent director. We do not list the “independent” definition we use on our internet website. 
+Section 16(a) Beneficial Ownership Reporting Compliance 
+Section 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), requires the Company’s directors, executive officers and beneficial owners of more than 10% of the Company’s common stock to file with the Securities and Exchange Commission initial reports of ownership and reports of changes in ownership of common stock and other equity securities of the Company. The Company believes that during the year ended December 31, 2008, each person who was an officer, director and beneficial owner of more than 10% of the Company’s common stock complied with all Section 16(a) filing requirements, except for the following: (i) one Form 4 for Gary Meller filed on October 30, 2009 that covered two reports and three transactions that were not reported on a timely basis; and (ii) one Form 4 for Lawrence Siebert filed on October 30, 2009 that covered one report and seven transactions; (iii) one Form 4 for Richard Larkin filed on October 30, 2009 that covered one report and seven transactions; (iv) one Form 4 for Katherine Davis that covered one report and two transactions; and (iv) one Form 4 for Javan Esfandiari that covered one report and eleven transactions. 
+Board of Directors and Committees 
+The Board of Directors held nine meetings during the fiscal year ended December 31, 2009 and each director participated in at least 75% of those meetings and meetings of the committees on which he/she served. Although the Company does not have a formal policy regarding attendance by members of the Board of Directors at the Company’s annual meeting of stockholders, the Company encourages each director to attend. None of the members of the Board of Directors was present at last year’s annual meeting of stockholders. 
+Audit Committee 
+The Company’s Audit Committee met four times in 2009 and currently consists of Katherine L. Davis (Chairperson) and Dr. Gary Meller. The Board of Directors has determined that Ms. Davis is an “audit committee financial expert,” as defined under the rules of the SEC. Each of the members of the Audit Committee is deemed “independent” in accordance with the NASDAQ Global Market’s requirements for independent directors. This committee oversees, reviews, acts on and reports to our Board of Directors on various auditing and accounting matters including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, and the performance of our independent accountants. A copy of the committee’s charter is available on the Company’s website at www.chembio.com. 
+Compensation Committee 
+The Company’s Compensation Committee met twice in 2009 and currently consists of Dr. Gary Meller (Chairperson) and Katherine L. Davis. Each of the committee’s members is deemed “independent” in accordance with the NASDAQ Global Market’s requirements for independent directors. The Compensation Committee establishes salaries, incentives and other forms of compensation for executive officers. The Compensation Committee also administers our incentive compensation plan. The Compensation Committee’s charter is available on the Company’s website at www.chembio.com. The Compensation Committee does not currently delegate its authority to any other party, and does not currently engage any compensation consultants to determine the amount or form of executive and director compensation. Executive officers do not play a role in the determination or recommendation of the form or amount of any executive compensation paid. 
+Nominating and Corporate Governance Committee 
+The Company’s Nominating and Corporate Governance Committee did not meet in 2009 and currently consists of Katherine L. Davis (Chairperson) and Dr. Gary Meller. Each of the committee’s members is deemed “independent” in accordance with the NASDAQ Global Market’s requirements for independent directors. The committee (i) identifies individuals qualified to become members of the Board of Directors, (ii) recommends director candidates to the Company’s Board of Directors, (iii) develops, updates as necessary, and recommends to the Company’s Board of Directors corporate governance principles and policies, and (iv) monitors compliance with such principles and policies. The committee’s charter is available on the Company’s website at www.chembio.com. All the nominees for director included in this proxy statement were recommended by the Nominating Committee, which is comprised entirely of non-management directors. 
+To be considered for nomination by the Board at the next annual meeting of stockholders, the nominations must be made by stockholders of record entitled to vote. Stockholder nominations must be made by notice in writing, delivered or mailed by first class U.S. mail, postage prepaid, to the Secretary of the Company at the Company’s principal business address, not less than 60 days nor more than 90 days prior to any meeting of the stockholders at which directors are to be elected. Each notice of nomination of directors by a stockholder shall set forth the nominee’s name, age, business address, if known, residence address of each nominee proposed in that notice, the principal occupation or employment of each nominee for the five years preceding the date of the notice, the number of shares of the Company’s common stock beneficially owned by each nominee and any arrangement, affiliation, association, agreement or other relationship of the nominee with any Company stockholder. 
+Stockholders wishing to send communications to the Board may contact Lawrence Siebert, our CEO, President and Chairman, at the Company’s principal executive office address. All such communications shall be shared with the members of the Board, or if applicable, a specified committee or director. 
+Leadership Structure of the Board 
+Currently, the Board believes that our chief executive officer (CEO) is best positioned to serve as Chairman, due to his ability to provide clear insight and direction of business strategies and plans to both the Board and management. The Board believes Chembio can most effectively execute its business strategies and plans if the Chairman is also a member of the management team. A single person, acting in the capacities of Chairman and CEO, provides unified leadership and focus. Although our Board has historically determined that combining the role of CEO and Chairman to be the most efficient and effective, we do not have formal guidelines that establish this approach as a policy. Therefore, under different circumstances, the Board does have the flexibility to separate the two roles. The Board has not appointed a “lead independent director” due to the small size of the Board and because two of the three directors are independent and thus a “lead independent director” would not add significant value at this time. 
+Risk Management 
+Management is responsible for assessing and managing the Company’s exposure to various risks. At least annually, the Company goes through its assessment process to identify risk and develop plans to address them. This process is led by the Chief Financial Officer. The Audit Committee has oversight responsibility to review management’s risk management process, including the policies and guidelines used by management to identify, assess and manage the Company’s exposure to risk. The Chief Financial Officer reports directly to the Audit Committee at least quarterly to provide an update on management’s efforts to manage risk. The Audit Committee also has oversight responsibility for financial risks. The Board of Directors has oversight responsibility for all other risks. 
+Diversity 
+The Board recognizes the importance of diversity in business experience, education, and professional skills in selecting nominees for director. The Board does not, however, have a formal policy concerning the consideration of diversity. 
+Audit Committee Report 
+This report shall not be deemed incorporated by reference by any general statement incorporating by reference this Proxy Statement into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under either of such Acts. 
+The Audit Committee oversees the Company’s financial reporting process. Management has the primary responsibility for the financial statements and the reporting process, including the systems of internal controls. In fulfilling its oversight responsibilities, the committee reviewed and discussed with management the audited financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 and the unaudited financial statements included in the Quarterly Reports on Form 10-Q for the first three quarters of the fiscal year ended December 31, 2009. 
+The committee discussed with the independent auditors, who are responsible for expressing an opinion on the conformity of audited financial statements with generally accepted accounting principles, the auditors’ judgments as to the quality, not just the acceptability, of the Company’s accounting principles and such other matters as are required to be discussed by the auditors with the committee under Statement on Auditing Standard No. 61, as amended. In addition, the committee discussed with the independent auditors the auditors’ independence from management and the Company, including the matters in the written disclosures and the letter required by the Independence Standards Board Standard No. 1. The committee considered whether the auditors’ providing services on behalf of the Company other than audit services is compatible with maintaining the auditors’ independence. 
+The committee discussed with the Company’s independent auditors the overall scope and plans for their respective audits. The committee will meet with the independent auditors, with and without management present, to discuss the results of the auditors’ examinations, their evaluations of the Company’s internal controls, and the overall quality of the Company’s financial reporting. 
+In reliance on the reviews and discussions referred to above, the committee approved inclusion of the audited financial statements in the Annual Report on Form 10-K for the year ended December 31, 2009 for filing with the SEC. 
+The Audit Committee 
+Katherine Davis (Chairperson) 
+Dr. Gary Meller 
+April 16, 2010 
+EXECUTIVE COMPENSATION 
+The following table summarizes all compensation recorded by the Company in each of the last two completed fiscal years for our principal executive officer and for our two most highly compensated executive officers other than our principal executive officer whose annual compensation exceeded $100,000. 
+Name / 
+Principal 
+Position 
+Year 
+Salary 1 
+($) 
+Bonus 2 
+($) 
+Option Awards 3 
+($) 
+Stock 
+Awards 
+($) 
+All Other Compensation 5 
+($) 
+Total 
+($) 
+Lawrence A. Siebert 4 
+2009 
+$ 
+265,000 
+$ 
+110,200 
+$ 
+37,950 
+$ 
+- 
+$ 
+7,200 
+$ 
+420,350 
+CEO 
+2008 
+265,000 
+26,000 
+36,695 
+- 
+8,267 
+335,962 
+Javan Esfandiari 
+2009 
+$ 
+230,192 
+$ 
+29,400 
+$ 
+28,200 
+$ 
+5,000 
+$ 
+4,883 
+$ 
+297,675 
+VP-R&D 
+2008 
+215,692 
+16,000 
+45,297 
+28,702 
+5,872 
+311,563 
+Tom Ippolito 
+2009 
+$ 
+181,500 
+$ 
+35,600 
+$ 
+21,150 
+$ 
+- 
+$ 
+140 
+$ 
+238,390 
+VP-Regulatory 
+2008 
+173,631 
+12,000 
+8,129 
+- 
+1,708 
+195,468 
+1 Salary is total base salary. 
+2 Bonuses earned in 2009 were partially based on reaching certain objectives, which included revenue dollar levels and operating profit levels, additional amounts earned were discretionary. Bonuses earned in 2008 were paid solely on a discretionary basis, and not pursuant to any bonus plan. 
+3 The estimated fair value of any option or common stock granted was determined in accordance with ASC 718, "Share-Based Payment". 
+4 Mr. Siebert also serves as a director on the Company’s board of directors. Mr. Siebert does not receive any compensation for this director role. 
+5 Other compensation includes an employer match to 401(K) contributions and car allowances where applicable. 
+Employment Agreements 
+Mr. Siebert. Effective May 11, 2009, the Company’s Board of Directors approved the Company’s extension of the June 15, 2006 employment agreement (the “Employment Agreement”) with Lawrence A. Siebert, the Company’s President and Chief Executive Officer, for an additional three-year term. On June 15, 2006, Mr. Siebert and the Company entered into an Employment Agreement, effective May 10, 2006, which was to terminate on May 10, 2008, extended in 2008 to May 10, 2009. Pursuant to the Employment Agreement, Mr. Siebert serves as the President and Chief Executive Officer of the Company and received an initial salary of $240,000 per year, which had been increased to $265,000 per year until Mr. Siebert agreed to a 15 percent reduction, to $225,000, effective January 19, 2009. Mr. Siebert’s salary was restored to $265,000 per annum effective in July 2009. Mr. Siebert also is eligible for a bonus of up to 50% of his salary, consisting of (i) a bonus of up to 25% of his salary that is at the complete discretion and determination of the board of directors, and (ii) a bonus of up to an additional 25% of his salary that will be determined based upon revenue and earnings performance criteria established each year by the board of directors. Mr. Siebert is eligible to participate in any profit sharing, stock option, retirement plan, medical and/or hospitalization plan, and/or other benefit plans except for disability and life insurance that the Company may from time to time place in effect for the Company’s executives during the term of Mr. Siebert’s employment agreement. If Mr. Siebert’s Employment Agreement is terminated by the Company without cause, or if Mr. Siebert terminates his Employment Agreement for a reasonable basis, including within 12 months of a change in control, the Company is required to pay as severance Mr. Siebert’s salary for six months. Mr. Siebert has agreed for a period of two years after the termination of his employment with the Company not to induce customers, agents, or other sources of distribution of the Company’s business under contract or doing business with the Company to terminate, reduce, alter, or divert business with or from the Company. The terms of the extended May 11, 2009 and May 11, 2008 Employment Agreements are identical to the June 15, 2006 Employment Agreement, except that under the May 11, 2008 extended Employment Agreement, Mr. Siebert received additional consideration in the form of incentive stock options to purchase 250,000 shares of the Company’s common stock exercisable at $0.13 per share, which was the closing price of the Company's common stock on June 3, 2008. The incentive stock options are immediately exercisable and they expire on the June 3, 2013. 
+Mr. Esfandiari. The Company entered into an employment agreement dated March 4, 2010, and to be effective March 5, 2010 (the "Employment Agreement"), with Mr. Esfandiari to continue as the Company's Senior Vice President of Research and Development for an additional term of three years. Mr. Esfandiari's salary under the Employment Agreement is $245,000 for the first year, $255,000 for the second year, and $265,000 for the final year. Mr. Esfandiari is eligible for a cash bonus of up to 50% of his base salary for each respective year, consisting of (i) a cash bonus of up to 30% of his calendar year base salary based on the performance of the Company's Dual Path Platform Technology, which is directly related to certain annual revenue targets budgeted by management of the Company; (ii) a cash bonus of up to 10% of his calendar year base salary based on the attainment of certain specific research and development objectives, as determined by the Board, and (iii) a cash bonus of up to 10% of his calendar year base salary that is at the complete discretion and determination of the board of directors. The Company also granted Mr. Esfandiari, pursuant to the Company's 2008 Stock Incentive Plan, incentive stock options to purchase 300,000 shares of the Company's common stock. The price per share of these options is equal to the fair market value of the Company's common stock as of the close of the market on March 5, 2010, which is the date on which the Agreement was effective. Of these stock options to purchase 100,000 shares vest on the effective date, options to purchase an additional 100,000 shares of the stock options vested on the second anniversary of the Employment Agreement, and options to purchase an additional 100,000 shares of the stock options vested on the third anniversary of the Employment Agreement. Mr. Esfandiari is eligible to participate in any profit sharing, stock option, retirement plan, medical and/or hospitalization plan, and/or other benefit plans except for disability and life insurance that the Company may from time to time place in effect for the Company’s executives during the term of Mr. Esfandiari’s employment agreement. If Mr. Esfandiari’s employment agreement is terminated by the Company without cause, or if Mr. Esfandiari terminates his employment agreement for a reasonable basis, as defined in the Employment Agreement including within 12 months of a change in control, the Company is required to pay as severance Mr. Esfandiari’s salary for twelve months. 
+Mr. Ippolito does not have an employment contract with the Company. 
+Executive Bonus Plan 
+The Company has established a bonus plan for its executives who do not have a contract. For the fiscal year ended December 31, 2009, there were three executives eligible for this bonus plan. Each executive can earn up to 25% of that executive’s salary in the form of a bonus. Half of the amount, or 12.5%, is determined by the Compensation Committee in its discretion, and the other half is subject to the Company’s attaining certain objectives based on revenue and operating profit levels for the fiscal year for which the bonus is paid. The plan, during 2009, called for a sliding percentage of the executive’s salary, from zero to 6.25% for attaining 85% to 100% of revenue goals, and from zero to 6.25% of the executive’s salary for attaining between zero percent to 150% of the designated operating profit goals. The Company achieved 98.3% of its revenue goals for 2009, resulting in a bonus of 5.5% of each executive’s salary, and achieved greater than 150% of its operating profit goal, resulting in a bonus of 6.25% of salary, for a total of 11.75% of salary. In addition, the Compensation Committee approved approximately 8% of salary in discretionary bonuses for the subject executives, bringing the total bonus to approximately 20% of salary. Goals for 2010 have not yet been established. 
+OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END 2009 
+Option Awards 
+Stock Awards 
+Name 
+Number of Securities Underlying Unexcercised Options Excerciseable (#) 
+Number of Securities Underlying Unexcercised Options Unexcersable 
+(#) 
+Option Exercise Price 
+($) 
+Option Expiration Date 
+Option Vesting Date 
+Number of Shares of Stock That Have Not Vest 
+(#) 
+Market Value of Shares of Stock That Have Not Vested 
+($) 
+Foot- 
+note 
+Lawrence A. Siebert 
+133,333 
+0.13 
+5/6/2014 
+5/6/2012 
+5 
+133,333 
+0.13 
+5/6/2014 
+5/7/2011 
+5 
+133,333 
+0.13 
+5/6/2014 
+5/6/2010 
+5 
+250,000 
+0.13 
+6/3/2013 
+6/3/2008 
+3 
+75,000 
+0.22 
+2/15/2013 
+2/15/2008 
+2 
+50,000 
+0.13 
+5/28/2011 
+1/1/2007 
+1, 4 
+50,000 
+0.13 
+5/28/2011 
+4/17/2006 
+1, 4 
+10,000 
+0.13 
+5/4/2011 
+4/17/2006 
+4 
+50,000 
+0.13 
+5/4/2011 
+5/5/2004 
+4 
+Javan Esfandiari 
+100,000 
+0.13 
+5/6/2014 
+5/6/2012 
+5 
+100,000 
+0.13 
+5/6/2014 
+5/7/2011 
+5 
+100,000 
+0.13 
+5/6/2014 
+5/6/2010 
+5 
+100,000 
+0.13 
+4/23/2012 
+3/5/2009 
+1, 4 
+100,000 
+0.13 
+4/23/2012 
+3/5/2008 
+1, 4 
+60,000 
+0.22 
+2/15/2013 
+2/15/2008 
+2 
+25,000 
+0.13 
+5/28/2011 
+5/28/2007 
+4 
+100,000 
+0.13 
+4/23/2012 
+4/23/2007 
+1, 4 
+18,750 
+0.13 
+3/24/2011 
+1/1/2007 
+4 
+25,000 
+0.13 
+5/17/2010 
+1/1/2007 
+4 
+25,000 
+0.13 
+5/28/2011 
+4/17/2006 
+1, 4 
+25,000 
+0.13 
+5/28/2011 
+4/17/2006 
+1, 4 
+5,000 
+0.13 
+5/4/2011 
+4/17/2006 
+4 
+25,000 
+0.13 
+5/17/2010 
+4/17/2006 
+4 
+18,750 
+0.13 
+3/24/2011 
+3/24/2006 
+4 
+30,000 
+0.13 
+5/4/2011 
+5/5/2004 
+4 
+Tom Ippolito 
+75,000 
+0.13 
+5/6/2014 
+5/6/2012 
+5 
+75,000 
+0.13 
+5/6/2014 
+5/7/2011 
+5 
+75,000 
+0.13 
+5/6/2014 
+5/6/2010 
+5 
+50,000 
+0.22 
+2/15/2013 
+2/15/2008 
+2 
+15,000 
+0.13 
+3/24/2011 
+3/24/2006 
+4 
+1 Stock issued in connection with an employment contract and under the 1999 Stock Option Plan. 
+2 On February 15, 2008 the Company granted options under the 1999 Stock Option Plan. 
+3 Options issued in connection with an employment contract and under the 2008 Stock Incentive Plan. 
+4 On May 7, 2009, the Compensation Committee of the Company reduced, to $0.13 per share, the exercise price of each outstanding employee option that was issued under the 1999 Equity Incentive Plan (the “1999 Plan”) for which the exercise price was greater than $0.44 per share of the Company’s common stock. There was no other change made to the terms of the stock options other than the reduction in the exercise price. A total of 1,036,750 options were affected and the fair value difference of the options before and after the reduction was $31,660 and was expensed in the three months ended June 30, 2009. 
+5 On May 7, 2009 in accordance with the terms of the Company’s 2008 Stock Incentive Plan, the Company granted certain employees of the Company, options to purchase an aggregate of 2,925,000 shares of the Company’s common stock. The exercise price for these options is equal to $0.13 per share. The options become exercisable in thirds on the first, second and third anniversaries of the date of the grant. Each option granted will expire and terminate, if not exercised sooner, upon the earlier to occur of (a) 30 days after termination of the employee’s employment with the Company or (b) the fifth anniversary of the date of grant. The fair value of these options is being amortized over the vesting life of the options. 
+Director Compensation 
+All non-employee directors are paid an $18,000 annual retainer, semi-annually, and once every five years, on the date of the annual meeting of stockholders that directors are elected or re-elected (every 5 years), receive stock options to acquire 375,000 shares of the Company's common stock, with an exercise price equal to the market price on the date of the grant. Stock options to acquire 75,000 shares become exercisable on the date of grant, and options to acquire an additional 75,000 shares become exercisable on the date of each of the four succeeding annual meetings of stockholders if and to the extent that the non-employee director is reelected as a director at each such annual meeting. The audit committee chairman is paid an annual retainer of $2,500, paid semi-annually. In addition, the non-employee directors are paid $1,000 in cash for each board of directors' meeting attended, and paid $500 in cash for each telephonic board of directors meeting. The non-employee directors who are members of a committee of the board of directors are paid $500 in cash for each committee meeting attended, or $750 in cash for each committee meeting attended if that non-employee director is the committee chairman. The following table summarizes all compensation recorded by the Company paid to directors in the recently completed fiscal year. 
+Name 
+Fees Earned or Paid in Cash 
+($) 1 
+Option Awards 
+($) 2 
+Total 
+($) 
+Katherine L. Davis 
+$ 
+29,500 
+$ 
+31,950 
+$ 
+61,450 
+Gary Meller 
+26,500 
+$ 
+31,950 
+58,450 
+James D. Merselis 3 
+1,000 
+- 
+1,000 
+1 Fees earned or paid in cash represents a yearly fee and fees for meeting expenses: (a) Ms. Davis received an $18,000 annual fee as a member of the board of directors, a $2,500 annual fee as audit committee chairman and $9,000 in meeting fees paid during 2009; (b) Mr. Meller received an $18,000 annual fee as a member of the board of directors, and $8,500 in meeting fees; (d) Mr. Merselis received $1,000 in meeting fees. 
+2 Each outside member of the board of directors is granted, once every five years, the right to purchase 375,000 shares of the company’s common stock with an exercise price equal to the market price on the date of the grant as part of their annual compensation. One-fifth of these options are exercisable on the date of grant, one-fifth become exercisable on the first anniversary of the date of grant, and additional one-fifths become exercisable on the second through fourth anniversary of the date of grant. The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. 
+3 Mr. Merselis resigned from our Board of Directors on February 9, 2009. 
+Compensation Committee Interlocks and Insider Participation 
+No executive officer of the Company served as a member of the Board of any other public company during the year ended December 31, 2009. No member of the Compensation Committee served as an executive officer of any other public company during the year ended December 31, 2009. No interlocking relationship exists between the members of our Compensation Committee and the Board or compensation committee of any other company. 
+ITEM 2. PROPOSAL TO RATIFY THE SELECTION OF PARENTE RANDOLPH, LLC 
+AS CERTIFIED INDEPENDENT ACCOUNTANTS 
+The Company, through and with the approval of the Audit Committee of the Company’s Board of Directors, engaged ParenteBeard LLC (Parente) of New York, New York as its independent registered public accounting firm to serve as the Company's certified independent accountants to audit the Company's financial statements for the fiscal year ended December 31, 2009. 
+During the years ended December 31, 2009 and 2008, and during the interim period from the end of the most recently completed fiscal year through April 16, 2010, the date of engagement, the Company did not consult with Parente regarding the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinions that might be rendered by Parente on the Company’s financial statements. Parente did not provide the Company with a written report or any oral advice that was an important factor considered by the Company in reaching a decision as to any accounting, auditing or financial reporting issue. 
+In addition, during the years ended December 31, 2009 and 2008, and during the interim period from the end of the most recently completed fiscal year through March 4, 2010, the date of engagement, the Company did not consult with Parente on any matter that was either the subject of a disagreement (as defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions to this item) or a reportable event (as described in Item304(a)(1)(v) of Regulation S-K). As such none of the required disclosures under Item 304(a)(2)(ii) apply. 
+It is expected that one or more representatives of Parente will be present, or available by phone, at the Annual Meeting and will be given the opportunity to make a statement and to respond to appropriate questions from stockholders. 
+Principal Accountant Fees and Services 
+All fees discussed below were paid to ParenteBeard LLC, except 2008 amounts, which were paid to Lazar Levine & Felix LLP. In February 2009, Lazar Levine & Felix LLP merged its practice into Parente Randolph, LLC, which subsequently changed its name to ParenteBeard LLC. 
+Audit Fees 
+For the years ended December 31, 2009 and 2008, the Company’s independent accounting firm billed the Company $145,000 and $136,000, respectively, for fees for the audit of the Company’s annual financial statements and review of financial statements included in the Company’s Forms 10-Q and 10-K. 
+Audit-Related Fees 
+For the years ended December 31, 2009 and 2008, the independent accounting firm did not provide the Company with any assurance and related services reasonably related to the performance of the audit or review of the Company’s financial statements that are not reported above under “Audit Fees.” 
+Tax Fees 
+For the years ended December 31, 2009 and 2008, the independent accounting firm billed the Company $20,000 and $13,500, respectively, for professional services for tax compliance, tax advice and tax planning. 
+All Other Fees 
+For the years ended December 31, 2009 and 2008, the independent accounting firm billed the Company none and $2,500, respectively for fees associated with the preparation and filing of the Company’s registration statements, responses to SEC comment letters and other related matters. 
+Audit Committee Pre-Approval Policies 
+The Audit Committee approves in advance all audit and non-audit services performed by the independent accounting firm. There are no other specific policies or procedures relating to the pre-approval of services performed by the independent accounting firm. 
+Required Vote; Board Recommendation 
+An affirmative vote of the majority of shares represented at the Annual Meeting in person or by proxy is necessary to ratify the selection of auditors. There is no legal requirement for submitting this proposal to the stockholders; however, the Board of Directors believes that it is of sufficient importance to seek ratification. Whether the proposal is approved or defeated, the Board may reconsider its selection of Parente. 
+The Board of Directors unanimously recommends that the stockholders vote FOR ratifying the selection of the certified public accounting firm of ParenteBeard LLC to serve as the Company’s certified independent accountants for the fiscal year ending December 31, 2010 or until the Board of Directors, in its discretion, replaces them. 
+RESOLUTIONS PROPOSED BY INDIVIDUAL STOCKHOLDERS; 
+DISCRETIONARY AUTHORITY TO VOTE PROXIES 
+Under Rule 14a-8(e) of the Securities Exchange Act of 1934, in order to be considered for inclusion in the proxy statement and form of proxy relating to our next annual meeting of stockholders following the end of our 2010 fiscal year, proposals by individual stockholders must be received by us no later than December 18 , 2010. 
+In addition, under Rule 14a-4(c)(1) of the Securities Exchange Act, the proxy solicited by the Board of Directors for the next annual meeting of stockholders following the end of our 2010 fiscal year will confer discretionary authority on any stockholder proposal presented at that meeting unless we are provided with notice of that proposal no later than March 3, 2011. 
+OTHER BUSINESS 
+The Board of Directors is not aware of any other matters that are to be presented at the Annual Meeting, and it has not been advised that any other person will present any other matters for consideration at the meeting. Nevertheless, if other matters should properly come before the Annual Meeting, the stockholders present, or the persons, if any, authorized by a valid proxy to vote on their behalf, shall vote on such matters in accordance with their judgment. 
+* * * * * 
+This Notice and Proxy statement are sent by order of the Board of Directors. 
+Dated: April 16, 2009 /s/ Lawrence A. Siebert 
+Lawrence A. Siebert, President, Chief Executive Officer 
+and Chairman of the Board 
+* * * * * 
+PROXY 
+PROXY 
+CHEMBIO DIAGNOSTICS, INC. 
+For the Annual Meeting of Stockholders on June 2, 2010 
+Proxy Solicited on Behalf of the Board of Directors 
+The undersigned hereby appoints Lawrence A. Siebert, Richard Larkin, or either of them, as proxies with full power of substitution to vote all the shares of the undersigned with all of the powers which the undersigned would possess if personally present at the Annual Meeting of Stockholders of Chembio Diagnostics, Inc. (the “Corporation”) to be held at 10:30 a.m. (local time) on June 2, 2010, at Chembio, 3661 Horseblock Road, Medford, New York 11763, or any adjournments thereof, on the following matters: 
+[X] Please mark votes as in this example. 
+1. To elect the following three directors: 
+Nominees: Katherine L. Davis, Dr. Gary Meller and Lawrence A. Siebert. 
+FOR ALL NOMINEES [ ] 
+WITHHELD AUTHORITY FOR ALL NOMINEES [ ] 
+FOR ALL NOMINEES EXCEPT AS NOTED ABOVE [ ] 
+2. To ratify the selection of ParenteBeard LLC as the Corporation’s certified independent accountants. 
+[ ] FOR [ ] AGAINST [ ] ABSTAIN 
+3. In their discretion, to vote upon an adjournment or postponement of the meeting. 
+[ ] YES [ ] NO [ ] ABSTAIN 
+4. In their discretion, to vote upon such other business as may properly come before the meeting. 
+[ ] YES [ ] NO [ ] ABSTAIN 
+(Continued and to be signed on the reverse side) 
+Unless contrary instructions are given, the shares represented by this proxy will be voted in favor of Items 1, 2, 3 and 4. This proxy is solicited on behalf of the Board of Directors of Chembio Diagnostics, Inc. 
+EVEN IF YOU PLAN TO ATTEND THE MEETING, PLEASE COMPLETE, DATE, SIGN AND RETURN THIS PROXY IN THE ACCOMPANYING ENVELOPE. 
+MARK HERE FOR ADDRESS CHANGE AND NOTE BELOW [ ] 
+Number of voting shares: 
+Dated: ____________________________________ 
+Signature: ____________________________________ 
+Signature: ____________________________________ 
+Signature if held jointly 
+(Please sign exactly as shown on your stock certificate and on the envelope in which this proxy was mailed. When signing as partner, corporate officer, attorney, executor, administrator, trustee, guardian, etc., give full title as such and sign your own name as well. If stock is held jointly, each join owner should sign.)
\ No newline at end of file
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@@ -0,0 +1,1151 @@
+DEF 14A
+1
+a2173459zdef14a.htm
+DEF 14A
+QuickLinks 
+-- Click here to rapidly navigate through this document 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+SCHEDULE 14A 
+Proxy
+Statement Pursuant to Section 14(a) of 
+the Securities Exchange Act of 1934 
+Filed by the Registrant ý 
+Filed by a Party other than the Registrant o 
+Check the appropriate box: 
+o 
+Preliminary Proxy Statement 
+o 
+Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2)) 
+ý 
+Definitive Proxy Statement 
+o 
+Definitive Additional Materials 
+o 
+Soliciting Material Pursuant to §240.14a-12 
+CROCS, INC. 
+(Name of Registrant as Specified In Its Charter) 
+(Name of Person(s) Filing Proxy Statement, if other than the Registrant) 
+Payment of Filing Fee (Check the appropriate box): 
+ý 
+No fee required. 
+o 
+Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11. 
+(1) 
+Title of each class of securities to which transaction applies: 
+(2) 
+Aggregate number of securities to which transaction applies: 
+(3) 
+Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined): 
+(4) 
+Proposed maximum aggregate value of transaction: 
+(5) 
+Total fee paid: 
+o 
+Fee paid previously with preliminary materials. 
+o 
+Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or
+Schedule and the date of its filing. 
+(1) 
+Amount Previously Paid: 
+(2) 
+Form, Schedule or Registration Statement No.: 
+(3) 
+Filing Party: 
+(4) 
+Date Filed: 
+Crocs, Inc. 
+6328 Monarch Park Place 
+Niwot, Colorado 80503 
+NOTICE OF THE 2006 ANNUAL MEETING OF STOCKHOLDERS TO 
+BE HELD OCTOBER 30, 2006 
+To
+the Stockholders of Crocs, Inc.: 
+We
+will hold the 2006 Annual Meeting of Stockholders of Crocs, Inc. at the Beaver Creek Lodge, 26 Avondale Lane, Beaver Creek, Colorado, on October 30, 2006, at
+9:00 a.m. Mountain time. 
+The
+meeting's purpose is to: 
+1. Elect
+two directors;
+2. Ratify
+the appointment of Deloitte & Touche LLP as our independent auditors for fiscal year 2006; and
+3. Consider
+any other matters that properly come before the meeting and any adjournments. 
+Only
+stockholders of record of our common stock at the close of business on September 27, 2006 are entitled to receive notice of and to vote at the meeting. Each share of common
+stock is entitled to one vote. 
+A
+list of the stockholders entitled to vote at the meeting will be available for examination at the meeting by any stockholder for any purpose relevant to the meeting. The list will also
+be available on the same basis for ten days prior to the meeting at our principal executive office, 6328 Monarch Park Place, Niwot, Colorado 80503. 
+All
+stockholders are cordially invited to attend the meeting in person. Whether or not you plan to attend the meeting in person, please mark, sign and date the
+enclosed proxy promptly and return it in the envelope provided. No postage is required if the proxy card is mailed in the United States. Stockholders who are present at the
+Annual Meeting may withdraw their proxy and vote in person if they so desire. 
+BY ORDER OF THE BOARD OF DIRECTORS 
+Ronald R. Snyder 
+President and Chief Executive Officer 
+Niwot,
+Colorado 
+October 6, 2006 
+Crocs, Inc. 
+6328 Monarch Park Place 
+Niwot, Colorado 80503 
+2006 ANNUAL MEETING OF STOCKHOLDERS 
+PROXY STATEMENT 
+This
+proxy statement is furnished to stockholders of Crocs, Inc., a Delaware corporation, in connection with the solicitation of proxies by our board of directors. The proxies
+being solicited will be voted at the 2006 Annual Meeting of Stockholders (the "Annual Meeting"), to be held on October 30, 2006 at 9:00 a.m., Mountain time, at the Beaver Creek Lodge, 26
+Avondale Lane, Beaver Creek, Colorado, or at any postponement or adjournment thereof, for the purpose of voting on proposals as set forth herein as well as other business matters which may arise. This
+proxy statement and the accompanying proxy card will first be mailed to stockholders on or about October 6, 2006. 
+GENERAL INFORMATION REGARDING ANNUAL MEETING 
+Record Date 
+Stockholders of record at the close of business on September 27, 2006 are entitled to notice of and to vote at the Annual Meeting. On the record date,
+there were 38,845,727 shares of our common stock outstanding. Each such share is entitled to one vote on each matter submitted to a vote at the Annual Meeting. 
+Quorum Requirements 
+A quorum is required to conduct the Annual Meeting. A majority of the outstanding shares entitled to vote must be present in person or by proxy at the Annual
+Meeting in order for a quorum to exist. Abstentions and broker non-votes count as present and voting for purposes of determining a quorum. A broker non-vote occurs when a
+broker returns a proxy card but does not vote on one or more matters because the broker does not have the authority to do so without instructions from the beneficial owner. Shares represented by
+proxies that are marked WITHHOLD with respect to the election of directors will be counted as present in determining whether there is a quorum. 
+Vote Requirements 
+If a quorum is present at the Annual Meeting, the following vote is required for approval of each matter to be voted on: 
+Election of Directors: A plurality of the shares present in person or by proxy and entitled to vote at the Annual Meeting
+must be voted FOR a director nominee. "Plurality" means that the nominees 
+who
+receive the largest number of votes cast are elected as director up to the maximum number of directors to be elected at the Annual Meeting. Consequently, proxies marked WITHHOLD and broker
+non-votes will have no impact on the election of directors. 
+Ratification of Appointment of Deloitte & Touche LLP: A majority of the shares present in person or by proxy and
+entitled to vote at the Annual Meeting must be voted FOR the ratification of the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for fiscal year 2006.
+Proxies marked ABSTAIN will have the practical effect of voting against this proposal. Broker non-votes will have no impact on the proposal. 
+Your Proxy 
+Whether or not you are able to personally attend the Annual Meeting, you are encouraged to vote your shares by completing, signing and returning the enclosed
+proxy card. Shares represented by properly executed proxy cards received by us, and not revoked prior to the Annual Meeting, will be voted at the Annual Meeting as directed in the signed proxy. If no
+directions are specified, such proxies will be voted FOR each of the proposals and in the best judgment of the proxy holders as to other matters that may properly come before the Annual Meeting. 
+If
+your shares are held in the name of a bank or brokerage firm, your bank or broker will send you a separate package describing the procedures and options for voting your shares. You
+should follow the instructions provided by your bank or brokerage firm. If you do not instruct your broker how to vote, your broker will vote your shares for you at his or her discretion on routine
+matters such as the election of directors and ratification of the independent registered public accounting firm. 
+Revocation 
+Any stockholder giving a proxy has the power to revoke the proxy, or change the proxy, at any time before the proxy is voted at the Annual Meeting by
+(i) sending another properly executed proxy bearing a later date or a written notice of revocation of the proxy to Corporate Secretary, Crocs, Inc., 6328 Monarch Park Place, Niwot,
+Colorado 80503 or (ii) voting in person at the Annual Meeting. 
+Attending the Annual Meeting 
+You are invited to personally attend the Annual Meeting. 
+Cost of Proxy Solicitation 
+We will bear the entire cost of this proxy solicitation. We may reimburse brokers, custodians, nominees and other fiduciaries for normal handling charges incurred
+for forwarding proxy materials to beneficial owners. Solicitation of proxies may be made personally or by mail or telephone by our directors, officers and other employees, who will receive no
+additional compensation for such services. 
+2 
+PROPOSAL 1—ELECTION OF DIRECTORS 
+Our board of directors currently consists of seven members divided into three classes, with each director elected to a three-year term. Under our
+amended and restated bylaws, each of our directors holds office until their successors have been elected and qualified or until their earlier death, resignation, disqualification or removal. We have
+divided the terms of office of the directors into three classes. Class I consists of Messrs. Retzloff and Stoffer, whose terms will expire at the Annual Meeting. Class II consists
+of Messrs. Croghan, Marks and Sharp, whose terms will expire at the annual meeting of stockholders to be held in 2007. Class III consists of Messrs. Smach and Snyder, whose terms
+will expire at the annual meeting of stockholders to be held in 2008. Messrs. Retzloff and Stoffer will not stand for re-election to the board of directors at the Annual Meeting. 
+Upon
+recommendation of the Governance and Nominating Committee, the board of directors has nominated Ronald L. Frasch and Marie Holman-Rao for election as Class I
+directors to serve for a three year term expiring at the 2009 annual meeting of stockholders. 
+Proxies
+cannot be voted for more than two nominees. Each of the director nominees has consented to serve for a three-year term. We do not contemplate that either of the
+nominees will be unable to stand for election, but should any nominee become unable to serve or will not serve for any reason, all proxies (except proxies marked to the contrary) will be voted for the
+election of a substitute nominee as our board of directors may recommend. 
+Class I Director Nominees 
+Ronald L. Frasch , age 57, has served as Vice Chairman and Chief Merchant of Saks Fifth Avenue, a division of Saks,
+Incorporated, since November 2004. From January 2004 to November 2004, Mr. Frasch was employed by Saks in a non-executive capacity. From April 2000 to January 2004,
+Mr. Frasch served as Chairman and Chief Executive Officer of Bergdorf Goodman (a subsidiary of Neiman Marcus Group, Inc.) and served as President of GFT North America (a subsidiary of
+Gruppo GFT, based in Turin, Italy, a global producer, marketer and distributor of fine men's and women's clothing, sportswear and furnishings) from 1996 to 2000. Mr. Frasch also served as
+President and Chief Executive Officer of Escada USA from 1994 to 1996. 
+Marie Holman-Rao , age 57, served as President, Design Services of Limited Brands, Inc. from 1997 to March 2006
+and currently serves Limited Brands, Inc. as a consultant. From 1993 until 1997, she served in various management positions at Gap, Inc., including, Executive Vice President, Design,
+Banana Republic, and President, Banana Republic in 1997. Ms. Holman-Rao also served as Senior Vice President and General Merchandise Manager at Ann Taylor from 1992 until 1993, and
+Vice President, Creative Development, Sport at Adrienne Vittadini, Inc. from 1989 to 1992. From 1986 to 1989, Ms. Holman-Rao served as President of Perry Ellis. 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" ALL 
+OF THE ABOVE-NAMED NOMINEES FOR DIRECTOR. 
+Information About Continuing Directors 
+Ronald R. Snyder ( Class III ), age 49, has served as our
+Chief Executive Officer since January 2005, was appointed as our President and a director in June 2004, and served as a consultant from October 2003 to June 2004. From
+March 2004 to December 2004, he was Chief Executive Officer of Vinci Corporation, a home theater equipment company. From April 2000 to December 2003, Mr. Snyder
+served as a senior executive with Flextronics International Ltd., a Nasdaq-listed electronics equipment manufacturer, where he was most recently President of the Flextronics Design division.
+Mr. Snyder joined Flextronics upon its acquisition of The Dii Group, Inc., of which he was a founder 
+3 
+and
+officer and where he had previously led various groups, including manufacturing operations, mergers and acquisitions, and sales and marketing. 
+Raymond D. Croghan ( Class II ), age 57, has served as a member of our board of
+directors since August 2004. Since 1999, Mr. Croghan has been retired. From 1991 to 1999, Mr. Croghan ran Croghan & Associates, Inc., a healthcare information
+technology consulting firm, which merged with Margolis Health Enterprise to form The TriZetto Group. Mr. Croghan serves on the boards of directors of several privately-held
+companies, and is a member of the board of trustees at Doane College in Crete, Nebraska. 
+Michael E. Marks ( Class II ), age 55, has served as a member of our board of
+directors since August 2004. On January 1, 2006, Mr. Marks joined Kohlberg Kravis Roberts & Co., a private equity firm, as a member of the firm. From January 1994 to
+January 1, 2006, Mr. Marks served as the Chief Executive
+Officer of Flextronics International Ltd. He was appointed Chairman of the Board of Flextronics effective upon his retirement as Chief Executive Officer on January 1, 2006, and he
+previously served as Chairman of the Board of Flextronics from 1993 to January 2003. Mr. Marks has served as a member of the board of directors of Flextronics since 1991, and also serves
+as a director of SanDisk Corporation and Schlumberger Limited. 
+Richard L. Sharp ( Class II ), age 59, has served as the Chairman of our board of
+directors since April 2005. From 1982 to 2002, Mr. Sharp served in various positions with Circuit City Stores, Inc., a consumer electronics and personal computer retailer, most
+recently as President from 1984 to 1997, Chief Executive Officer from 1986 to 2000 and Chairman of the Board from 1994 to 2002. He is also a director of Flextronics International Ltd. and
+Chairman of the Board of Carmax, Inc., the nation's largest specialty retailer of used cars and light trucks. 
+Thomas J. Smach ( Class III ), age 46, has served as a member of our board of
+directors since April 2005. Since January 2005, Mr. Smach has served as the Chief Financial Officer of Flextronics International Ltd. From April 2000 to
+December 2004, Mr. Smach served as Senior Vice President—Finance of Flextronics. From 1997 to April 2000, he served as the Senior Vice President, Chief Financial
+Officer and Treasurer of The Dii Group, Inc. Mr. Smach is a certified public accountant. Mr. Smach serves on the board of directors of ADVA AG Optical Networking. 
+EXECUTIVE OFFICERS 
+In addition to Ronald R. Snyder, our President and Chief Executive Officer, whose biographical information is disclosed above under "Information About Continuing
+Directors," our executive officers include the following individuals: 
+Name 
+Age 
+Position(s) 
+Peter S. Case 
+45 
+Chief Financial Officer, Senior Vice President—Finance and Treasurer 
+Michael C. Margolis 
+55 
+Vice President—Sales & Marketing 
+John P. McCarvel 
+50 
+Senior Vice President—Global Operations 
+Peter S. Case has served as our Chief Financial Officer and Treasurer since April 2006 and has served as our Senior Vice
+President—Finance since February 2006. Mr. Case served as the Executive Vice President, Chief Financial Officer and Treasurer of Ashworth, Inc., a Nasdaq-listed sports
+apparel and accessories company, from September 2005 to February 2006. From June 2000 to September 2005, Mr. Case served in several executive and managerial
+positions with Ashworth, including Director of Finance, Vice President of Finance, and Senior Vice President of Finance and Information Technology. 
+Michael C. Margolis has served as our Vice President—Sales & Marketing since January 2005, and led our sales
+group as an independent consultant from October 2003 to December 2004. From 
+4 
+May 1995
+to December 2004, Mr. Margolis was a founder and served as Vice President of Source Solutions, Inc., an apparel and merchandising company. He also successfully
+founded and ran a number of sporting goods and apparel companies prior to Source Solutions, and has extensive experience establishing and maintaining sales relationships with large retail chains. 
+John P. McCarvel has served as Senior Vice President—Global Operations since October 2005 and served as our Vice
+President—Asian & Australian Operations from January 2005 to September 2005, after providing consulting services to us during 2004. From October 2001 to
+January 2005, Mr. McCarvel served as Vice President for the Design, Test and Semiconductor division of Flextronics International Ltd., where he was responsible for building
+Flextronics's engineering infrastructure in Asia and growing Flextronics's business in the region. From 1999 to October 2001, he served as President of U.S. Operations and Senior Vice President
+of Worldwide Sales and Marketing for Singapore Technology Assembly Test Services Ltd., a semiconductor services company. He previously worked in executive level positions with Micron Custom
+Manufacturing Services, Inc. and The Dii Group, Inc. 
+BENEFICIAL OWNERSHIP OF OUR COMMON STOCK 
+The following table sets forth information with respect to the beneficial ownership of our common stock as of September 27, 2006 by: 
+• each
+person (or group of affiliated persons) who is known by us to own beneficially more than 5% of our voting securities;
+• each
+current director;
+• each
+of the named executive officers; and
+• all
+current directors and executive officers as a group; and 
+Beneficial
+ownership is determined in accordance with the SEC's rules. In computing percentage ownership of each person, shares of common stock subject to options held by that person
+that are currently exercisable or convertible, or exercisable or convertible within 60 days of September 27, 2006, are deemed to be outstanding and beneficially owned by that person. In
+addition, shares that are required to be issued by us to any person pursuant a restricted stock award agreement within 60 days of September 27, 2006 are also deemed to be outstanding and
+beneficially owned by that person. None of these shares, however, are deemed outstanding for the purpose of computing the percentage ownership of any other person. 
+Except
+as indicated in this table and pursuant to applicable community property laws, each stockholder named in the table has sole voting and investment power with respect to the shares
+set forth opposite such stockholder's name. Percentage ownership is based on 38,845,727 shares of our common stock outstanding on September 27, 2006. Unless otherwise indicated below, the
+address for each person who owns more than 5% of our voting securities and for each director and named 
+5 
+executive
+officer listed below is in care of Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503. 
+Beneficial 
+Ownership 
+Name of Beneficial Owner 
+Shares 
+Percent 
+5% Stockholders (1) : 
+Mazama Capital Management, Inc. (2) 
+3,019,005 
+7.8 
+% 
+Michael J. Roberts (3) 
+1,942,683 
+5.0 
+% 
+Non-Employee Directors: 
+Raymond D. Croghan (4) 
+337,853 
+* 
+Michael E. Marks (5) 
+1,969,500 
+5.1 
+% 
+Mark A. Retzloff (6) 
+439,513 
+1.1 
+% 
+Richard L. Sharp (7) 
+1,101,529 
+2.8 
+% 
+Thomas J. Smach (8) 
+177,063 
+* 
+Bradley L. Stoffer (9) 
+553,259 
+1.4 
+% 
+Named Executive Officers: 
+Ronald R. Snyder (10) 
+2,073,450 
+5.2 
+% 
+Lyndon V. "Duke" Hanson, III (11) 
+566,458 
+1.5 
+% 
+Michael C. Margolis (12) 
+502,143 
+1.3 
+% 
+John P. McCarvel (13) 
+246,796 
+* 
+Caryn D. Ellison (14) 
+256,985 
+* 
+All current directors and executive officers as a group (10 persons) (15) 
+7,521,106 
+18.5 
+% 
+* Less
+than 1%
+(1) Messrs. Marks
+and Snyder are listed below and also beneficially own more than 5% of our voting securities.
+(2) As
+reported in a Schedule 13G filed with the SEC. The address for Mazama Capital Management, Inc. is One Southwest Columbia Street, Suite 1500, Portland, Oregon 97258.
+(3) Shares
+beneficially owned include 1,306,682 shares of common stock owned by Sandstone Ventures, LLC. Mr. Roberts is the manager of Sandstone Ventures, LLC and exercises voting
+and investment power over the shares beneficially owned by Sandstone Ventures, LLC. Also includes 636,001 shares of common stock owned by the Michael J. Roberts Trust. Mr. Roberts is the
+trustee of the trust and exercises voting and investment power over all of the shares. The address for Sandstone Ventures, LLC and the Michael J. Roberts Trust is 6684 Gunpark Drive East, Boulder, CO,
+80301.
+(4) Shares
+beneficially owned includes 87,608 shares subject to options exercisable within 60 days of September 27, 2006. Also includes an aggregate of 18,480 shares of
+common stock beneficially owned by two trusts for the benefit of Mr. Croghan's two daughters. Mr. Croghan's spouse is the trustee of both trusts and she exercises sole voting and
+investment power over the shares. Mr. Croghan disclaims beneficial ownership of such shares.
+(5) Shares
+beneficially owned includes 87,608 shares subject to options exercisable within 60 days of September 27, 2006 and 1,757,633 shares beneficially owned by WB
+Investors, LLC. Mr. Marks is the managing member of WB Investors, LLC and exercises voting and investment power over the shares beneficially owned by WB Investors, LLC.
+(6) Shares
+beneficially owned includes 87,608 shares subject to options exercisable within 60 days of September 27, 2006 and 351,905 shares of our common stock owned by
+Retzloff Family Company, 
+6 
+LLLP.
+Mr. Retzloff is the managing partner of Retzloff Family Company, LLLP and exercises voting and investment power over all of these shares. 
+(7) Shares
+beneficially owned includes 175,215 shares subject to options exercisable within 60 days of September 27, 2006, 592,694 shares beneficially owned by The RLS Trust
+dated 9/14/05, 58,405 shares beneficially owned by BES & RS, LLC, 58,405 shares beneficially owned by EGG & RS, LLC, and 58,405 shares beneficially owned by RBG & RS, LLC.
+Mr. Sharp is the sole trustee of the trust and is the sole manager of each of BES & RS, LLC, EGG & RS, LLC, and RBG & RS, LLC and he exercises voting and investment power
+over all of the shares beneficially owned by the trust and each company. Shares beneficially owned also includes 58,405 shares of common stock beneficially owned by Mr. Sharp's spouse and
+Mr. Sharp disclaims beneficial ownership of such shares. The address for Mr. Sharp is 9020 Stony Point Parkway, #180, Richmond, VA 23235.
+(8) Shares
+beneficially owned include 146,013 shares subject to options exercisable within 60 days of September 27, 2006, 2,200 shares held as custodian for
+Mr. Smach's two children under the New York Uniform Gifts to Minors Act. Mr. Smach exercises voting and investment power over all of these shares.
+(9) Shares
+beneficially owned includes 87,608 shares subject to options exercisable within 60 days of September 27, 2006 and 232,826 shares held as custodian for
+Mr. Stoffer's two minor children under the Oregon Uniform Transfer to Minors Act. Mr. Stoffer exercises voting and investment power over all of these shares.
+(10) Shares
+beneficially owned includes 730,064 shares subject to options exercisable within 60 days of September 27, 2006 and 9,736 shares that will be issued pursuant to a
+restricted stock award agreement within 60 days of September 27, 2006. Also includes 170,499 shares held in the name of Union Bank of California, custodian f/b/o Ronald R. Snyder, 928
+shares held by Mr. Snyder's spouse, Kimberly Snyder, 15,652 shares that will be issued to Ms. Snyder pursuant to a restricted stock award agreement within 60 days of
+September 27, 2006, and 43,502 shares held as custodian for or in the name of Mr. Snyder's four minor children and stepchildren under the Colorado Uniform Transfer to Minors Act.
+Mr. Snyder exercises voting and investment power over all of these shares other than the shares held by Ms. Snyder. Mr. Snyder disclaims beneficial ownership of all shares held by
+Ms. Snyder.
+(11) Shares
+beneficially owned includes 44,291 shares subject to options exercisable within 60 days of September 27, 2006. Also includes 17,050 shares held of record by two
+trusts for the benefit of Mr. Hanson's two minor children. Mr. Hanson's brother, R. Douglas Hanson, is the trustee of both trusts and exercises sole voting and investment power over the
+shares. Mr. Hanson disclaims beneficial ownership of the shares held by the trusts.
+(12) Shares
+beneficially owned includes 280,345 shares subject to options exercisable within 60 days of September 27, 2006. Also includes 130,802 shares held in the name of
+Pershing LLC c/f Michael C. Margolis IRA, 6,626 shares held of record by two trusts for the benefit of Mr. Margolis' two daughters, and 6,341 shares held jointly with his spouse.
+Mr. Margolis exercises voting and investment power over all of these shares other than the shares held by the trusts. Mr. Margolis' spouse, Crystine J. Margolis, is the trustee of both
+trusts and exercises sole voting and investment power over the shares held by the trusts. Mr. Margolis disclaims beneficial ownership of the shares held by the trusts.
+(13) Shares
+beneficially owned includes 60,043 shares subject to options exercisable within 60 days of September 27, 2006. Also includes 108,958 shares held jointly with his
+spouse.
+(14) Shares
+beneficially owned includes 35,043 shares subject to options exercisable within 60 days of September 27, 2006 and 116,810 shares that will be issued pursuant to
+a restricted stock award agreement within 60 days of September 27, 2006. Also includes 4,674 shares held as custodian for 
+7 
+Ms. Ellison's
+two minor children under the Colorado Uniform Transfer to Minors Act. Ms. Ellison exercises voting and investment power over all of these shares. Ms. Ellison served
+as our Chief Financial Officer and Treasurer from November 2004 to April 2006. 
+(15) Shares
+beneficially owned includes 671,660 shares of common stock subject to options issued to six non-employee directors and 1,206,104 shares of common stock subject to
+options or restricted stock award agreements issued to four executive officers and one executive officer's spouse that are exercisable or issuable within 60 days of September 27, 2006. 
+BOARD OF DIRECTORS AND COMMITTEES OF THE BOARD 
+Board Composition 
+Our board of directors currently consists of seven members divided into three classes, with each director elected to a three-year term. Under our
+amended and restated bylaws, each of our directors holds office until their successors have been elected and qualified or until their earlier death, resignation, disqualification or removal. We have
+divided the terms of office of the directors into three classes. Class I currently consists of Messrs. Retzloff and Stoffer, whose terms will expire at the Annual Meeting.
+Class II consists of Messrs. Croghan, Marks and Sharp, whose terms will expire at the annual meeting of stockholders to be held in 2007. Class III consists of Messrs. Smach
+and Snyder, whose terms will expire at the annual meeting of stockholders to be held in 2008. 
+At
+each annual meeting of stockholders, the successors to directors whose terms expire at such meetings will be elected and will serve from the time of election and qualification until
+the third annual meeting following election and until their successors are duly elected and qualified. The current authorized number of directors is seven. The authorized number of directors may be
+changed by resolution of the board. Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each
+class will consist
+of one-third of the directors. Vacancies on the board can be filled by resolution of the board of directors. 
+Nasdaq
+listing standards require that our board of directors have a majority of independent directors. The board of directors has determined that all of the current members of our board
+of directors except Messrs. Snyder and Retzloff are independent directors as defined by Rule 4200(a)(15) of the Nasdaq listing standards. The board makes a determination regarding the
+independence of each director annually based on the relevant facts and circumstances. Applying these standards and the independence criteria defined by the Nasdaq listing standards, the board has made
+a subjective determination as to each independent director that no relationships exist that in the opinion of the board would interfere with the exercise of his or her independent judgment in carrying
+out the responsibilities of a director. In making these determinations, the directors reviewed and discussed information provided by the directors and us with regard to each director's business and
+personal activities as they may relate to our company and management. 
+During
+2005, the board of directors met three times and acted by written consent on various other occasions. All directors attended 75% or more of the meetings of the board of directors
+or the committees of the board on which they serve. We encourage, but do not require, our directors to attend the Annual Meeting. 
+Stockholders
+who wish to communicate with the board of directors or with specified individual directors may do so by mailing such written communication to: Corporate Secretary,
+Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503. The Corporate Secretary will review all correspondence, and will forward the board or an individual director a summary of the
+correspondence received and copies of correspondence that the Corporate Secretary determines requires the attention of the board or an individual director. The board or an individual director may at
+any time request copies and 
+8 
+review
+all correspondence received by the Corporate Secretary that is intended for the board or such individual director. 
+Board Committees 
+Our board of directors has the authority to appoint committees to perform certain management and administrative functions. Our board of directors has established
+the following committees: 
+Audit Committee. Messrs. Smach (Chairman) and Croghan are the current members of our audit committee. We intend to
+appoint a third independent director to the audit committee within the time
+period prescribed by the SEC and Nasdaq. The audit committee met three times in 2005. The functions of the audit committee include oversight of the integrity of our financial statements, our
+compliance with legal and regulatory requirements, the performance, qualifications and independence of our independent auditors and the performance of our internal audit function. Our audit committee
+is directly responsible, subject to stockholder ratification, for the appointment, retention, compensation, evaluation, termination and oversight of the work of any independent auditor engaged for the
+purpose of preparing or issuing an audit report or related work. The purpose and responsibilities of our audit committee are set forth in the Audit Committee Charter approved by our board of directors
+on June 30, 2005 and was amended and restated by our board of directors on September 20, 2006. The amended Audit Committee Charter is attached hereto as Appendix A. 
+All
+of the members of the audit committee are, or will be when appointed, independent as determined in accordance with Nasdaq rules and relevant federal securities laws and regulations.
+Our board of directors has determined that Mr. Smach qualifies as an "audit committee financial expert" as defined by the applicable regulations of the SEC. 
+Compensation Committee. Our compensation committee consists of Messrs. Marks (Chairman) and Croghan. The compensation
+committee met three times in 2005 and acted by written consent on various other occasions. The compensation committee has overall responsibility for evaluating and approving our executive officer
+incentive compensation, benefit, severance, equity-based or other compensation plans, policies and programs. The compensation committee is also responsible for producing an annual report on executive
+compensation for inclusion in our proxy statement. The purpose and responsibilities of our compensation committee are set forth in the Compensation Committee Charter approved by our board of directors
+on June 30, 2005. All of the members of the compensation committee are, or will be when appointed, independent as determined in accordance with Nasdaq listing standards and relevant federal
+securities laws and regulations. 
+9 
+Governance and Nominating Committee. Our governance and nominating committee consists of Messrs. Sharp (Chairman) and
+Stoffer. The governance and nominating committee did not meet in 2005. The governance and nominating committee assists our board of directors in promoting our best interests and the best interests of
+our stockholders through the implementation of sound corporate governance principles and practices. In furtherance of this purpose, the governance and nominating committee identifies individuals
+qualified to become board members and recommends to our board of directors the director nominees for the next annual meeting of stockholders. It also reviews the qualifications and independence of the
+members of our board of directors and its various committees on a regular basis and makes any recommendations the committee members may deem appropriate from time to time concerning any recommended
+changes in the composition of our board of directors and its committees. The governance and nominating committee also recommends to our board of directors the corporate governance guidelines and
+standards regarding the independence of outside directors applicable to us and reviews such guidelines and standards and the provisions of the governance and nominating committee charter on a regular
+basis to confirm that such guidelines, standards and charter remain consistent with sound corporate governance practices and with any legal or regulatory requirements of Nasdaq. The governance and
+nominating committee also monitors our board of directors and leads our board of directors in its annual review of our board of directors' performance. 
+The
+purpose and responsibilities of our governance and nominating committee are set forth in the Governance and Nominating Committee Charter approved by our board of directors on
+June 30, 2005. All of the members of the governance and nominating committee are, or will be when appointed, independent as determined in accordance with the Nasdaq listing standards. 
+Director Nomination Process 
+In identifying potential director candidates, the governance and nominating committee relies on recommendations from a number of sources, including current
+directors and officers. The governance and nominating committee may also hire outside consultants or search firms or other advisors to assist in identifying director candidates. The governance and
+nominating committee will consider director candidates recommended by stockholders on the same basis as it considers other candidates. Any stockholder wishing to recommend a candidate for
+consideration by the governance and nominating committee may do so by submitting a written recommendation to the committee in accordance with the procedures as set forth under "Stockholder Proposals
+and Nominations for 2007 Annual Meeting." 
+In
+evaluating a candidate for director, the governance and nominating committee considers, among other things, the candidate's judgment, knowledge, integrity, business and industry
+experience, and
+expertise which are likely to enhance our board of director's ability to manage and direct our affairs and business. The governance and nominating committee also takes into account independence
+requirements imposed by law or regulations (including the Nasdaq listing standards). In the case of director candidates recommended by stockholders, the governance and nominating committee may also
+consider the number of shares held by the recommending stockholder, the length of time that such shares have been held and the relationship, if any, between the recommending stockholder and the
+recommended director nominee. 
+Code of Business Conduct and Ethics and Committee Charters 
+We have adopted a Code of Business Conduct and Ethics that applies to all directors and employees, including our principal executive, financial and accounting
+officers. The Code of Business Conduct and Ethics is posted on our website at www.crocs.com. We intend to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure
+of amendments to, or waivers from, provisions of our Code of Business Conduct and Ethics that apply to our directors and principal executive, financial and accounting officers by posting such
+information on our website. The Audit Committee Charter, 
+10 
+Compensation
+Committee Charter and Governance and Nominating Committee Charter are also available on our website at www.crocs.com. Any person may request a copy of the Code of Business Conduct and
+Ethics or committee charters free of charge by writing: Corporate Secretary, Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503. 
+Compensation of Directors 
+Until September 2006, we granted our non-employee directors options to purchase 116,810 shares of our common stock upon their initial election
+to our board of directors and options to purchase an additional 29,203 shares of our common stock for each year of service. The Chairman of the board of directors also received options to purchase an
+additional 58,405 shares of our common stock upon his initial election as Chairman. The Chairman of the audit committee received options to purchase an additional 29,203 shares of common stock for
+each year of service. The options were granted at the fair market value of our common stock on the date of grant and have terms of seven years. Each option grant vests annually over four years, so
+long as such person remains a director. 
+In
+September 2006, our board of directors approved a new compensation arrangement for non-employee directors to be effective September 1, 2006. Under the new
+arrangement, directors who are not our employees receive annual cash compensation of $40,000, payable quarterly. Additional annual cash compensation is paid to the chairperson of each committee of the
+board of directors as follows: $10,000 for the Chair of the audit committee and $5,000 for each of the
+compensation committee Chair and the governance and nominating committee Chair. In addition, all directors are reimbursed for their reasonable out-of-pocket expenses incurred
+in attending meetings of the board of directors and its committees. 
+In
+addition, each new non-employee director will now be awarded options to purchase 40,000 shares of our common stock upon their initial election to our board of directors
+and continuing directors will be awarded options to purchase an additional 10,000 shares of our common stock for each year of service. The Chairman of the board of directors will now receive options
+to purchase an additional 10,000 shares of our common stock upon his initial election as Chairman. The options are granted at the fair market value of our common stock on the date of grant and have a
+term of seven years. Each option grant will vest annually over four years, so long as such person remains a director. 
+Compensation Committee Interlocks and Insider Participation 
+The board of directors formed our compensation committee on April 16, 2005 and Messrs. Croghan and Marks served as the members of our compensation
+committee for the remainder of our fiscal year ended December 31, 2005. No executive officer currently serves, or in the past has served, on the compensation committee or the board of directors
+of any other company of which any of the members of our compensation committee or any of our directors is an executive officer. 
+Prior
+to April 16, 2005, we did not have a compensation committee and Mr. Snyder was a member of our board of directors and was concurrently our Chief Executive Officer. As
+a member of the board, Mr. Snyder participated in deliberations of our board of directors concerning executive officer compensation. 
+EXECUTIVE COMPENSATION 
+The following summary compensation table indicates the cash and non-cash compensation paid to our Chief Executive Officer and our four other most
+highly compensated executive officers, collectively referred to as the "named executive officers," during our fiscal years ended December 31, 2004 and 2005. The compensation described in this
+table does not include medical, group life insurance or other benefits that are generally available to all of our salaried employees. 
+11 
+Summary Compensation Table 
+Long-Term 
+Compensation Awards 
+Annual 
+Compensation 
+Name and Principal Position 
+Restricted 
+Stock 
+Awards 
+Securities 
+Underlying 
+Options (#) 
+All Other 
+Compensation (1) 
+Year 
+Salary 
+Bonus 
+Ronald R. Snyder 
+Chief Executive Officer and President 
+2005 
+2004 
+$ 
+295,000 
+95,000 
+(3) 
+$ 
+345,000 
+90,000 
+$ 
+606,182 
+— 
+(2) 
+— 
+467,240 
+$ 
+— 
+500,000 
+(4) 
+Michael C. Margolis 
+Vice President—Sales & Marketing 
+2005 
+200,000 
+243,131 
+386,280 
+(5) 
+280,345 
+— 
+Caryn D. Ellison (6) 
+Vice President—Finance 
+2005 
+192,000 
+98,500 
+1,254,539 
+(7) 
+— 
+— 
+John P. McCarvel 
+Senior Vice President—Global Operations 
+2005 
+195,000 
+183,445 
+386,280 
+(8) 
+— 
+— 
+Lyndon V. "Duke" Hanson, III 
+Vice President—Customer Relations 
+2005 
+2004 
+125,000 
+95,300 
+74,625 
+15,150 
+— 
+— 
+58,405 
+— 
+— 
+105,420 
+(9) 
+(1) We
+have omitted perquisites and other personal benefits that do not exceed the lesser of $50,000 or 10% of the executive officer's annual salary and bonus disclosed in this table.
+(2) Includes
+a grant of 58,405 shares of common stock on September 1, 2005, and grants of 4,868 shares of common stock on each of October 1, November 1, and
+December 1, 2005 pursuant to the vesting terms under a restricted stock award agreement.
+(3) Mr. Snyder
+began his employment with us in June 2004. In accordance with an arrangement with Vinci Corporation, an entity controlled by Mr. Snyder, we paid an
+additional $65,000 (including payroll taxes) to Mr. Snyder for services performed by Mr. Snyder on behalf of Vinci Corporation while he was employed by us. Vinci Corporation reimbursed
+us for these expenses.
+(4) Includes
+1,500 Class B membership units with a fair market value of $150,000, which converted into 350,430 shares of our common stock, transferred to Mr. Snyder by our
+then-current President and a board member as compensation for consulting services rendered to us prior to the commencement of his employment with us in June 2004. Also includes
+1,500 Class B membership units with a fair market value of $150,000, which converted into 350,430 shares of our common stock, transferred to Mr. Snyder by Anthony Kruse, a holder of more
+than 5% of our common stock at the time of the transfer, as compensation for consulting services rendered to us prior to the commencement of his employment with us in June 2004. Also includes
+2,000 Class B membership units with a fair market value of $200,000, which converted into 467,240 shares of our common stock, and were granted to Mr. Snyder for consulting services.
+(5) Includes
+a grant of 77,796 shares of common stock on July 1, 2005 pursuant to the vesting terms under a restricted stock award agreement.
+(6) Ms. Ellison
+served as our Chief Financial Officer and Treasurer from November 2004 to April 2006.
+(7) Includes
+a grant of 116,810 shares of common stock on October 1, 2005 pursuant to the vesting terms under a restricted stock award agreement. 
+12 
+(8) Includes
+a grant of 77,796 shares of common stock on July 1, 2005 pursuant to the vesting terms under a restricted stock award agreement.
+(9) Includes
+sales commissions of $19,213. Also includes 500 Class B membership units with a fair market value of $86,207, which converted into 116,810 shares of our common stock,
+as compensation for services. 
+The
+following table sets forth certain information concerning option grants to the named executive officers during 2005. 
+Option Grants in 2005 
+Individual Grants 
+Potential Realizable 
+Value at Assumed 
+Rates of Stock Price 
+Appreciation for 
+Option Term 
+Percent of 
+Total 
+Options 
+Granted to 
+Employees in 
+Fiscal Year 
+Number of 
+Securities 
+Underlying 
+Options Granted 
+Name 
+Exercise 
+Price 
+Expiration 
+Date 
+5% 
+10% 
+Michael C. Margolis 
+280,345 
+22 
+% 
+$ 
+5.69 
+8/1/15 
+$ 
+7,994,539 
+$ 
+13,674,834 
+Lyndon V. "Duke" Hanson, III 
+58,405 
+5 
+% 
+$ 
+1.70 
+1/1/15 
+$ 
+1,898,559 
+$ 
+3,081,950 
+The
+options granted to Mr. Margolis were granted under our 2005 Equity Incentive Plan. The options have a term of 10 years and 25% of the options vested on
+January 1, 2006. The remaining 75% will vest in 36 equal monthly installments thereafter. 
+The
+options granted to Mr. Hanson were granted outside of our 2005 Equity Incentive Plan. The options have a term of 10 years and 25% of the options vested on
+January 1, 2006. The remaining 75% will vest in 36 equal monthly installments thereafter. The options are subject to termination prior to the expiration date in the event of the optionee's
+death, disability or termination of employment, as set forth in the option agreement. 
+All
+of the options were granted at an exercise price equal to the fair market value of our common stock on the date of grant, as determined in good faith by our board of directors.
+Because there was no public market for our stock prior to our initial public offering, our board of directors determined the fair market value of our common stock by considering a number of factors,
+including, but not limited to, our financial performance and prospects for our future growth and profitability. 
+The
+amounts shown on this table as the "Potential Realizable Value at Assumed Rates of Stock Price Appreciation for Option Term" represent hypothetical gains that could be achieved for
+the respective options if exercised at the end of the option term. These gains are based on assumed rates of stock price appreciation of 5% and 10%, compounded annually, which are required to be
+presented by SEC rules, and do not reflect our estimates or projections of the future price of our common stock. The gains are based on the assumed rates of appreciation presented, beginning on the
+grant date of the options, in the value of our common stock from the initial public offering price of $21.00 per share. The gains shown are net of the option exercise price, but do not include
+deductions for taxes or other expenses associated with the exercise. Actual gains, if any, on stock option exercises will depend on the future performance of our common stock, the option holder's
+continued employment through the option period, and the date on which the options are exercised. 
+The
+following table sets forth information concerning the number and value of exercisable and unexercisable options held by the named executive officers who held options as of
+December 31, 2005. The value of unexercised in-the-money options at December 31, 2005 represents an amount equal to the difference between the initial public
+offering price of $21.00 per share and the option exercise 
+13 
+price,
+multiplied by the number of unexercised in-the-money options. An option is in-the-money if the fair market value of the underlying shares exceeds
+the exercise price of the option. 
+Aggregated Option Exercises in 2005 and Year-End Option Values 
+Number of Securities 
+Underlying 
+Unexercised Options at 
+Fiscal Year-End 
+Value of Unexercised 
+In-The-Money 
+Options at 
+Fiscal Year-End (1) 
+Number of Shares Acquired on Exercise 
+Name 
+Value 
+Realized 
+Exercisable 
+Unexercisable 
+Exercisable 
+Unexercisable 
+Ronald R. Snyder 
+— 
+$ 
+— 
+146,013 
+321,227 
+$ 
+2,917,341 
+$ 
+6,418,116 
+Michael C. Margolis 
+— 
+— 
+280,345 
+(2) 
+— 
+4,292,083 
+— 
+Caryn D. Ellison 
+— 
+— 
+— 
+— 
+— 
+— 
+John P. McCarvel 
+— 
+— 
+— 
+— 
+— 
+— 
+Lyndon V. "Duke" Hanson, III 
+— 
+— 
+— 
+58,405 
+— 
+1,127,218 
+(1) The
+value of unexercised in-the-money options is based on our initial public offering price of $21.00 per share, minus the actual exercise price.
+(2) The
+options held by Mr. Margolis are immediately exercisable but are subject to vesting restrictions providing that, in the event any of the options are exercised prior to the
+time they are vested, the shares received upon such exercise will be subject to repurchase until the applicable vesting period has been satisfied. The vesting provisions are described above under
+"Option Grants in 2005." 
+Employment Agreements 
+Agreement with Peter Case 
+On February 2, 2005, we entered into an at-will employment arrangement with Peter Case, our Chief Financial Officer, Senior Vice
+President—Finance, and Treasurer, pursuant to which we will pay Mr. Case a monthly salary of $22,916.66, as well as a potential maximum performance based bonus of $41,249.99 per
+quarter. Under the terms of the arrangement, on February 7, 2006, we granted Mr. Case options to purchase 120,000 shares of our common stock at $21.00 per share, which was the initial
+public offering price of our common stock and the fair market value of our common stock at the time of grant. 
+Agreement with Caryn Ellison 
+On October 18, 2004, we entered into an at-will employment arrangement with Caryn Ellison, our Vice President—Finance and former
+Chief Financial Officer. The arrangement calls for Ms. Ellison to be compensated at a rate of $16,000 per month and provides that we will pay six months severance in the event
+Ms. Ellison's employment is terminated by us. The arrangement also provides for Ms. Ellison to receive annual equity awards of 116,810 shares of our common stock on each of
+October 1, 2006 and October 1, 2007. 
+REPORT OF THE COMPENSATION COMMITTEE 
+Compensation Philosophy 
+Our compensation philosophy is pay for performance. The compensation committee has designed compensation to establish a relationship between executive pay and the
+performance of the company and the individual executive. Executive performance will be defined and measured against the 
+14 
+company's
+business, strategic and financial goals, and individual performance objectives where appropriate. 
+Compensation Elements 
+Executives are compensated through a combination of base salary, incentive cash bonus and long-term share based incentive awards. 
+Base Salary 
+In determining base salary levels, the compensation committee considers the difficulty and scope of the job, the competitive market in which the company competes
+for talent, and the executive's performance. To determine the competitive market pay levels, the committee considers several factors, including executive and company performance, individual experience
+and pay levels at peer companies. 
+Incentive Bonus 
+The incentive cash bonus is intended to reward behavior and results that assist in meeting the company's business, strategic and financial goals. Performance
+criteria are set annually and may include company business objectives, company earnings or other financial criteria applicable to the executive, the company or both. Bonuses may exceed 100% of the
+executive's base salary and are payable at the full discretion of the board of directors. On August 3, 2006, the compensation committee approved an incentive bonus plan for certain officers of
+the company. As explained below, with respect to Ronald Snyder, the bonus plan ties incentive bonus payments to the company's earnings per share. Additional details of the bonus plan are set forth in
+our Current Report on Form 8-K filed with the SEC on August 3, 2006. 
+Long-Term Incentives 
+Long-term incentive compensation is intended to align the interests of the company's executives with the interests of the stockholders. It also allows
+the company to attract able individuals and to provide a means whereby those individuals, upon whom the responsibilities of the successful administration and management of the company are of
+importance, can acquire and maintain stock ownership, reinforcing their concern for the welfare of the company. Equity grants are made at the discretion of the compensation committee pursuant to the
+2005 Equity Incentive Plan. 
+CEO Compensation 
+Mr. Snyder's compensation is determined in accordance with the executive compensation philosophy established by the compensation committee. The
+compensation committee considers the company's overall performance (measured by business, strategic and financial goals), Mr. Snyder's individual performance, and peer company CEO compensation
+when determining Mr. Snyder's compensation. The compensation committee also looks at the relative fairness of the compensation of Mr. Snyder in relation to our other executives.
+Mr. Snyder's base salary in 2005 was $295,000. In 2005, Mr. Snyder also received a $345,000 cash bonus and restricted stock awards valued at $616,182. The bonus and restricted stock
+awards were granted to reward Mr. Snyder's significant role in the company's tremendous revenue and sales growth in 2005. The large restricted stock award also served to further align
+Mr. Snyder's financial interests with the interests of the stockholders. 
+As
+noted above, the compensation committee recently approved an incentive bonus plan for certain officers of the company, including Mr. Snyder. The first level of bonus ("Level 1
+Bonus") is contingent on the company achieving earnings per share of $0.78, excluding share-based compensation expense, for the year ending December 31, 2006, which would represent an increase
+of approximately 34.5% from the earnings per share recorded for the year ended December 31, 2005. The second level 
+15 
+of
+bonus ("Level 2 Bonus") is contingent on the company achieving earnings per share of $0.98, excluding share-based compensation expense, for the year ending December 31, 2006, which would
+represent an increase of approximately 69.0% from the earnings per share recorded for the year ended December 31, 2005. The bonus plan provides that Mr. Snyder will receive a cash bonus
+equal to 100% of his base salary if the Level 1 Bonus is achieved and will receive an additional 100% of his base salary if the Level 2 Bonus is achieved. Complete details of the bonus plan are set
+forth in our Current Report on Form 8-K filed with the SEC on August 3, 2006. 
+The
+Compensation Committee: 
+Michael
+E. Marks (Chairman) 
+Raymond D. Croghan 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+Ronald Snyder's spouse, Kimberly Snyder, was employed during 2005 as our Director of Apparel and Accessories, and received $81,250 in salary and $27,000 in bonus
+compensation in 2005. We also entered into a restricted stock award agreement with Ms. Snyder in 2005, pursuant to which Ms. Snyder received 15,419 shares of our common stock on
+October 1, 2005 and will receive an additional 15,652 shares of our common stock on October 1, 2006 and 15,653 shares of our common stock on October 1, 2007. 
+In
+April 2003, we entered into an oral distribution arrangement with St. Vrain Trading, LLC, an entity controlled by Mark Retzloff, a member of our board of directors, which
+granted St. Vrain the exclusive right to distribute our footwear products in Hawaii. Under the arrangement, St. Vrain purchased our footwear products at a discount to our standard wholesale prices. In
+May 2005, we purchased all of the assets of St. Vrain Trading for a net amount in cash equal to $55,563, and the assumption of a lease agreement and other liabilities. The purchased assets consisted
+of $81,707 in cash and accounts receivable, inventory valued at $39,910 and $1,750 of other assets. 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify our directors and executive officers, in addition to the indemnification provided for in our certificate of
+incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain expenses (including attorneys' fees), judgments, fines
+and settlement amounts incurred by any such person in any action or proceeding, including any action by us or in our right, arising out of such person's services as a director or executive officer of
+ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request. 
+SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE 
+Prior to our initial public offering in February 2006, our directors, executive officers and persons beneficially holding more than 10% of our common stock were
+not subject to the reporting requirements of Section 16 of the Securities Exchange Act of 1934. 
+REPORT OF THE AUDIT COMMITTEE 
+The audit committee has reviewed and discussed the audited financial statements for the fiscal year ended December 31, 2005 with the company's management
+and Deloitte & Touche LLP, the company's independent registered public accounting firm. Management is primarily responsible for the preparation, presentation and integrity of the financial
+statements, accounting and financial reporting principles and internal control over financial reporting. Deloitte & Touche LLP is responsible for 
+16 
+performing
+an independent audit of the financial statements in accordance with generally accepted auditing standards and for expressing opinions on the conformity of the financial statements with
+accounting principles generally accepted in the United States. 
+The
+audit committee has discussed with Deloitte & Touche LLP the matters required to be discussed by Statement on Auditing Standards No. 61, Communication with Audit Committees, as amended,
+and has received the written disclosures and the letter from Deloitte & Touche LLP required by
+Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees. The audit committee has also discussed with
+Deloitte & Touche LLP their independence. 
+Based
+on its reviews and discussions referred to above, the audit committee has recommended to the board of directors that the audited financial statements be included in the company's
+Annual Report on Form 10-K for the year ended December 31, 2005, for filing with the Securities and Exchange Commission. 
+The
+Audit Committee: 
+Thomas
+J. Smach (Chairman) 
+Raymond D. Croghan 
+PROPOSAL 2—RATIFICATION OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+The audit committee has appointed Deloitte & Touche LLP, as the independent registered public accounting firm for the fiscal year ending
+December 31, 2006. Deloitte & Touche LLP has served as our independent public accounting firm since 2005. We are not required to submit this appointment to the stockholders for approval
+but the board believes it is desirable as a matter of policy. 
+If
+the stockholders do not ratify this appointment, the audit committee will investigate the reasons for the rejection and consider other independent registered public accounting firms.
+Even if the appointment is ratified, the audit committee may, in its discretion, appoint a different independent registered public accounting firm. 
+PRINCIPAL ACCOUNTING FIRM FEES AND SERVICES 
+The following table sets forth the aggregate fees we paid to Deloitte & Touche LLP, our independent registered public accounting firm, and other member
+firms of Deloitte Touche Thomatsu and their respective affiliates, which we refer to collectively as Deloitte entities, for professional services provided during 2005. We did not employ a registered
+public accounting firm during 2004, however, in connection with the our initial public offering, Deloitte & Touche LLP performed audit procedures related to the years ended December 31,
+2002, 2003 and 2004, with the fees reflected in 2004 below. All fees paid to the Deloitte entities were pre-approved by the Audit Committee, which concluded that the provision of such
+services by the Deloitte entities was compatible with the maintenance of that firm's independence in the conduct of its auditing functions. 
+2005 
+2004 
+Audit fees (1) 
+$ 
+977,710 
+$ 
+350,984 
+Audit-related fees 
+— 
+— 
+Tax fees (2) 
+65,763 
+— 
+All other fees 
+— 
+— 
+Total fees 
+$ 
+1,043,473 
+$ 
+350,984 
+(1) Audit
+fees relate to professional services rendered in connection with the audit of our annual financial statements included in our Annual Report on Form 10-K and
+services attendant to, or 
+17 
+required
+by, statute or regulation, such as: (i) comfort letters, consents and other audit services related to SEC and other regulatory filings; and (ii) accounting consultation related
+to the audit. Audit fees consisted of audit work performed and billed through the date of this filing. 
+(2) Tax
+fees include professional services rendered in connection with tax compliance, tax advice, tax consulting and tax planning. 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" THE RATIFICATION OF DELOITTE & TOUCHE LLP AS THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR FISCAL YEAR 2006. 
+STOCKHOLDERS SHARING THE SAME ADDRESS 
+To reduce the expense of delivering duplicate proxy solicitation materials, we and some brokers may take advantage of the SEC's "householding" rules. These
+householding rules permit the delivery of only one set of proxy solicitation materials to stockholders who share the same address, unless otherwise requested. Any stockholder of record who shares an
+address with another stockholder of record and who has received only one set of proxy solicitation materials may receive a separate copy of those materials, without charge and/or request future
+delivery of separate materials upon writing the Corporate Secretary, Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503 or calling 303-848-7000. Likewise, any
+stockholder of record who shares an address with another stockholder of record and who has received multiple sets of proxy solicitation materials may request future delivery of a single copy of those
+materials upon writing the Corporate Secretary, Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503 or calling 303-848-7000. 
+STOCKHOLDER PROPOSALS AND NOMINATIONS FOR 2007 ANNUAL MEETING 
+Any proposal of a stockholder intended to be included in our proxy statement for the 2007 annual meeting of stockholders pursuant to Rule 14a-8
+of the SEC's rules, must be received by us no later than June 8, 2007, unless the date of our 2007 annual meeting is more than 30 days before or after October 30, 2007, in which
+case the proposal must be received a reasonable time before we begin to print and mail our proxy materials. All proposals should be addressed to the Corporate Secretary, Crocs, Inc., 6328
+Monarch Park Place, Niwot, Colorado 80503. 
+In
+order for a stockholder to nominate a candidate for director for election or to bring other business before the 2007 annual meeting, we must receive timely notice of the nomination or
+business in writing by the close of business not less than 90 days nor more than 120 days prior to the anniversary date of the immediately preceding annual meeting of stockholders.
+However, in the event that the annual meeting is called for a date that is not within 30 days before or 60 days after such anniversary date, notice by the stockholder to be timely must
+be received not earlier than the close of business on the 120th day prior to such annual meeting and not later than the close of business on the later of the 90th day prior to such annual meeting or
+the tenth day following the date on which notice of the date of the annual meeting was made public. 
+OTHER MATTERS 
+We do not intend to bring before the Annual Meeting any matters other than the proposals specifically described above and we know of no matters other than those
+to come before the Annual Meeting. If
+any other matters properly come before the Annual Meeting, it is the intention of the persons named in the accompanying proxy to vote such proxy in accordance with the recommendation of the our
+management on such matters, including any matters dealing with the conduct of the meeting. 
+18 
+Annex A 
+CROCS, INC. 
+Audit Committee Charter 
+Amended and Restated on September 20, 2006 
+Purpose 
+The purpose of the Audit Committee (the "Audit Committee") of the board of directors (the "Board") of Crocs, Inc. (the "Company") is to oversee the accounting and
+financial reporting processes of the Company and the audits of the financial statements of the Company. 
+The
+Audit Committee members are not professional accountants or auditors and their functions are not intended to duplicate or certify the activities of management or the independent
+auditor. While the Audit Committee has the responsibilities set forth in this Audit Committee Charter, it is not the duty of the Audit Committee to plan or conduct audits or to determine that the
+Company's financial statements are complete and accurate and are in accordance with generally accepted accounting principles. This is the responsibility of the Company's management and independent
+auditor. 
+Composition 
+The Audit Committee shall consist of at least three directors (subject to the applicable Nasdaq Stock Market rules relating to vacancies and public company
+phase-in provisions) appointed by, and serving
+at the discretion of, the Board. A director may serve on the Audit Committee only if the Board determines that he or she: 
+(a) is
+"independent" as that term is defined under the listing standards of The Nasdaq Stock Market;
+(b) meets
+the criteria for independence under Section 10A(m)(3) of the Securities Exchange Act of 1934, as amended (the "Exchange Act") and the rules and regulations of the Securities and
+Exchange Commission (the "SEC");
+(c) is
+free of any relationship that, in the opinion of the Board, would interfere with his or her individual exercise of independent judgment;
+(d) has
+not participated in the preparation of the financial statements of the Company or any current subsidiary of the Company at any time during the three years prior to such member's
+appointment to the Audit Committee; and
+(e) is
+able to read and understand fundamental financial statements, including a company's balance sheet, income statement, and cash flow statement. 
+At
+least one member of the Audit Committee shall have past employment experience in finance or accounting, requisite professional certification in accounting, or any other comparable
+experience or background that results in the individual's financial sophistication, including being or having been a chief executive officer, chief financial officer or other senior officer with
+financial oversight responsibilities. 
+The
+Audit Committee shall also endeavor to have at all times on the Audit Committee at least one member who satisfies the definition of an "audit committee financial expert" as defined
+by the SEC. 
+Audit
+Committee members may be removed or replaced by the Board from time to time in its discretion. 
+A-1 
+The
+Board shall appoint one member of the Audit Committee as chairperson. He or she shall be responsible for leadership of the Audit Committee, including overseeing the agenda, presiding
+over the meetings and reporting to the Board. 
+Responsibilities and Duties 
+In carrying out its responsibilities, the Audit Committee believes that its policies and procedures should remain flexible in order to best react to changing
+circumstances. The primary duties and responsibilities of the Audit Committee shall be as follows: 
+Oversight of Independent Auditor 
+1. Be
+directly responsible for the appointment, retention, compensation, evaluation, termination and oversight of the work of the Company's independent auditor (including resolution of
+disagreements between management and the independent auditor regarding financial reporting) engaged for the purpose of preparing or issuing an audit report or related work. The independent auditor
+shall report directly to the Audit Committee.
+2. Pre-approve
+all audit services and permissible non-audit services by the Company's independent auditor.
+3. Review
+and discuss representations from the independent auditor regarding:
+• critical
+accounting policies and practices to be used;
+• alternative
+treatments of financial information within generally accepted accounting principles that have been discussed with management, ramifications of the use of such
+alternative disclosures and treatments, and the treatment preferred by the independent auditor; and
+• other
+material written communications between the independent auditor and management, such as any management letter or schedule of unadjusted differences.
+4. Ensure
+regular rotation of the lead and concurring audit partners and other significant audit partners of the Company's independent auditor as required by law.
+5. Obtain
+and review a report from the independent auditor at least annually regarding all relationships between the independent auditor and the Company consistent with Independence
+Standards Board Standard No. 1.
+6. Evaluate
+the qualifications, performance and independence of the independent auditor, including:
+• actively
+engaging in a dialogue with the independent auditor regarding any relationship or services that may impact the auditor's objectivity and independence;
+• at
+least annually, evaluating the independence of the auditor, including assessing whether all relationships between the independent auditor and the Company and the
+provisions of permissive non-audit services are compatible with maintaining the auditor's independence;
+• considering
+whether the independent auditor's quality controls are adequate; and
+• reviewing
+and evaluating the qualifications and performance of the Company's independent auditor.
+7. On
+an annual basis, review the independent auditor's audit plan and discuss scope, staffing, locations, reliance upon management and general audit approach.
+8. Review
+with the independent auditor any audit problems or difficulties the auditor may have encountered and management's response thereto. Such reviews should include any difficulties 
+A-2 
+encountered
+in the course of the audit work, including any restrictions on the scope of activities or access to required information. 
+9. Discuss
+with the independent auditor the matters required to be discussed by Statement on Auditing Standards No. 61 related to the conduct of the audit.
+10. Confirm
+that none of the audit partners earn or receive compensation based on procuring engagements with the Company for providing products or services, other than audit, review or
+attest services. 
+Oversight of Financial Reporting, Internal Control and Disclosure Matters 
+11. Review
+and discuss with management and the independent auditor the Company's annual audited financial statements prior to the filing of the Company's Form 10-K, and recommend to the
+Board whether the audited financial statements should be included in the Company's Form 10-K.
+12. Review
+and discuss with management and the independent auditor, prior to the filing of the Company's Form 10-Q, the Company's quarterly financial statements, including the results of
+the independent auditor's review of the quarterly financial statements.
+13. Discuss
+with management and the independent auditor:
+• material
+financial reporting issues and judgments made in connection with the preparation of the Company's financial statements;
+• any
+material changes, including proposed changes, in the Company's selection or application of accounting principles;
+• any
+significant deficiencies or material weaknesses in the design or operation of internal controls that could adversely affect the Company's ability to record, process,
+summarize and report financial data; and
+• any
+fraud, whether or not material, that involves management or other employees who have a significant role in the Company's internal controls.
+14. Discuss
+with management the Company's policies and procedures with respect to earnings press releases, including the use of "pro forma" or "adjusted" non-GAAP information, as well as
+with respect to financial information and earnings guidance provided to analysts and rating agencies.
+15. Discuss
+with management and the independent auditor the effect of regulatory and accounting initiatives as well as off-balance sheet structures on the Company's financial statements.
+16. Review
+any significant reports to management prepared by the independent auditor or the internal audit personnel and management's responses.
+17. Discuss
+with management and the independent auditor any correspondence with regulators or governmental agencies and any published reports that raise material issues regarding the
+Company's financial statements or accounting policies.
+18. Consider
+the effectiveness of the company's internal control system, including information technology security and control.
+19. Understand
+the scope of internal and external auditors' review of internal control over financial reporting, and obtain reports on significant findings and recommendations, together
+with management's responses.
+20. Discuss
+with management and the independent auditor the independent auditor's attestation of management's report on internal controls. 
+A-3 
+Oversight of Compliance and Regulatory Matters 
+21. Establish
+and review periodically procedures for the receipt, retention and treatment of complaints received by the Company regarding accounting, internal accounting controls or
+auditing matters, and the confidential, anonymous submission by employees of concerns regarding questionable accounting or auditing matters. The Audit Committee has the authority to conduct any
+investigation appropriate to fulfilling its responsibilities and has direct access to the Company's outside counsel and anyone in the Company with respect thereto.
+22. Discuss
+with the independent auditor and management any other matters covered by Section 10A of the Exchange Act, as determined necessary or appropriate by the Audit Committee to
+ensure compliance. 
+Oversight of Internal Audit 
+23. Review
+with management and the internal audit director (or equivalent position) the charter, plans, activities, staffing, and organizational structure of the internal audit function.
+24. Ensure
+there are no unjustified restrictions or limitations to the scope, timing or extent of procedures planned and performed by the internal audit function.
+25. Review
+and concur on the appointment, replacement, or dismissal of the internal audit director (or equivalent position).
+26. Review
+the effectiveness of the internal audit function.
+27. On
+a regular basis, meet separately with the internal audit director (or equivalent position) to discuss any matters that the committee or internal audit believes should be discussed
+privately. 
+Other Responsibilities 
+28. Approve
+all related party transactions of the Company. The term "related party transaction" shall refer to transactions required to be disclosed pursuant to Item 404 of the SEC's
+Regulation S-K.
+29. Review
+with the full Board any material issues that arise with respect to the quality or integrity of the Company's financial statements, the Company's compliance with legal or
+regulatory requirements, and the performance and independence of the Company's independent auditor.
+30. Perform
+any other activities consistent with this Audit Committee Charter, the Company's Bylaws and governing law, as the Audit Committee or the Board deems necessary or appropriate.
+31. Monitor
+compliance with the Code of Business Conduct and Ethics. 
+Committee Administration 
+32. Prepare
+the Audit Committee report required by the rules of the SEC to be included in the Company's annual proxy statement.
+33. Meet
+periodically with management and the independent auditor in separate executive sessions.
+34. Review
+the Audit Committee's own performance annually.
+35. Review
+and reassess the adequacy of this Audit Committee Charter annually and recommend any proposed changes to the Board and have the Audit Committee Charter published at least every
+three years in accordance with SEC regulations. 
+A-4 
+Outside Advisers 
+The Audit Committee shall have the authority to retain independent counsel and other legal, accounting or other advisors as the Audit Committee determines
+necessary to carry out its duties. The Company shall provide funding, as determined by the Audit Committee, for payment of compensation to any advisors employed by the Audit Committee and for payment
+of ordinary administrative expenses that are necessary for the Audit Committee to carry out its duties. 
+Delegation of Duties 
+To the extent permissible under applicable laws and regulations, the Audit Committee may delegate its responsibilities to one or more members of the Audit
+Committee. 
+Meetings 
+The Audit Committee shall meet at least four times annually, and special meetings shall be called as necessary. 
+The
+Audit Committee may request any officer or employee of the Company or the Company's outside counsel or independent auditor to attend a meeting of the Audit Committee or to meet with
+any members of, or consultants to, the Audit Committee. 
+All
+meetings of the Audit Committee shall be held pursuant to the Bylaws of the Company with regard to notice and waiver thereof, and written minutes of each meeting shall be duly filed
+in the Company's
+records. A majority of the members of the Audit Committee shall constitute a quorum of the Audit Committee. 
+Education 
+The Company is responsible for providing the Audit Committee with educational resources related to accounting principles and procedures, current accounting topics
+pertinent to the Company and other material as may be requested by the Audit Committee. The Company shall assist the Audit Committee in maintaining appropriate financial literacy. 
+Authority 
+By adopting this Charter, the Board delegates to the Audit Committee full authority in its discretion to: 
+(a) perform
+each of the responsibilities of the Audit Committee described above;
+(b) appoint
+a chair of the Audit Committee, unless a chair is designated by the Board;
+(c) engage
+independent counsel and other advisers as the Audit Committee determines necessary to carry out its responsibilities; and
+(d) cause
+the officers of the corporation to provide such funding as the Audit Committee shall determine to be appropriate for payment of compensation to the Company's independent auditor
+and any legal counsel or other advisers engaged by the Audit Committee, and payment of ordinary administrative expenses of the Audit Committee that are necessary or appropriate in carrying out its
+duties. 
+A-5 
+Annual Meeting Proxy Card 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR THE PROPOSALS BELOW. THIS PROXY IS SOLICITED BY THE BOARD OF DIRECTORS. 
+A. Election of Directors 
+1. The
+Board of Directors recommends a vote FOR the listed nominees. 
+For 
+Withhold 
+Ronald L. Frasch 
+o 
+o 
+Marie Holman-Rao 
+o 
+o 
+B. Issues 
+The
+Board of Directors recommends a vote FOR the following proposal. 
+For 
+Against 
+Abstain 
+1. 
+Ratification of the appointment of Deloitte & Touche LLP as our independent auditors for fiscal year 2006. 
+o 
+o 
+o 
+2. 
+In their discretion, to transact other business as may properly come before the meeting or any postponement or adjournment thereof. 
+C. Authorized Signatures—Sign Here—This section must be completed for your instructions to be executed. 
+The
+undersigned hereby revokes all proxies heretofore given by the undersigned for said meeting. The proxy may be revoked prior to its exercise. 
+Note:
+Please sign exactly as your name or names appear hereon. When shares are held by joint tenants, both should sign. When signing as attorney, executor, administrator, trustee or guardian, please
+give full title as such. If a corporation, please sign in full corporate name by President or other authorized officer. If a partnership, please sign in partnership name by authorized person. 
+Name: 
+Date: 
+Proxy—Crocs, Inc. 
+PROXY SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS FOR THE ANNUAL MEETING OF STOCKHOLDERS ON OCTOBER 30, 2006 
+The
+undersigned hereby appoints Ronald R. Snyder and Peter S. Case, and each of them, with power of substitution, as proxies of the undersigned, to attend the Annual Meeting of Stockholders of Crocs,
+Inc. (the "Company"), to be held at the Beaver Creek Lodge, 26 Avondale Lane, Beaver Creek, Colorado, on October 30, 2006 at 9:00 a.m., Mountain time, and all adjournments thereof, and to vote, as
+indicated on the reverse side, the shares of Common Stock of the Company which the undersigned is entitled to vote with all the powers the undersigned would possess if present at the meeting. 
+This proxy, when properly executed, will be voted in the manner directed herein by the undersigned stockholder(s). If no specific direction is given, this proxy will be voted
+FOR each of the proposals. 
+PLEASE DATE AND SIGN ON THE REVERSE SIDE AND MAIL PROMPTLY IN THE ENCLOSED ENVELOPE. 
+(Continued and to be signed on reverse side.) 
+QuickLinks 
+NOTICE OF THE 2006 ANNUAL MEETING OF STOCKHOLDERS TO BE HELD OCTOBER 30, 2006 
+2006 ANNUAL MEETING OF STOCKHOLDERS PROXY STATEMENT 
+GENERAL INFORMATION REGARDING ANNUAL MEETING 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" ALL OF THE ABOVE-NAMED NOMINEES FOR DIRECTOR. 
+EXECUTIVE OFFICERS 
+BENEFICIAL OWNERSHIP OF OUR COMMON STOCK 
+BOARD OF DIRECTORS AND COMMITTEES OF THE BOARD 
+EXECUTIVE COMPENSATION 
+Aggregated Option Exercises in 2005 and Year-End Option Values 
+REPORT OF THE COMPENSATION COMMITTEE 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE 
+REPORT OF THE AUDIT COMMITTEE 
+PRINCIPAL ACCOUNTING FIRM FEES AND SERVICES 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" THE RATIFICATION OF DELOITTE & TOUCHE LLP AS THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR FISCAL YEAR 2006. 
+STOCKHOLDERS SHARING THE SAME ADDRESS 
+STOCKHOLDER PROPOSALS AND NOMINATIONS FOR 2007 ANNUAL MEETING 
+OTHER MATTERS 
+CROCS, INC. Audit Committee Charter Amended and Restated on September 20, 2006
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001047469-06-012548/proxy_rpt.txt b/raw/proxies/0001334036/0001047469-06-012548/proxy_rpt.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e2ddbafa54d884cb80bc56b453ca936ae4edca10
--- /dev/null
+++ b/raw/proxies/0001334036/0001047469-06-012548/proxy_rpt.txt
@@ -0,0 +1,14 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+Ronald Snyder's spouse, Kimberly Snyder, was employed during 2005 as our Director of Apparel and Accessories, and received $81,250 in salary and $27,000 in bonus
+compensation in 2005. We also entered into a restricted stock award agreement with Ms. Snyder in 2005, pursuant to which Ms. Snyder received 15,419 shares of our common stock on
+October 1, 2005 and will receive an additional 15,652 shares of our common stock on October 1, 2006 and 15,653 shares of our common stock on October 1, 2007. 
+In
+April 2003, we entered into an oral distribution arrangement with St. Vrain Trading, LLC, an entity controlled by Mark Retzloff, a member of our board of directors, which
+granted St. Vrain the exclusive right to distribute our footwear products in Hawaii. Under the arrangement, St. Vrain purchased our footwear products at a discount to our standard wholesale prices. In
+May 2005, we purchased all of the assets of St. Vrain Trading for a net amount in cash equal to $55,563, and the assumption of a lease agreement and other liabilities. The purchased assets consisted
+of $81,707 in cash and accounts receivable, inventory valued at $39,910 and $1,750 of other assets. 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify our directors and executive officers, in addition to the indemnification provided for in our certificate of
+incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain expenses (including attorneys' fees), judgments, fines
+and settlement amounts incurred by any such person in any action or proceeding, including any action by us or in our right, arising out of such person's services as a director or executive officer of
+ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request.
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001047469-08-005543/proxy.txt b/raw/proxies/0001334036/0001047469-08-005543/proxy.txt
new file mode 100644
index 0000000000000000000000000000000000000000..76fb0403be55b70ecd8e57439727418b5051e8ec
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+DEF 14A
+1
+a2185158zdef14a.htm
+DEF 14A
+QuickLinks 
+-- Click here to rapidly navigate through this document 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+SCHEDULE 14A 
+Proxy
+Statement Pursuant to Section 14(a) of 
+the Securities Exchange Act of 1934 
+Filed by the Registrant ý 
+Filed by a Party other than the Registrant o 
+Check the appropriate box: 
+o 
+Preliminary Proxy Statement 
+o 
+Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2)) 
+ý 
+Definitive Proxy Statement 
+o 
+Definitive Additional Materials 
+o 
+Soliciting Material Pursuant to §240.14a-12 
+CROCS, INC. 
+(Name of Registrant as Specified In Its Charter) 
+(Name of Person(s) Filing Proxy Statement, if other than the Registrant) 
+Payment of Filing Fee (Check the appropriate box): 
+ý 
+No fee required. 
+o 
+Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11. 
+(1) 
+Title of each class of securities to which transaction applies: 
+(2) 
+Aggregate number of securities to which transaction applies: 
+(3) 
+Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined): 
+(4) 
+Proposed maximum aggregate value of transaction: 
+(5) 
+Total fee paid: 
+o 
+Fee paid previously with preliminary materials. 
+o 
+Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or
+Schedule and the date of its filing. 
+(1) 
+Amount Previously Paid: 
+(2) 
+Form, Schedule or Registration Statement No.: 
+(3) 
+Filing Party: 
+(4) 
+Date Filed: 
+Crocs, Inc. 
+6328 Monarch Park Place 
+Niwot, Colorado 80503 
+NOTICE OF THE 2008 ANNUAL MEETING OF STOCKHOLDERS TO 
+BE HELD JUNE 26, 2008 
+To
+the Stockholders of Crocs, Inc.: 
+We
+will hold the 2008 Annual Meeting of Stockholders of Crocs, Inc. at the Beaver Creek Lodge, 26 Avondale Lane, Beaver Creek, Colorado, on June 26, 2008, at
+1:00 p.m. Mountain Time. 
+The
+meeting's purpose is to: 
+1. elect
+two Class III directors;
+2. ratify
+the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for fiscal year 2008; and
+3. consider
+any other matters that properly come before the meeting or any postponement or adjournment thereof. 
+Only
+stockholders of record of our common stock at the close of business on April 28, 2008 are entitled to receive notice of and to vote at the meeting. Each share of common stock
+is entitled to one vote. 
+A
+list of the stockholders entitled to vote at the meeting will be available for examination at the meeting by any stockholder for any purpose relevant to the meeting. The list will also
+be available on the same basis for ten days prior to the meeting at our principal executive office, 6328 Monarch Park Place, Niwot, Colorado 80503. 
+All
+stockholders are cordially invited to attend the meeting in person. Whether or not you plan to attend the meeting in person, please vote your shares, as instructed in the Notice of
+Internet Availability of Proxy Materials, over the Internet, or by telephone after your receipt of hard copies of the proxy materials, as promptly as possible. You may also request a paper proxy card,
+which will include a reply envelope, to submit your vote by mail, as described in the Notice of Internet Availability of Proxy Materials. Stockholders who are present at the Annual Meeting may
+withdraw their proxy and vote in person if they so desire. 
+BY ORDER OF THE BOARD OF DIRECTORS 
+Ronald R. Snyder 
+President and Chief Executive Officer 
+Niwot,
+Colorado 
+April 29, 2008 
+1 
+Crocs, Inc. 
+6328 Monarch Park Place 
+Niwot, Colorado 80503 
+2008 ANNUAL MEETING OF STOCKHOLDERS 
+PROXY STATEMENT 
+This proxy statement was first made available to stockholders on or about April 29, 2008. It is furnished to stockholders of Crocs, Inc., a Delaware
+corporation, in connection with the solicitation of proxies by our Board of Directors. The proxies being solicited will be voted at the 2008 Annual Meeting of Stockholders (the "Annual Meeting"), to
+be held on June 26, 2008 at 1:00 p.m., Mountain time, at the Beaver Creek Lodge, 26 Avondale Lane, Beaver Creek, Colorado, or at any postponement or adjournment thereof, for the purpose
+of voting on proposals as set forth herein as well as other business matters which may properly come before the meeting. 
+Under
+new rules of the Securities and Exchange Commission, we are furnishing proxy materials to our stockholders on the Internet, rather than mailing printed copies to our stockholders.
+If you received a Notice of Internet Availability of Proxy Materials by mail, you will not receive a printed copy of the proxy materials unless you request one as instructed in that notice. Instead,
+the Notice of Internet Availability of Proxy Materials will instruct you as to how you may access and review the proxy
+materials on the Internet. If you received a Notice of Internet Availability of Proxy Materials by mail and would like to receive a printed copy of our proxy materials, please follow the instructions
+included in the Notice of Internet Availability of Proxy Materials. 
+GENERAL INFORMATION REGARDING ANNUAL MEETING 
+Record Date 
+Stockholders of record at the close of business on April 28, 2008 are entitled to notice of and to vote at the Annual Meeting. On the record date, there
+were 83,218,542 shares of our common stock outstanding. Each such share is entitled to one vote on each matter submitted to a vote at the Annual Meeting. 
+Quorum Requirements 
+A quorum is required to conduct the Annual Meeting. The holders of a majority of the outstanding shares entitled to vote generally in the election of directors
+must be present in person or by proxy at the Annual Meeting in order for a quorum to exist. Abstentions and broker non-votes count as present and voting for purposes of determining a
+quorum. A broker non-vote occurs when a broker returns a proxy card but does not vote on one or more matters because the broker does not have the authority to do so without instructions
+from the beneficial owner. Shares represented by proxies that are marked WITHHOLD with respect to the election of directors will be counted as present in determining whether there is a quorum. 
+2 
+Vote Requirements 
+If a quorum is present at the Annual Meeting, the following vote is required for approval of each matter to be voted on: 
+Election of Directors: The election of the directors nominated will require a plurality of the votes cast in person or by
+proxy at the Annual Meeting. "Plurality" means that the nominees who receive the largest number of votes cast are elected as directors up to the maximum number of directors to be elected at the Annual
+Meeting. Consequently, proxies marked WITHHOLD and broker non-votes will have no impact on the election of directors. Cumulative voting is not permitted. 
+Ratification of Appointment of Deloitte & Touche LLP: The affirmative vote of the holders of a majority of the
+shares of our common stock present in person or by proxy and entitled to vote at the Annual Meeting is required for the ratification of the appointment of Deloitte & Touche LLP as our
+independent registered public accounting firm for fiscal year 2008. Proxies marked ABSTAIN will have the effect of voting against this proposal. Broker non-votes will have no impact on the
+proposal. 
+Other Proposals: With respect to any other matters properly brought before the Annual Meeting, the affirmative vote of a
+majority of the shares of common stock present in person or by proxy and entitled to vote on the matter will be the act of the stockholders. Broker non-votes will have no effect on these
+proposals, and abstentions will have the effect of voting against these proposals. 
+Your Proxy 
+Whether or not you are able to personally attend the Annual Meeting, you are encouraged to vote your shares as instructed in the Notice of Internet Availability
+of Proxy Materials. Shares represented by properly executed methods, and not revoked prior to the Annual Meeting, will be voted at the Annual Meeting as directed in the proxy. If no directions are specified, such proxies will
+be voted FOR each of the proposals described in this proxy statement and in the best judgment of the proxy holders as to other
+matters that may properly come before the Annual Meeting. 
+If
+your shares are held in the name of a bank or brokerage firm, your bank or broker will send you a separate package describing the procedures and options for voting your shares. You
+should follow the instructions provided by your bank or brokerage firm. If you do not instruct your broker how to vote, your broker will vote your shares for you at his or her discretion on routine
+matters such as the election of directors and ratification of the independent registered public accounting firm. 
+Revocation 
+Any stockholder giving a proxy has the power to revoke the proxy, or change the proxy, at any time before the proxy is voted at the Annual Meeting by
+(i) re-voting online at www.proxyvote.com, (ii) sending another properly executed proxy bearing a later date or a written notice of revocation of the proxy to Corporate
+Secretary, Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503 or (iii) voting in person at the Annual Meeting. 
+Attending the Annual Meeting 
+You are invited to personally attend the Annual Meeting. 
+Cost of Proxy Solicitation 
+We will bear the entire cost of this proxy solicitation. We may reimburse brokers, custodians, nominees and other fiduciaries for normal handling charges incurred
+for forwarding proxy materials to beneficial owners. Solicitation of proxies may be made personally or by mail or telephone by our directors, officers and other employees, who will receive no
+additional compensation for such services. 
+3 
+PROPOSAL 1—ELECTION OF DIRECTORS 
+Our Board of Directors currently consists of seven members divided into three classes, with each director elected to a three-year term. Under our
+amended and restated bylaws, each of our directors holds office until his or her successor has been elected and qualified or until such director's earlier death, resignation, disqualification or
+removal. We have divided the terms of office of the directors into three classes. Class I consists of Ronald L. Frasch and Marie Holman-Rao, whose terms will expire at the annual
+meeting to be held in 2009. Class II consists of Raymond D. Croghan, Michael E. Marks and Richard L. Sharp, whose terms will expire at the annual meeting to be held in 2010. Class III
+consists of Thomas J. Smach and Ronald R. Snyder,
+whose terms will expire at the Annual Meeting. Messrs. Smach and Snyder will stand for re-election to the Board of Directors at the Annual Meeting. 
+Upon
+recommendation of the Governance and Nominating Committee, the Board of Directors has nominated Messrs. Smach and Snyder for election as Class III directors to serve
+for a three year term expiring at the 2011 annual meeting of stockholders. 
+Proxies
+cannot vote for more than two nominees. Each of the director nominees has consented to serve for a three-year term. We do not contemplate that any of the nominees
+will be unable to stand for election, but should any nominee become unable to serve or will not serve for any reason, all proxies (except proxies marked to the contrary) will be voted for the election
+of a substitute nominee as our Board of Directors may recommend. 
+Class III Director Nominees 
+Thomas J. Smach ( Class III ), age 47, has served as a member
+of our Board of Directors since April 2005. Since January 2005, Mr. Smach has served as the Chief Financial Officer of Flextronics International Ltd., a NASDAQ-listed electronics
+equipment manufacturer ("Flextronics"). From April 2000 to December 2004, Mr. Smach served as Senior Vice President—Finance of Flextronics. From 1997 to April 2000, he served as the
+Senior Vice President, Chief Financial Officer and Treasurer of The Dii Group, Inc., a value-added electronics design and manufacturing service provider. Mr. Smach is a certified public
+accountant and also serves on the Board of Directors of ADVA AG Optical Networking and BMC Software. 
+Ronald R. Snyder ( Class III ), age 51, has served as our Chief Executive Officer
+since January 2005, was appointed as our President and a director in June 2004, and served as a consultant from October 2003 to June 2004. From March 2004 to December 2004, he was Chief Executive
+Officer of Vinci Corporation, a home theater equipment company. From April 2000 to December 2003, Mr. Snyder served as a senior executive with Flextronics, where he was most recently President
+of the Flextronics design division. Mr. Snyder joined Flextronics upon its acquisition of The Dii Group, Inc., of which he was a founder and an officer and where he had previously led
+various groups, including manufacturing operations, mergers and acquisitions, and sales and marketing. 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" ALL 
+OF THE ABOVE-NAMED NOMINEES FOR DIRECTOR. 
+Information About Continuing Directors 
+Raymond D. Croghan ( Class II ), age 58, has served as a
+member of our Board of Directors since August 2004. Since 1999, Mr. Croghan has been retired. From 1991 to 1999, Mr. Croghan ran Croghan & Associates, Inc., a healthcare
+information technology consulting firm, which merged with Margolis Health Enterprise to form The TriZetto Group. Mr. Croghan serves on the boards of directors of several
+privately-held companies. 
+Michael E. Marks ( Class II ), age 57, has served as a member of our Board of
+Directors since August 2004. Mr. Marks manages a private equity fund, Riverwood Capital LLC, which invests in 
+4 
+rapidly
+growing private companies in North America and emerging markets. Before founding Riverwood Capital, LLC, he served as a member and then a senior advisor to Kohlberg Kravis
+Roberts & Co., a private equity firm. Earlier, he served as CEO of Flextronics from January 1994 to January 2006. Mr. Marks currently sits on the boards of SanDisk Corporation,
+Schlumberger Ltd. and Sun MicroSystems, Inc. 
+Richard L. Sharp ( Class II ), age 61, has served as the Chairman of our Board of
+Directors since April 2005. From 1982 to 2002, Mr. Sharp served in various positions with Circuit City Stores, Inc., a consumer electronics and personal computer retailer, most recently
+as President from 1984 to 1997, Chief Executive Officer from 1986 to 2000 and Chairman of the Board from 1994 to 2002. Mr. Sharp served as Chairman and Chief Executive Officer of
+CarMax, Inc., the nation's largest specialty retailer of used cars and light trucks, from 1994 to 2000 and Chairman from October 2002 to June 2007. He is also a director of Flextronics. 
+Ronald L. Frasch ( Class I ), age 59, has served as a member of our Board of
+Directors since October 2006. Since February 2007, Mr. Frasch has served as President and Chief Merchandising Officer of Saks Fifth Avenue, a division of Saks, Incorporated, and a
+NYSE-listed luxury fashion retailer. He held the post of Vice Chairman and Chief Merchant of Saks Fifth Avenue from November 2004 until January 2007. From January 2004 to November 2004,
+Mr. Frasch was employed by Saks in a non-executive capacity. From April 2000 to January 2004, Mr. Frasch served as Chairman and Chief Executive Officer of Bergdorf Goodman (a
+subsidiary of Neiman Marcus Group, Inc.) and served as President of GFT North America (a subsidiary of Gruppo GFT, based in Turin, Italy, a global producer, marketer and distributor of fine
+men's and women's clothing, sportswear and furnishings) from 1996 to 2000. Mr. Frasch also served as President and Chief Executive Officer of Escada USA from 1994 to 1996. 
+Marie Holman-Rao ( Class I ), age 59, has served as a member of our Board
+of Directors since October 2006. Since March 2006, Ms. Holman-Rao has served as Chief Executive Officer and President of M. Rao Design Consulting Group. From 1997 to March 2006,
+Ms. Holman-Rao served as President, Design Services of Limited Brands, Inc., a NYSE-listed specialty retailer. From 1993 until 1997, she served in various
+management positions at Gap, Inc., including Executive Vice President, Design, Banana Republic and President, Banana Republic in 1997. Ms. Holman-Rao also served as Senior
+Vice President and General Merchandise Manager at Ann Taylor from 1992 until 1993 and as Vice President, Creative Development, Sport at Adrienne Vittadini, Inc. from 1989 to 1992. From 1986 to
+1989, Ms. Holman-Rao served as President of Perry Ellis. 
+EXECUTIVE OFFICERS 
+In addition to Ronald R. Snyder, our President and Chief Executive Officer, whose biographical information is disclosed above under "Election of Directors," our
+executive officers as of March 31, 2008 include the following individuals: 
+Name 
+Age 
+Position(s) 
+John P. McCarvel 
+51 
+Chief Operations Officer and Executive Vice President 
+Russell C. Hammer 
+51 
+Chief Financial Officer, Senior Vice President—Finance and Treasurer 
+Michael C. Margolis 
+56 
+Vice President—Sales & Marketing 
+John P. McCarvel has served as our Chief Operating Officer and Executive Vice President since February 2007. Previously,
+Mr. McCarvel served as our Senior Vice President—Global Operations from October 2005 to February 2007 and as our Vice President—Asian & Australian Operations from
+January 2005 to September 2005, after providing consulting services to us during 2004. From October 2001 to January 2005, Mr. McCarvel served as Vice President for the Design, Test and
+Semiconductor 
+5 
+division
+of Flextronics, where he was responsible for building Flextronics' engineering infrastructure in Asia and growing Flextronics' business in the region. From 1999 to October 2001, he served as
+President of U.S. Operations and Senior Vice President of Worldwide Sales and Marketing for Singapore Technology Assembly Test Services Ltd., a semiconductor services company. He previously
+worked in executive level positions with Micron Custom Manufacturing Services, Inc., a manufacturer of electronic products for computing and digital applications, and The Dii Group, Inc. 
+Russell C. Hammer has served as our Chief Financial Officer, Senior Vice President of Finance and Treasurer since January 2008. Prior to
+joining Crocs, Mr. Hammer was employed for 29 years at Motorola, Inc., a global supplier of wireless handsets and mobile communication products. During his employment with Motorola,
+Mr. Hammer served as Chief Financial Officer and Corporate Vice President of Motorola's Connected Home Solutions Business from April 2005 to August 2007. From August 2002 to March 2005, he
+served as Chief Audit Officer for Motorola, and from August 1998 to July 2002 he served as Chief Financial Officer, Asia Cellular Subscriber Business of Motorola. Mr. Hammer also served in
+other executive roles for Motorola's various divisions during his tenure with the company. 
+Michael C. Margolis has served as our Vice President—Sales & Marketing since January 2005 and led our sales group as an
+independent consultant from October 2003 to December 2004. From May 1995 to December 2004, Mr. Margolis was a founder and served as Vice President of Source Solutions, Inc., an apparel
+and merchandising company. He also successfully founded and ran a number of sporting goods and apparel companies prior to Source Solutions and has extensive experience establishing and maintaining
+sales relationships with large retail chains. 
+BENEFICIAL OWNERSHIP OF OUR COMMON STOCK 
+The following table sets forth information with respect to the beneficial ownership of our common stock as of March 31, 2008 by: 
+• each
+person (or group of affiliated persons) who is known by us to own beneficially more than 5% of our voting securities;
+• each
+current director or nominee;
+• each
+of the named executive officers listed in the table below, (or "NEO"); and
+• all
+directors and executive officers as a group. 
+Beneficial
+ownership is determined in accordance with the Securities and Exchange Commission ("SEC") rules. In computing percentage ownership of each person, shares of common stock
+subject to options held by that person that are currently exercisable or convertible, or exercisable or convertible within 60 days of March 31, 2008, are deemed to be outstanding and
+beneficially owned by that person. In addition, shares that are required to be issued by us to any person pursuant to a restricted stock award agreement within 60 days of March 31, 2008
+are also deemed to be outstanding and beneficially owned by that person. None of these shares, however, are deemed outstanding for the purpose of computing the percentage ownership of any other
+person. 
+Except
+as indicated in this table and pursuant to applicable community property laws, each stockholder named in the table has sole voting and investment power with respect to the shares
+set forth opposite such stockholder's name. Percentage ownership is based on 83,187,803 shares of our common stock outstanding on March 31, 2008. Unless otherwise indicated below, the address
+for each 
+6 
+person
+who owns more than 5% of our voting securities and for each director and named executive officer listed below is in care of Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503. 
+Beneficial Ownership 
+Name of Beneficial Owner 
+Shares 
+Percent 
+5% Stockholders: 
+Mazama Capital Management, Inc.(1) 
+6,894,344 
+8.3% 
+Non-Employee Directors: 
+Richard L. Sharp(2) 
+1,447,454 
+1.7% 
+Michael E. Marks(3) 
+1,640,005 
+2.0% 
+Thomas J. Smach(4) 
+127,210 
+* 
+Raymond D. Croghan(5) 
+85,861 
+* 
+Marie Holman-Rao(6) 
+20,000 
+* 
+Ronald L. Frasch(7) 
+5,000 
+* 
+Named Executive Officers: 
+Ronald R. Snyder(8) 
+1,109,579 
+1.3% 
+John P. McCarvel(9) 
+407,750 
+* 
+Michael C. Margolis(10) 
+145,634 
+* 
+Peter S. Case(11) 
+36,668 
+* 
+Russell C. Hammer 
+— 
+* 
+All current directors and executive officers as a group (11 persons)(12) 
+5,025,161 
+6.0% 
+* Less
+than 1%
+(1) Based
+solely on a Schedule 13G filed with the SEC on February 8, 2008. The address for Mazama Capital Management, Inc. is One Southwest Columbia Street,
+Suite 1500, Portland, Oregon 97258.
+(2) Shares
+beneficially owned include 297,024 shares subject to options exercisable within 60 days of March 31, 2008, 800,000 shares beneficially owned by The RLS Trust,
+116,810 shares beneficially owned by BES & RS, LLC, 116,810 shares beneficially owned by EGG & RS, LLC, and 116,810 shares beneficially owned by RBG &
+RS, LLC. Mr. Sharp is the sole trustee of The RLS Trust and is the sole manager of each of BES & RS, LLC, EGG & RS, LLC, and RBG & RS, LLC, and
+he exercises voting and investment power over all of the shares beneficially owned by the trust and each company. The address for Mr. Sharp is 9020 Stony Point Parkway, #180, Richmond, VA
+23235.
+(3) Shares
+beneficially owned include 175,197 shares subject to options exercisable within 60 days of March 31, 2008 and 1,214,808 shares beneficially owned by WB
+Investors, LLC. Mr. Marks is the managing member of WB Investors, LLC and exercises voting and investment power over the shares beneficially owned by WB Investors, LLC.
+(4) Shares
+beneficially owned include 122,210 shares subject to options exercisable within 60 days of March 31, 2008 and 5,000 shares held as custodian for
+Mr. Smach's two children and nephew under the New York Uniform Gifts to Minors Act. Mr. Smach exercises voting and investment power over the shares.
+(5) Shares
+beneficially owned include 80,901 shares subject to options exercisable within 60 days of March 31, 2008 and an aggregate of 4,960 shares of common stock
+beneficially owned by two trusts for the benefit of Mr. Croghan's two daughters. Mr. Croghan's spouse is the trustee of both trusts and she exercises sole voting and investment power
+over the shares. Mr. Croghan disclaims beneficial ownership of such shares. 
+7 
+(6) Shares
+beneficially owned are subject to options exercisable within 60 days of March 31, 2008.
+(7) Shares
+beneficially owned are subject to options exercisable within 60 days of March 31, 2008.
+(8) Shares
+beneficially owned include 194,954 shares subject to options exercisable within 60 days of March 31, 2008, 19,468 shares that will be issued pursuant to a
+restricted stock award agreement within 60 days of March 31, 2008 and 895,161 shares held in the name of Pershing LLC f/b/o Ronald R. Snyder.
+(9) Shares
+beneficially owned include 153,386 shares subject to options exercisable within 60 days of March 31, 2008 and 254,364 shares held jointly with his spouse.
+(10) Shares
+beneficially owned include 89,176 shares subject to options exercisable within 60 days of March 31, 2008, 400 shares held of record by Mr. Margolis'
+daughter and 56,058 shares held jointly with his spouse. Mr. Margolis disclaims beneficial ownership of the shares held by his daughter.
+(11) Shares
+beneficially owned are subject to options exercisable within 60 days of March 31, 2008.
+(12) Shares
+beneficially owned include 700,332 shares of common stock subject to options issued to six non-employee directors and 493,656 shares of common stock subject to
+options issued or restricted stock awards granted to five executive officers that are exercisable or issuable within 60 days of March 31, 2008. 
+BOARD OF DIRECTORS AND COMMITTEES OF THE BOARD 
+Board Composition 
+Our Board of Directors currently consists of seven members divided into three classes, with each director elected to a three-year term. Under our
+amended and restated bylaws, each of our directors holds office until his or her successor is elected and qualified or until such director's earlier death, resignation, disqualification or removal. 
+At
+each annual meeting of stockholders, the successors to directors whose terms expire at such meeting will be elected, or such directors will be re-elected, and will serve
+from the time of election and qualification until the third annual meeting following their election and until their successors are duly elected and qualified. The current authorized number of
+directors is seven. The authorized number of directors may be changed by resolution of the board. Any additional directorships resulting from an increase in the number of directors will be distributed
+among the three classes so that, as nearly as possible, each class will consist of one-third of the directors. Vacancies on the board can be filled by resolution of the Board of Directors. 
+NASDAQ
+listing standards require that our Board of Directors have a majority of independent directors. The Board of Directors has determined that all of the current members of our Board
+of Directors, except Mr. Snyder, are independent directors as defined by Rule 4200(a) (15) of the NASDAQ
+listing standards. The Board makes a determination regarding the independence of each director annually based on the relevant facts and circumstances. Applying these standards and the independence
+criteria defined by the NASDAQ listing standards, the Board has made a subjective determination as to each independent director that no relationships exist that, in the opinion of the Board, would
+interfere with the exercise of his or her independent judgment in carrying out the responsibilities of a director. 
+During
+2007, the Board of Directors met six times and acted by written consent on various other occasions. All directors attended 75% or more of the meetings of the Board of Directors
+and the meetings of the committees of the Board on which they serve. The outside directors of the Board hold executive sessions without members of management present, including Mr. Snyder.
+Executive sessions were held on four occasions in 2007 and 100% of the outside directors were in attendance. We 
+8 
+encourage,
+but do not require, our directors to attend the annual meeting. Mr. Snyder and Mr. Croghan attended our 2007 annual meeting of stockholders. 
+Stockholders
+who wish to communicate with the Board of Directors or with specified individual directors may do so by mailing such written communication to: Corporate Secretary,
+Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503. The Corporate Secretary will review all correspondence and will forward to the Board or an individual director a summary of the
+correspondence received and copies of correspondence that the Corporate Secretary determines requires the attention of the board or such individual director. The Board or an individual director may at
+any time request copies and review all correspondence received by the Corporate Secretary that is intended for the Board or such individual director. 
+Board Committees 
+Our Board of Directors has the authority to appoint committees to perform certain management and administrative functions. Our Board of Directors has established
+the following committees: 
+Audit Committee. Messrs. Smach (Chairman), Croghan and Frasch are the current members of
+our Audit Committee. The Audit Committee met four times in 2007. The functions of the Audit Committee include oversight of the integrity of our financial statements, our compliance with legal and
+regulatory requirements, the performance, qualifications and independence of our independent auditors and the performance of our internal audit function. Our Audit Committee is directly responsible,
+subject to stockholder ratification, for the appointment, retention, compensation, evaluation, termination and oversight of the work of any independent auditor engaged for the purpose of preparing or
+issuing an audit report or related work. The purpose and responsibilities of our Audit Committee are set forth in the Audit Committee Charter, which was amended and restated by our Board of Directors.
+The amended and restated Audit Committee Charter can be found on our website at www.crocs.com. 
+All
+of the members of the Audit Committee are independent as determined in accordance with NASDAQ rules and relevant federal securities laws and regulations. Our Board of Directors has
+determined that Mr. Smach qualifies as an "audit committee financial expert" as defined by the applicable regulations of the SEC. 
+Compensation Committee. Our Compensation Committee consists of Messrs. Marks (Chairman)
+and Croghan. The Compensation Committee met twelve times in 2007. The Compensation Committee has overall responsibility for evaluating and approving our executive officer incentive compensation,
+benefits, severance, equity-based or other compensation plans, policies and programs. The Compensation Committee is also responsible for approving our Compensation, Discussion and Analysis for
+inclusion in our proxy statement. The purpose and responsibilities of our Compensation Committee are set forth in the Compensation Committee Charter, which was approved by our Board of Directors on
+June 30, 2005. The Compensation Committee Charter can be found on our website at www.crocs.com. All of the members of the Compensation Committee are independent as determined in accordance with
+NASDAQ listing standards and relevant federal securities laws and regulations. 
+Role of the Compensation Committee. The Compensation Committee has the authority to establish and monitor the executive
+compensation programs and to make decisions regarding the compensation of the NEOs. The Compensation Committee sets the Chief Executive Officer's compensation. The Compensation Committee also reviews
+the recommendations of the Chief Executive Officer with respect to compensation of the other NEOs and, after reviewing such recommendations, sets the compensation of the other NEOs. The Compensation
+Committee also monitors, administers and approves awards under our various incentive compensation plans for all levels of our employees, 
+9 
+including
+awards under our 2007 Incentive Plan, 2007 Equity Incentive Plan and 2008 Cash Incentive Plan. 
+The
+Compensation Committee relies on its judgment in making compensation decisions after reviewing our performance and evaluating each executive's performance against established goals,
+leadership ability and responsibilities, and current compensation arrangements. When setting total compensation for each of the NEOs, the Compensation Committee reviews the NEO's current compensation,
+which includes equity and non-equity based compensation. The Compensation Committee also evaluates surveys and other available data regarding the executive compensation programs of
+comparative companies. The compensation program for NEOs and the Compensation Committee assessment process are designed to be flexible so as to better respond to the evolving business environment and
+individual circumstances. 
+Role of Consultants. In 2007, neither the Compensation Committee nor management engaged a third party consultant for
+determining the amount or particular form of any NEO compensation. In evaluating the 2008 executive compensation, however, the Compensation Committee and management engaged a third party consultant,
+Mercer, to provide an overall evaluation of our NEO compensation, including a comparison against our peers, on elements of compensation including base pay,
+performance based bonuses and long-term equity awards. The peer group information, which includes peers utilized in 2007 (detailed below), was collected and presented to the Compensation
+Committee by Mercer in March 2008. The use of these market benchmarks, while helpful to the Committee in determining the 2008 executive compensation, is principally intended to assist the Compensation
+Committee as a point of reference and is not considered to be determinative in the Compensation Committee's decision-making process. The Compensation Committee is granted authority to retain such
+outside counsel, experts and other advisers as deemed necessary. 
+Employment and Severance Agreements. The current NEOs, with the exception of Mr. Hammer, do not have employment,
+severance or change in control agreements, although unvested options and restricted stock may become vested on a change in control pursuant to individual option or restricted stock award agreements.
+Based on our employment agreement with Mr. Hammer, we will pay six months of his base salary upon involuntary termination without cause. The NEOs serve at the will of the Board, which enables
+us to terminate their employment with discretion and to determine the terms of any severance. This is consistent with our performance-based employment and compensation philosophy. 
+Governance and Nominating Committee. Our Governance and Nominating Committee consists of
+Mr. Sharp (Chairman) and Ms. Holman-Rao. The Governance and Nominating Committee met once in 2007. The Governance and Nominating Committee assists our Board of Directors in
+promoting the best interests of the Company and our stockholders through the implementation of sound corporate governance principles and practices. In furtherance of this purpose, the Governance and
+Nominating Committee identifies individuals qualified to become board members and recommends to our Board of Directors the director nominees for the next annual meeting of stockholders. It also
+reviews the qualifications and independence of the members of our Board of Directors and its various committees and makes any recommendations the Governance and Nominating Committee members may deem
+appropriate concerning any recommended changes in the composition of our Board of Directors and its committees. The Governance and Nominating Committee also recommends to our Board of Directors the
+corporate governance guidelines and standards regarding the independence of outside directors applicable to us and reviews the provisions of the Governance and Nominating Committee Charter on a
+regular basis to confirm that such guidelines, standards and charter remain consistent with sound corporate governance practices and with any legal or regulatory requirements of NASDAQ. The Governance
+and Nominating Committee also monitors and leads our Board of Directors in its annual review of our Board of Directors' performance. 
+10 
+The
+purpose and responsibilities of our Governance and Nominating Committee are set forth in the Governance and Nominating Committee Charter, which was approved by our Board of Directors
+on June 30, 2005. The Governance and Nominating Committee Charter can be found on our website at www.crocs.com. All of the members of the Governance and Nominating Committee are independent as
+determined in accordance with the NASDAQ listing standards. 
+Director Nomination Process. In identifying potential director candidates, the Governance and Nominating Committee relies on
+recommendations from a number of sources, including current directors and officers. The Governance and Nominating Committee may also hire outside consultants or search firms or other advisors to
+assist in identifying director candidates. The Governance and Nominating Committee will consider director candidates recommended by stockholders on the same basis as it considers other candidates. Any
+stockholder wishing to recommend a candidate for consideration by the Governance and Nominating Committee may do so by submitting a written recommendation to the Governance and Nominating Committee in
+accordance with the procedures set forth under "Stockholder Proposals and Nominations for 2009 Annual Meeting." 
+In
+evaluating a candidate for director, the Governance and Nominating Committee considers, among other things, the candidate's judgment, knowledge, integrity, business and industry
+experience, and expertise, which are likely to enhance the Board of Director's ability to manage and direct our affairs and business. The Governance and Nominating Committee also takes into account
+independence requirements imposed by law or regulations (including the NASDAQ listing standards). In the case of director candidates recommended by stockholders, the Governance and Nominating
+Committee may also consider the number of shares held by the recommending stockholder, the length of time that such shares have been held and the relationship, if any, between the recommending
+stockholder and the recommended director nominee. 
+Code of Business Conduct and Ethics and Committee Charters 
+We have adopted a Code of Business Conduct and Ethics that applies to all directors and employees, including our principal executive, financial and accounting
+officers. The Code of Business Conduct and Ethics is posted on our website at www.crocs.com. We intend to satisfy the requirements under Item 5.05 of Form 8-K regarding
+disclosure of amendments to, or waivers from, provisions of our Code of Business Conduct and Ethics that apply to our directors and principal executive, financial and accounting officers by posting
+such information on our website. The Audit Committee Charter, Compensation Committee Charter and Governance and Nominating Committee Charter are also available on our website at www.crocs.com. Any
+person may request a copy of the Code of Business Conduct and Ethics or committee charters free of charge by submitting a written request to: Corporate Secretary, Crocs, Inc., 6328 Monarch Park
+Place, Niwot, Colorado 80503. 
+11 
+Compensation of Directors 
+The table below summarizes the total compensation paid or earned by each of the non-employee directors for the fiscal year ended December 31,
+2007. 
+Year 
+Fees Earned or Paid in Cash 
+Option Awards(1) 
+Total 
+Raymond D. Croghan 
+2007 
+$ 
+40,000 
+$ 
+303,286 
+$ 
+343,286 
+Ronald L. Frasch 
+2007 
+40,000 
+248,381 
+288,381 
+Marie Holman-Rao 
+2007 
+40,000 
+248,381 
+288,381 
+Michael E. Marks 
+2007 
+45,000 
+303,286 
+348,286 
+Richard L. Sharp 
+2007 
+45,000 
+289,971 
+334,971 
+Thomas J. Smach 
+2007 
+50,000 
+419,106 
+469,106 
+(1) Amounts
+reflect the dollar amount recognized for financial statement reporting purposes for the year ended December 31, 2007, in accordance with SFAS 123R and includes
+amounts from awards granted in and prior to 2007. Assumptions used in the calculations of these amounts are set forth in Footnote 5 to our Consolidated Financial Statements included in our Annual
+Report on Form 10-K for the year ended December 31, 2007. 
+As
+of December 31, 2007, each non-employee director had the following number of stock options outstanding. All information regarding options outstanding have been
+restated, as appropriate, to reflect to the 2-for-1 stock split that occurred on June 14, 2007, which was effected as a 100% common stock dividend distributed on that
+date. 
+Options 
+Outstanding at 
+December 31, 2007 
+Raymond D. Croghan 
+203,510 
+Ronald L. Frasch 
+85,000 
+Marie Holman-Rao 
+100,000 
+Michael E. Marks 
+297,806 
+Richard L. Sharp 
+448,836 
+Thomas J. Smach 
+288,623 
+In
+2007 our non-employee directors received annual cash compensation of $40,000, payable quarterly. Additional annual cash compensation was paid to the chairperson of each
+committee of the Board of Directors as follows: $10,000 for the Chair of the Audit Committee and $5,000 for each of the Compensation Committee Chair and the Governance and Nominating Committee Chair.
+All directors were reimbursed for their reasonable out-of-pocket expenses incurred in attending meetings of the Board of Directors and its committees. 
+Each
+new non-employee director is awarded options to purchase 80,000 shares of our common stock on his or her initial election to our Board of Directors, and continuing
+directors are awarded options to purchase an additional 20,000 shares of our common stock for each year of service. The Chairman of the Board of Directors receives options to purchase an additional
+20,000 shares of our common stock on initial election as Chairman. The options are granted at the fair market value of our common stock on the date of grant and have a term of seven years. Each option
+grant vests in four equal installments on the respective dates of the first four annual meetings following the grant date, so long as such person remains a director. 
+Compensation Committee Interlocks and Insider Participation 
+Messrs. Croghan and Marks served as the members of our Compensation Committee during the fiscal year ended December 31, 2007. None of our executive
+officers currently serve, or in the past has served, on the compensation committee or the board of directors of any other company, whose executive officers served as a member of our Compensation
+Committee or Board of Directors. 
+12 
+EXECUTIVE COMPENSATION 
+COMPENSATION DISCUSSION AND ANALYSIS 
+The following discussion and analysis provides information regarding our executive compensation objectives and principles, procedures, practices and decisions,
+and is provided to help give perspective to the numbers and narratives that follow in the tables within this section. This discussion will focus on our objectives, principles, practices and decisions
+with respect to the compensation of the following named executive officers (the "NEOs"): 
+• Ronald
+R. Snyder, Chief Executive Officer and President
+• John
+P. McCarvel, Chief Operating Officer and Executive Vice President
+• Michael
+C. Margolis, Vice President—Sales and Marketing
+• Peter
+S. Case, Former Chief Financial Officer, Senior Vice President—Finance and Treasurer
+• Russell
+C. Hammer, Chief Financial Officer, Senior Vice President—Finance and Treasurer, effective January 2008 
+Executive Compensation Objectives and Principles 
+The overall objective of our executive compensation program is to create long-term value for our stockholders by attracting and retaining talented
+executives, rewarding superior operating and financial performance, and aligning the long-term interests of our executives with those of our stockholders. Accordingly, our executive
+compensation program incorporates the following principles: 
+• Compensation
+should be based on individual job responsibility, demonstrated leadership ability, management experience, individual performance and our performance. Employees
+in positions of leadership and broad responsibility are generally compensated by elements that are linked to our overall performance and stockholder returns.
+• Compensation
+should reflect the fair market value of the services received. We believe that a fair and competitive pay package for the NEOs is essential to attract and
+retain talented executives in key positions.
+• Compensation
+is designed to reward NEOs based on both our short-term and long-term performance. Base pay is tied to individual performance and market
+conditions for similar positions. Bonuses are tied to achievement of short-term quantitative performance goals that we believe closely correlate to share value. Long-term
+performance is rewarded through equity-based awards such as stock options, the value of which depends on future share prices, and the realization of which is contingent on satisfaction of vesting
+schedules requiring continued service with us.
+• Compensation
+should foster long-term focus. Compensation is designed to align executives' interests with those of our stockholders. A significant percentage of
+total compensation is allocated to non-cash compensation as a result of this philosophy. We do not use an exact formula for allocating between cash and non-cash compensation. 
+The
+Compensation Committee forms its judgments regarding the levels and component mix of executive compensation by considering the market competition for executive talent, the risk to an
+executive inherent in employment with a company that has a relatively short operating history, and our financial goals. The following are several specific financial metrics used by the Compensation
+Committee in determining the final 2007 compensation for executives: 
+• Revenues
+increased 138.9% to $847.4 million in 2007 from $354.7 million in 2006. 
+13 
+• Net
+income increased 161.2% to $168.2 million in 2007 from $64.4 million in 2006.
+• Diluted
+earnings per share increased 146.9% to $2.00 in 2007 from $0.81 in 2006. 
+Elements of Compensation 
+Our executive compensation objectives and principles are implemented through the use of the following elements of compensation, each of which is discussed more
+fully below: 
+• Base
+Pay
+• Performance-Based
+Bonus
+• Long-Term
+Equity Awards
+• Other
+Personal Benefits 
+Our
+executive compensation program seeks to attract, retain, and motivate exemplary executive talent who are able to succeed in our fast paced high growth company. Our executive
+compensation program also seeks to hold our executives accountable and reward them appropriately for successful business results. We are firmly committed to our stockholders, and our executive
+compensation program is structured to align our executives' compensation with our stockholders' interests. To meet each of these objectives, our core executive compensation program encompasses base
+salaries, annual performance-based incentive compensation, and long-term equity incentive awards. We believe that the total compensation opportunities offered to our executives are
+sufficient to reduce the need for anything other than limited executive perquisites (which are detailed later in this report) or enhanced benefit programs beyond those that are typically available to
+all other employees. 
+The
+Compensation Committee does not utilize an exact calculation in determining the break-down of NEO compensation among base pay, annual performance-based bonus, and
+long-term equity awards; rather, the Compensation Committee takes into consideration all forms of compensation. Because we are a rapidly growing company, we believe that a substantial
+portion of each NEO's compensation should be in the form of annual performance-based bonus and equity awards. In general, compensation of the NEOs is set at levels where we are competitive with our
+market peers of the S&P 600 Footwear Index and two similar companies due to either their multi-brand business model or high growth (collectively, "Peers"), with the expectation that shortfalls
+in base pay, if any, will be recouped through performance bonuses should our performance entitle the NEO to receive performance bonuses. The Peers and the criteria for their inclusion are listed
+below: 
+Company 
+Criteria 
+Brown Shoe Co., Inc . 
+S&P 600 Footwear 
+K-Swiss, Inc . 
+S&P 600 Footwear 
+Quiksilver, Inc . 
+Similar Multi-Brand Business Model 
+Skechers USA, Inc . 
+S&P 600 Footwear 
+Stride Rite CP 
+S&P 600 Footwear 
+Timberland Co . 
+S&P 600 Footwear 
+Under Armour, Inc . 
+High Growth 
+Wolverine World Wide, Inc . 
+S&P 600 Footwear 
+Base Pay. The Compensation Committee established base pay in 2007 by considering the size of our operations, the
+responsibilities of the NEOs and the competitive marketplace for executive talent in similar positions, in particular that of our Peers. The Compensation Committee sets the base pay of the Chief
+Executive Officer. Base pay for other NEOs is set by the Compensation Committee after reviewing the recommendation of the Chief Executive Officer. Annual adjustments are influenced by 
+14 
+growth
+of our operations, revenues and profitability, individual performance, changes in responsibility and other factors. 
+Performance-Based Bonuses. In an effort to encourage achievement of our performance objectives, the amount of potential bonus
+to be paid to the NEOs for the year upon achievement of these performance objectives is set at a level which the Compensation Committee believes is in excess of the bonuses paid by our Peers. The
+combination of base pay and performance-based bonuses is intended to result in an aggregate rate of salary and bonus compensation exceeding competitive market standards when we exceed the performance
+objectives set by the Compensation Committee. The Compensation Committee believes that a compensation plan exceeding competitive market standards offers NEOs additional incentive to outperform our
+Peers and ensures that we attract and retain talented NEOs. 
+Under
+our 2007 Incentive Plan, the bonus amount for each NEO was expressed as a percentage of the NEO's base pay ranging from 25% to 800% contingent on us achieving diluted earnings per
+share growth in 2007 between 10% to 175% over our fully diluted earnings per share for the year ended December 31, 2006. If we did not reach the minimum earnings per share target of 10%, the
+NEOs would not have been eligible for bonuses under the plan. The percentages were determined by the Compensation Committee based on the estimated contribution and responsibility of the individual
+NEO. The Compensation Committee also takes into consideration the inherent employment risk accepted by an officer of a rapidly growing company with a limited operating history. 
+The
+bonuses payable to the NEOs in 2007 were paid early in 2008 after the Compensation Committee had determined the amount actually earned and payable. For 2007, our performance entitled
+the NEOs to the bonus levels between the target and maximum amounts allowed under our 2007 Incentive Plan with deferred compensation also recognized for certain of our NEOs who elected to participate
+in our related Senior Executive Deferred Compensation Plan. Total bonuses earned by the NEO's ranged from 75% to 600% of their base salaries. Information on target and maximum bonus amounts are
+included in the Grants of Plan Based Awards Table below. The Compensation Committee has discretion to depart from the formula in approving the bonuses and decrease bonuses after general results are
+known. In 2007, the Compensation Committee adjusted certain bonuses during their review of our performance and each NEO's individual contribution to our performance. Adjustments were made for certain
+NEOs based on the results of the Compensation Committee's assessment and represent decreases against the bonus amount that would have been paid if the bonus amount were based on our performance alone.
+Bonuses earned under the 2007 Incentive Plan are reported under the headings "Non-Equity Incentive Plan Compensation" and "Bonuses," respectively, in the Summary Compensation Table below. 
+In
+addition, the 2008 Cash Incentive Plan was approved at the 2007 Annual Meeting of Stockholders. This plan qualifies as a performance-based compensation plan in accordance with
+Section 162(m) of the Internal Revenue Code (hereafter referred to as "the Code"). See "Deductibility of Executive Compensation" below for further discussion. 
+Senior Executive Deferred Compensation Plan. Certain senior executives, including NEOs, are eligible to participate in the
+2007 Senior Executive Deferred Compensation Plan (the "Senior Executive Plan"). Under the Senior Executive Plan, a participant may defer all or a part of his or her bonus amount exceeding 200% of
+their target bonus in accordance with the applicable deferral agreement executed by the participant. The deferred compensation is credited to a deferral account established for each participant under
+the Senior Executive Plan for recordkeeping purposes. Under the Senior Executive Plan, we established an irrevocable trust into which we are required to deposit cash or other assets as specified in
+the applicable deferral agreement, equal to the aggregate amount required to be credited to the participant's deferral account, less any applicable taxes required to be withheld. In 2008,
+Messrs. Snyder and McCarvel elected to participate in the Senior Executive Plan and deferred $1,600,000 and $640,000, respectively. The deferred bonuses for Mr. Snyder and Mr. McCarvel
+vest 
+15 
+ratably
+on a quarterly basis over a three year period, with a pro rata amount vesting on each calendar quarter, providing a long-term retention incentive. The deferred bonuses for
+Messrs. Snyder and McCarvel will be 100% vested upon a change of control (as defined in the Senior Executive Plan) if they are employed at that time or if their employment is terminated as a
+result of death or disability. 
+In
+March 2008, the Compensation Committee approved performance targets under the 2008 Cash Incentive Plan in accordance with the 2007 methodology, which is based on achievement of
+diluted earnings per share growth in 2008 between 15% to 35% over our fully diluted earnings per share for the year ended December 31, 2007. The 2008 Cash Incentive Plan awards a bonus
+expressed as a percentage of 2008 base salary ranging from 50% to 100%. Diluted earnings per share growth below 15% would result in the NEO being ineligible for a bonus in accordance with this plan.
+Bonus targets were established based on estimated contribution and responsibility. 
+Long-Term Equity Awards. Discretionary long-term equity awards, in the form of stock options and
+restricted stock, are granted at the Compensation Committee's discretion to the NEOs annually in order to provide long-term performance-based compensation, to
+encourage the NEOs to continue their employment throughout the vesting periods of the awards, and to align management and stockholder interests. The Compensation Committee considers grant size and the
+appropriate combination of equity-based awards in making NEO grant decisions. For 2007 and 2008, the amount of long-term equity awards granted to NEOs was based on the Compensation
+Committee's assessment of each NEO's expected future contributions and the award levels of our Peers. We granted long-term equity awards at the Compensation Committee meeting held in
+January 2008. In 2007 and 2008, the Compensation Committee approved stock option grants for the NEOs as listed below: 
+Name 
+2008 Stock Option Awards: 
+Number of Securities 
+Underlying Options 
+(#) 
+2007 Stock Option Awards: 
+Number of Securities 
+Underlying Options 
+(#) 
+Ronald R. Snyder 
+200,000 
+350,000 
+John P. McCarvel 
+150,000 
+250,000 
+Peter S. Case 
+30,000 
+80,000 
+Russell C. Hammer 
+150,000 
+— 
+Michael Margolis 
+30,000 
+60,000 
+We
+compared our long-term equity award program for 2007 against the equity-based compensation programs of our Peers to assist in determining both the structure and amount of
+awards to be made in 2008. The Compensation Committee believes that the awards made to NEOs in 2007 were made at levels consistent with those of our Peers and the anticipated contribution and
+responsibility of the NEO in future years. 
+Options
+are granted with an exercise price equal to the closing price per share on the date of grant and vest pro rata over four-years, with the first year vesting on a
+"cliff" basis followed by monthly vesting for the remaining three years. Stock options only have economic value to the grantee to the extent the market price of the underlying shares on the exercise
+date exceeds the exercise price. Accordingly, options provide compensation only if the underlying share price increases over the option term and the NEO's employment continues until the vesting date.
+The Compensation Committee believes that the granting of stock options with an exercise price equal to the market value on the date of grant represents a preferred method of equity incentive
+compensation when compared to stock awards because the value of the option award to the NEO is based solely on future increases in the market value of our stock. 
+Other Benefits. Other benefits are provided to the NEOs in order to achieve a competitive pay package as detailed in the
+Summary Compensation Table below. The Compensation Committee believes that those benefits, which are detailed in the Summary Compensation Table under the heading 
+16 
+"All
+Other Compensation," are reasonable, competitive and consistent with our overall executive compensation program. Those benefits consist principally of employer-paid premiums on health
+insurance and country club dues. 
+Deductibility of Executive Compensation 
+Section 162(m) of the Code imposes a $1 million annual limit on the amount that a public company may deduct for compensation paid to the company's
+chief executive officer during a tax year or to any of the company's four other most highly compensated executive officers who are still employed at the end of the tax year. The limit does not apply
+to compensation that meets the requirements of the Code for "qualified performance-based" compensation (i.e., compensation paid only if the executive meets pre-established,
+objective goals based on performance criteria approved by the company's stockholders). 
+The
+Compensation Committee reviews and considers the deductibility of executive compensation under Section 162(m) of the Code. In certain situations, the Compensation Committee
+may approve compensation that does not meet the requirements of the Code in order to ensure competitive levels of total compensation for its executive officers. Stock option grants in 2007 were
+intended to constitute "qualified performance-based compensation" under Section 162(m). The annual performance bonuses payable in 2008 under our 2007 Incentive Plan also met the requirements
+for consideration as "qualified performance-based compensation" under Section 162(m). 
+COMPENSATION COMMITTEE REPORT 
+The Compensation Committee has reviewed the foregoing Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K and
+discussed the Compensation Discussion and Analysis with the Company's management. Based on such review and discussions with management, the Compensation Committee recommended to the Board that the
+foregoing Compensation Discussion and Analysis be included in this proxy statement. 
+THE
+COMPENSATION COMMITTEE 
+Michael Marks, Chairman 
+Ray Croghan 
+17 
+Summary Compensation Table 
+The following summary compensation table indicates the cash and non-cash compensation paid to each of our NEOs during our fiscal years ended
+December 31, 2007 and 2006. The compensation described in this table does not include benefits that are generally available to all of our salaried employees. All information regarding stock and
+option awards has been restated, as appropriate, to reflect the 2-for-1 stock split that occurred on June 14, 2007, which was effected as a 100% common stock dividend
+distributed on that date. 
+Name and Principal Position 
+Year 
+Salary 
+($) 
+Bonus 
+($) 
+Stock Awards 
+($)(1) 
+Option Awards 
+($)(1) 
+Non-Equity Incentive Plan Compensation 
+($)(2) 
+All Other Compensation 
+($)(3) 
+Total 
+($) 
+Ronald R. Snyder 
+Chief Executive Officer and President 
+2007 
+2006 
+$ 
+800,000 
+500,000 
+$ 
+— 
+500,000 
+$ 
+402,584 
+344,937 
+$ 
+2,548,659 
+1,603,296 
+$ 
+3,200,000 
+1,000,000 
+$ 
+19,325 
+10,711 
+$ 
+6,970,568 
+3,958,944 
+John P. McCarvel 
+Chief Operating Officer and Executive Vice President 
+2007 
+2006 
+400,000 
+275,000 
+— 
+220,000 
+— 
+460,333 
+768,666 
+132,655 
+1,280,000 
+440,000 
+15,398 
+— 
+2,464,064 
+1,527,988 
+Peter S. Case 
+Chief Financial Officer, Senior Vice President—Finance and Treasurer 
+2007 
+2006 
+300,000 
+249,000 
+— 
+82,500 
+— 
+— 
+483,392 
+258,034 
+225,000 
+230,000 
+19,381 
+10,116 
+1,027,773 
+829,650 
+Michael Margolis 
+Vice President—Sales & Marketing 
+2007 
+2006 
+300,000 
+231,000 
+— 
+57,500 
+— 
+66,185 
+621,245 
+475,992 
+300,000 
+230,000 
+15,398 
+— 
+1,236,643 
+1,060,677 
+(1) Amounts
+reflect the dollar amount recognized for financial statement reporting purposes for the year ended December 31, 2007 and 2006, in accordance with SFAS 123R, and
+include amounts from awards granted in and prior to such years. Assumptions used in the calculations of these amounts are included in Footnote 5 to our Consolidated Financial Statements
+included in our Annual Report on Form 10-K for the year ended December 31, 2007.
+(2) Amounts
+for Mr. Snyder and Mr. McCarvel include deferred compensation under the Senior Executive Plan of $1.6 million and $640,000, respectively, and will vest
+over a three year period.
+(3) All
+other compensation represents incremental healthcare premiums paid by us on behalf of the employee and golf club membership fees. We cover 100% of the healthcare premiums for
+certain executives, a benefit that is not offered to other employees. 
+18 
+Grants of Plan-Based Awards Table 
+The table below summarizes the options granted during the year ended December 31, 2007 to each of the NEOs listed in the Summary Compensation Table. All
+information regarding option awards account for the 2-for-1 stock split that occurred on June 14, 2007, which was effected as a 100% common stock dividend on that date. 
+Estimated Possible 
+Payouts Under 
+Non-Equity Incentive 
+Plan Awards(1) 
+All Other Option 
+Awards: Number 
+of Securities 
+Underlying 
+Options 
+(#) 
+Exercise or 
+Base Price of 
+Option Awards 
+($/Sh) 
+Name 
+Grant 
+Date 
+Target 
+($) 
+Maximum 
+($) 
+Grant Date Fair 
+Value of Option 
+Awards(2) 
+Ronald R. Snyder 
+3/30/2007 
+1/9/2007 
+$ 
+400,000 
+$ 
+6,400,000 
+350,000 
+$ 
+22.92 
+$ 
+3,925,390 
+John P. McCarvel 
+3/30/2007 
+1/9/2007 
+160,000 
+$ 
+2,560,000 
+250,000 
+22.92 
+2,803,850 
+Peter S. Case 
+3/30/2007 
+1/9/2007 
+90,000 
+$ 
+1,440,000 
+80,000 
+22.92 
+897,232 
+Michael C. Margolis 
+3/30/2007 
+1/9/2007 
+2/28/2007 
+75,000 
+$ 
+1,200,000 
+40,000 
+20,000 
+22.92 
+24.36 
+448,616 
+237,580 
+(1) Awards
+represent possible payments under our 2007 Bonus Plan. Payments are based on specified target levels of diluted earnings per share, as described in the Compensation Discussion
+and Analysis. The actual amounts earned for fiscal year 2007 are reported in the Summary Compensation Table as Non-Equity Incentive Plan Compensation. Executives must have been employed on
+the date the payments were made to have been eligible for a payment. The target payments were based on achieving the target level of performance with ranges from 25% to 50% of salary. The maximum
+payout amounts were based on the plan maximum, which ranges from 200% to 800% of salary.
+(2) Grant
+date fair value for stock options was determined pursuant to SFAS 123R. Assumptions used in the calculations of these amounts are set forth in Footnote 5 to our
+Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2007. 
+Narrative to Summary Compensation Table and Grants of Plan-Based Awards Table 
+Employment Arrangements 
+We have entered into employment agreements with Mr. Hammer and Mr. Case as set forth below. 
+Russell C. Hammer. In January 2008, we entered into an employment agreement with Mr. Hammer,
+our current Chief Financial Officer, Senior Vice President—Finance, and Treasurer. The employment agreement provides that Mr. Hammer will receive a monthly salary of $31,250,
+subject to annual adjustments. Mr. Hammer's bonus target will be sixty percent of his base salary. He will also be eligible to receive bonuses pursuant to our 2008 Cash Incentive Plan based on
+performance criteria established by the Compensation Committee. 
+Mr. Hammer
+will also receive reimbursement for relocation and housing expenses and will be entitled to participate in all employee benefit plans and programs generally available
+to our executives, including our Senior Executive Plan. The employment agreement also provides that Mr. Hammer will receive a lump sum equal to six months base salary if he is terminated by us
+involuntarily without cause. During his employment with the Company and for a period of six months after the termination of his employment, Mr. Hammer will be restricted from participating in
+certain competitive businesses. 
+19 
+Pursuant
+to our 2007 Equity Incentive Plan and the terms of the employment agreement, we also awarded Mr. Hammer options to purchase 150,000 shares of our common stock at an
+exercise price of $30.05, the closing price of our common stock on the grant date. Twenty-five percent of the options will vest on the first anniversary of the grant date and the remaining
+options will vest in 36 equal monthly installments upon his completion of each additional month of continuous employment with us after the first anniversary of the grant date. 
+Peter S. Case. We have an at-will employment arrangement with Mr. Case pursuant to
+which we pay Mr. Case a monthly salary of $25,000 as well as a performance based bonus target of sixty percent of his base salary. Mr. Case currently serves as our Senior Vice President,
+Retail Division, effective as of January 2008. 
+Awards 
+On January 9, 2007, the Compensation Committee granted stock option awards to several of our NEOs. The awards vest one-fourth after the first
+anniversary of the grant date with the remainder vesting in 36 equal and successive monthly installments after the applicable initial vesting date. 
+No
+other restricted stock or stock options were awarded to NEOs in the year ended December 31, 2007; however, we issued shares of our common stock pursuant to the vesting terms of
+restricted stock awards made prior to 2007. 
+Salary and Bonus in Proportion to Total Compensation 
+In 2007, our NEOs received less than thirty-four percent of their total compensation reported in the Summary Compensation Table in the form of base salary and
+cash incentive awards. As noted in "Compensation Discussion and Analysis" above, we believe that a substantial portion of each NEOs compensation should be in the form of equity awards. Our
+Compensation Committee believes that our current program substantially aligns our NEOs compensation with our Peers, while also permitting our Compensation Committee to provide incentives to the NEOs
+to pursue performance that increases stockholder value. Please see "Compensation Discussion and Analysis" for a description of the objectives of our compensation program and overall compensation
+philosophy. 
+20 
+Outstanding Equity Awards at Fiscal Year-End Table 
+The table below summarizes the unexercised options and unvested stock awards as of December 31, 2007 for each of the NEOs listed in the Summary
+Compensation Table. The information below accounts for the 2-for-1 stock split that occurred on June 14, 2007, which was effected as a 100% common stock dividend on that
+date. 
+Option Awards 
+Stock Awards 
+Name 
+Number of Securities Underlying Unexercised Options 
+(#) 
+Exercisable(1) 
+Number of Securities Underlying Unexercised Options 
+(#) 
+Unexercisable 
+Option Exercise Price 
+($) 
+Option Expiration Date 
+Number of Shares or Units of Stock That Have Not Vested 
+(#) 
+Market Value of Shares or Units of Stock That Have Not Vested 
+($) 
+Ronald R. Snyder 
+19,469 
+19,469 
+— 
+175,214 
+486,707 
+350,000 
+(2) 
+(3) 
+(4) 
+$ 
+0.51 
+10.50 
+22.92 
+9/1/2011 
+2/6/2016 
+1/9/2017 
+87,558 
+(8) 
+$ 
+3,223,010 
+John P. McCarvel 
+57,543 
+— 
+62,543 
+250,000 
+(3) 
+(4) 
+10.50 
+22.92 
+2/6/2016 
+1/9/2017 
+Peter S. Case 
+30,000 
+— 
+129,999 
+80,000 
+(5) 
+(4) 
+10.50 
+22.92 
+2/6/2016 
+1/9/2017 
+Michael C. Margolis 
+11,668 
+— 
+— 
+151,685 
+40,000 
+20,000 
+(6) 
+(4) 
+(7) 
+2.85 
+22.92 
+24.36 
+8/1/2015 
+1/9/2017 
+2/28/2017 
+(1) Options
+granted from inception through September 20, 2006 are exercisable immediately on the grant date. In order to preserve the vesting provisions of the options, the shares
+of our common stock underlying options that are exercised early are subject to a repurchase right by us at the lower of exercise price or fair market value of the underlying stock at the date of
+repurchase.
+(2) Twenty-five
+percent of the options vested on September 1, 2005. Thereafter, the options vest in 36 successive equal monthly installments upon the optionee's
+completion of each additional month of continuous employment.
+(3) Twenty-five
+percent of the options vested on January 1, 2007. Thereafter, the options vest in 36 equal monthly installments upon the optionee's completion of each
+additional month of continuous employment.
+(4) Twenty-five
+percent of the options vested on January 9, 2008. Thereafter, the options vest in 36 equal monthly installments upon the optionee's completion of each
+additional month of continuous employment.
+(5) Twenty-five
+percent of the options vested on February 1, 2007. Thereafter, the options vest in 36 equal monthly installments upon the optionee's completion of each
+additional month of continuous employment.
+(6) Twenty-five
+percent of the options vested on August 1, 2006. Thereafter, the options vest in 36 equal monthly installments upon the optionee's completion of each
+additional month of continuous employment.
+(7) Twenty-five
+percent of the options vested on February 28, 2008. Thereafter, the options vest in 36 equal monthly installments upon the optionee's completion of each
+additional month of continuous employment.
+(8) 9,734
+shares of common stock will be issued on the first day of each month, ending on September 1, 2008, provided that Mr. Snyder remains employed by us as of each
+issuance date. 
+21 
+Option Exercises and Stock Vested Table 
+The table below summarizes the options exercised and stock awards vested during the year ended December 31, 2007 for each of the NEOs listed in the Summary
+Compensation Table. 
+Option Awards 
+Stock Awards 
+Name 
+Number of Shares Acquired on Exercise 
+(#) 
+Value Realized on Exercise 
+($) 
+Number of Shares Acquired on Vesting 
+(#) 
+Value Realized on Vesting 
+($) 
+Ronald R. Snyder 
+1,168,101 
+$ 
+41,797,105 
+116,832 
+$ 
+4,654,976 
+John P. McCarvel 
+— 
+— 
+156,056 
+6,710,408 
+Peter S. Case 
+80,001 
+2,335,892 
+— 
+— 
+Michael C. Margolis 
+140,017 
+5,161,814 
+— 
+— 
+Nonqualified Deferred Compensation 
+The table below summarizes the non-equity incentive compensation that was deferred relating to the year ended December 31, 2007 for each of the
+NEOs listed in the Summary Compensation Table. 
+Name 
+Executive Contributions(1) 
+$ 
+Crocs, Inc. Contributions 
+$ 
+Aggregate Earnings 
+$ 
+Aggregate Withdrawals/ Distributions 
+$ 
+Aggregate Balance 
+$ 
+Ronald R. Snyder 
+$ 
+1,600,000 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+1,600,000 
+John P. McCarvel 
+640,000 
+— 
+— 
+— 
+640,000 
+Peter S. Case 
+— 
+— 
+— 
+— 
+— 
+Michael Margolis 
+— 
+— 
+— 
+— 
+— 
+(1) Under
+our Senior Executive Plan, participants have the option to defer any bonus amount exceeding 200% of the participant's target bonus. The deferred amount will vest ratably on a
+quarterly basis over a three year period, with a pro rata amount vesting on each calendar quarter. Any unvested balance will vest immediately upon the death or disability of the participant or upon a
+Change in Control, as defined in the plan. The total amounts shown above for Messrs. Snyder and McCarvel are included in the Non Equity Incentive Compensation Plan column of the Summary
+Compensation Table. 
+22 
+Potential Payments on Terminations or Change in Control 
+Our NEOs do not have any special guaranteed payments due on retirement. However, all stock option and restricted stock awards have an acceleration clause that
+provides that all unvested outstanding equity awards will immediately vest in the event of a change in control. The following table summarizes potential payments on termination or change in control at
+December 31, 2007. 
+Termination for Cause 
+Change In Control 
+Name 
+Stock 
+Options 
+Unvested and 
+Accelerated 
+Severance 
+Stock Options 
+and Awards 
+Unvested and 
+Accelerated 
+($)(1) 
+Severance 
+Ronald R. Snyder 
+— 
+— 
+$ 
+24,027,029 
+— 
+John P. McCarvel 
+— 
+— 
+5,118,006 
+— 
+Peter S. Case 
+— 
+— 
+4,531,474 
+— 
+Michael C. Margolis 
+— 
+— 
+5,955,823 
+— 
+(1) All
+of our stock options and restricted stock vests on a change in control pursuant to individual option or restricted stock award agreements. The calculation of the amount disclosed
+is based on the number of unvested shares at December 31, 2007 multiplied by the closing price of our common stock on the NASDAQ Market on December 31, 2007, less the exercise price for
+stock options. 
+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+Related Party Transactions 
+In 2008, we sponsored Germain Racing Truck #9 in the NASCAR Craftsman Truck Series. Justin Marks is employed by Germain Racing as the driver of Truck #9. Justin
+Marks is the son of our director, Michael Marks. The total amount of our sponsorship commitment to Germain Racing for 2008 is $600,000. We believe that a related person, Justin Marks, has a material
+interest in the sponsorship by virtue of his employment with Germain Racing as the driver of Truck #9. The sponsorship is part of our larger auto racing sponsorship and sports marketing efforts and
+was negotiated at an arms-length basis with terms similar to those of our other auto racing sponsorships. 
+Policy on Transactions with Related Persons 
+Our Business Code of Conduct and Ethics requires that any transaction involving us in which one of our directors, nominees for director, executive officers, or
+greater than five percent stockholders, or their immediate family members, have a material interest be approved or ratified by the Audit Committee if the amount involved exceeds $100,000. The full
+Board reviews ordinary course of business transactions in which directors have an interest as part of the Board's annual director independence review, and our Business Code of Conduct and Ethics
+requires the full board to waive any conflicts of interest between us and any director or officer. In determining whether to approve or ratify any such transaction, the Audit Committee must consider,
+in addition to other factors it deems appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. 
+All
+transactions disclosed above were reviewed and approved in accordance with this policy. 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify our directors and executive officers, in addition to the indemnification provided for in our certificate of
+incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain 
+23 
+expenses
+(including attorneys' fees), judgments, fines and settlement amounts incurred by any such person in any action or proceeding, including any action by or in the right of the Company, arising
+out of such person's services as a director or executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request. We believe
+that these provisions and agreements are necessary to attract and retain qualified persons as directors and executive officers. 
+SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE 
+Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors and executive officers, and persons who own more than ten percent
+of our common stock, to file with the SEC and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common
+stock. 
+To
+our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all required
+reports of our officers, directors and greater than ten percent stockholders under Section 16(a) were timely filed during the year ended December 31, 2007, except for the following:
+(1) three Forms 4 relating to Ronald R. Snyder's beneficial ownership, the first of which reported a grant of stock options, the second of which reported open market sales, and the third
+of which reported Mr. Snyder's exercise of stock options; (2) one Form 4 relating to Michael C. Margolis' beneficial ownership, which reported a grant of stock options;
+(3) three Forms 4 relating to John P. McCarvel's beneficial ownership, the first of which reported an open market sale, the second of which reported a grant of stock options and the
+third of which reported an open market sale; and (4) one Form 4 relating to Peter S. Case's beneficial ownership, which reported a grant of stock options. 
+REPORT OF THE AUDIT COMMITTEE 
+The Audit Committee has reviewed and discussed the audited financial statements for the fiscal year ended December 31, 2007 with the Company's management
+and Deloitte & Touche LLP, the Company's independent registered public accounting firm. Management is responsible for the preparation, presentation and integrity of the financial
+statements, accounting and financial reporting principles and internal control over financial reporting. Deloitte & Touche LLP is responsible for performing an independent audit of the
+financial statements in accordance with generally accepted auditing standards and for expressing opinions on the conformity of the financial statements with accounting principles generally accepted in
+the United States. 
+The
+Audit Committee has discussed with Deloitte & Touche LLP the matters required to be discussed by Statement on Auditing Standards No. 61, Communication with Audit Committees, as
+amended, and has received the written disclosures and the letter from Deloitte & Touche LLP
+required by Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees. The Audit Committee has also discussed
+with Deloitte & Touche LLP their independence. 
+Based
+on its reviews and discussions referred to above, the Audit Committee has recommended to the Board of Directors that the audited financial statements be included in the Company's
+Annual Report on Form 10-K for the year ended December 31, 2007, for filing with the Securities and Exchange Commission. 
+The
+Audit Committee: 
+Thomas
+J. Smach (Chairman) 
+Raymond D. Croghan 
+Ronald L. Frasch 
+24 
+PROPOSAL 2—RATIFICATION OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+The Audit Committee has appointed Deloitte & Touche LLP, as the independent registered public accounting firm for the fiscal year ending
+December 31, 2008. Deloitte & Touche LLP has served as our independent public accounting firm since 2005. We are not required to submit this appointment to the stockholders for
+approval but the Board believes it is desirable as a matter of policy. 
+If
+the stockholders do not ratify this appointment, the Audit Committee will investigate the reasons for the rejection and consider other independent registered public accounting firms.
+Even if the appointment is ratified, the Audit Committee may, in its discretion, appoint a different independent registered public accounting firm. 
+PRINCIPAL ACCOUNTING FIRM FEES AND SERVICES 
+The following table sets forth the aggregate fees we paid to Deloitte & Touche LLP, our independent registered public accounting firm, and other
+member firms of Deloitte Touche Tohmatsu and their respective affiliates, which we refer to collectively as Deloitte entities, for professional services provided during 2007 and billed through the
+date of this filing. The Audit Committee is required to pre-approve all non-audit services provided by Deloitte & Touche LLP. All
+fees paid to the Deloitte entities were pre-approved by the Audit Committee, which concluded that the provision of such services by the Deloitte entities was compatible with the
+maintenance of that firm's independence in the conduct of its auditing functions. We expect that a representative of Deloitte & Touche LLP will attend the Annual Meeting and will have
+the opportunity to make any statements if he or she so desires and to respond to appropriate stockholder questions. 
+2007 
+2006(3) 
+Audit fees(1) 
+$ 
+2,772,645 
+$ 
+1,180,825 
+Audit-related fees 
+— 
+— 
+Tax fees(2) 
+57,194 
+189,421 
+All other fees 
+— 
+— 
+Total fees 
+$ 
+2,829,839 
+$ 
+1,370,246 
+(1) Audit
+fees relate to professional services rendered in connection with the audit of our annual financial statements and internal controls over financial reporting, both of which are
+included in our Annual Report on Form 10-K and services attendant to, or required by, statute or regulation, such as: (i) comfort letters, consents and other audit services
+related to SEC and other regulatory filings; and (ii) accounting consultation related to the audit. Audit fees consisted of audit work performed and billed through the date of this filing.
+(2) Tax
+fees include professional services rendered in connection with tax compliance, tax advice, tax consulting and tax planning.
+(3) 2006
+fees for both Audit and Tax fees were recalculated to represent actual costs incurred. We received invoices for 2006 services subsequent to the 2007 proxy filing date. 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" THE RATIFICATION OF DELOITTE & TOUCHE LLP AS THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
+FOR FISCAL YEAR 2008. 
+25 
+STOCKHOLDER PROPOSALS AND NOMINATIONS FOR 2009 ANNUAL MEETING 
+Any proposal of a stockholder intended to be included in our proxy statement for the 2009 Annual Meeting of Stockholders pursuant to Rule 14a-8
+of the SEC's rules, must be received by us no later than December 30, 2008, unless the date of our 2009 annual meeting is more than 30 days before or after June 26, 2009, in which
+case the proposal must be received a reasonable time before we begin to print and mail our proxy materials. All proposals should be addressed to the Corporate Secretary, Crocs, Inc., 6328
+Monarch Park Place, Niwot, Colorado 80503. 
+In
+order for a stockholder to nominate a candidate for director for election or to bring other business before the 2009 annual meeting, we must receive timely notice of the nomination or
+business in writing by the close of business not less than 90 days nor more than 120 days prior to the anniversary date of the immediately preceding annual meeting of stockholders.
+However, in the event that the annual meeting is called for a date that is not within 30 days before or 60 days after such anniversary date, notice by the stockholder to be timely must
+be received not earlier than the close of business on the 120th day prior to such annual meeting and not later than the close of business on the later of the 90th day prior to such
+annual meeting or the tenth day following the date on which notice of the date of the annual meeting was made public. 
+OTHER MATTERS 
+We do not intend to bring before the Annual Meeting any matters other than the proposals specifically described above, and we know of no matters other than those
+to come before the Annual Meeting. If any other matters properly come before the Annual Meeting, it is the intention of the persons named in the accompanying proxy to vote such proxy in accordance
+with the recommendation of the our management on such matters, including any matters dealing with the conduct of the Annual Meeting. 
+26 
+6328 MONARCH PARK PLACE 
+NIWOT, CO 80503 
+VOTE BY INTERNET— www.proxyvote.com 
+Use the Internet to transmit your voting instructions and for electronic delivery of information up until 11:59 P.M. Eastern Time the day before the cut-off date or meeting date. Have your proxy card in hand when you access the web site and
+follow the instructions to obtain your records and to create an electronic voting instruction form. 
+ELECTRONIC DELIVERY OF FUTURE STOCKHOLDER COMMUNICATIONS 
+If you would like to reduce the costs incurred by Crocs, Inc. in mailing proxy materials, you can consent to receiving all future proxy statements, proxy cards and annual reports electronically via e-mail or the Internet. To sign up for
+electronic delivery, please follow the instructions above to vote using the Internet and, when prompted, indicate that you agree to receive or access stockholder communications electronically in future years. 
+VOTE BY PHONE—1-800-690-6903 
+Use any touch-tone telephone to transmit your voting instructions up until 11:59 P.M. Eastern Time the day before the cut-off date or meeting date. Have your proxy card in hand when you call and then follow the instructions. 
+VOTE BY MAIL 
+Mark, sign and date your proxy card and return it in the postage-paid envelope we have provided or return it to Crocs, Inc., c/o Broadridge, 51 Mercedes Way, Edgewood, NY 11717. 
+TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS: 
+CROCS1 
+KEEP THIS PORTION FOR YOUR RECORDS 
+DETACH AND RETURN THIS PORTION ONLY 
+THIS PROXY CARD IS VALID ONLY WHEN SIGNED AND DATED. 
+CROCS, INC. 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" ITEMS 1 AND 2. 
+For 
+All 
+Withhold 
+All 
+For All 
+Except 
+To withhold authority to vote for any individual nominee(s), mark "For All Except" and write the number(s) of the nominee(s) on the line below. 
+Vote on Directors 
+o 
+o 
+o 
+1. 
+ELECTION OF DIRECTORS 
+Nominees: 
+01) Thomas J. Smach 
+02) Ronald R. Snyder 
+Vote on Proposal 
+For 
+Against 
+Abstain 
+2. 
+Ratification of the appointment of Deloitte & Touche LLP as our independent auditors for fiscal year 2008. 
+o 
+o 
+o 
+3. 
+In their discretion, to transact other business as may properly come before the meeting or any postponement or adjournment thereof. 
+The shares represented by this proxy when properly executed will be voted in the manner directed herein by the undersigned Stockholder(s). If no direction is made, this proxy will be voted FOR items 1 and
+2. 
+For address changes and/or comments, please check this box and write them on the back where indicated. 
+o 
+Please indicate if you plan to attend this meeting. 
+o 
+o 
+Yes 
+No 
+(NOTE: Please sign exactly as your name(s) appear(s) hereon. All holders must sign. When signing as attorney, executor, administrator, or other fiduciary, please give full title as such. Joint owners should each sign
+personally. If a corporation, please sign in full corporate name, by authorized officer. If a partnership, please sign in partnership name by authorized person.) 
+Signature [PLEASE SIGN WITHIN BOX] 
+Date 
+Signature (Joint Owners) 
+Date 
+Important Notice Regarding Internet Availability of Proxy Materials for the Annual Meeting: The Notice and Proxy Statement and Annual Report are available
+at www.proxyvote.com. 
+CROCS, INC. 
+THIS PROXY IS SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS 
+ANNUAL MEETING OF STOCKHOLDERS 
+June 26, 2008 
+The undersigned hereby appoints Ronald R. Snyder and Russell C. Hammer, and each of them, with power of substitution, as proxies of the undersigned, to attend the Annual Meeting
+of Stockholders of Crocs, Inc. (the "Company"), to be held at the Beaver Creek Lodge, 26 Avondale Lane, Beaver Creek, Colorado, on June 26, 2008 at 1:00 p.m., Mountain Time, and
+all adjournments thereof, and to vote, as indicated on the reverse side, the shares of Common Stock of the Company which the undersigned is entitled to vote with all the powers the undersigned would
+possess if present at the meeting. 
+THIS PROXY, WHEN PROPERLY EXECUTED, WILL BE VOTED AS DIRECTED HEREIN BY THE UNDERSIGNED STOCKHOLDER(S). IF NO SPECIFIC DIRECTIONS ARE GIVEN, THIS PROXY WILL BE VOTED FOR THE
+ELECTION OF THE NOMINEES LISTED ON THE REVERSE SIDE FOR THE BOARD OF DIRECTORS AND FOR THE PROPOSAL. 
+PLEASE MARK, SIGN, DATE AND RETURN THIS PROXY CARD PROMPTLY USING THE ENCLOSED REPLY ENVELOPE 
+Address Changes/Comments: 
+(If
+you noted any Address Changes/Comments above, please mark corresponding box on the reverse side.) 
+CONTINUED AND TO BE SIGNED ON REVERSE SIDE 
+QuickLinks 
+NOTICE OF THE 2008 ANNUAL MEETING OF STOCKHOLDERS TO BE HELD JUNE 26, 2008 
+2008 ANNUAL MEETING OF STOCKHOLDERS 
+PROXY STATEMENT 
+GENERAL INFORMATION REGARDING ANNUAL MEETING 
+EXECUTIVE OFFICERS 
+BENEFICIAL OWNERSHIP OF OUR COMMON STOCK 
+BOARD OF DIRECTORS AND COMMITTEES OF THE BOARD 
+EXECUTIVE COMPENSATION 
+COMPENSATION DISCUSSION AND ANALYSIS 
+COMPENSATION COMMITTEE REPORT 
+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE 
+REPORT OF THE AUDIT COMMITTEE 
+PRINCIPAL ACCOUNTING FIRM FEES AND SERVICES 
+STOCKHOLDER PROPOSALS AND NOMINATIONS FOR 2009 ANNUAL MEETING 
+OTHER MATTERS
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001047469-08-005543/proxy_rpt.txt b/raw/proxies/0001334036/0001047469-08-005543/proxy_rpt.txt
new file mode 100644
index 0000000000000000000000000000000000000000..d45da885b8638fffb835219ff05f160cb061e757
--- /dev/null
+++ b/raw/proxies/0001334036/0001047469-08-005543/proxy_rpt.txt
@@ -0,0 +1,22 @@
+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+Related Party Transactions 
+In 2008, we sponsored Germain Racing Truck #9 in the NASCAR Craftsman Truck Series. Justin Marks is employed by Germain Racing as the driver of Truck #9. Justin
+Marks is the son of our director, Michael Marks. The total amount of our sponsorship commitment to Germain Racing for 2008 is $600,000. We believe that a related person, Justin Marks, has a material
+interest in the sponsorship by virtue of his employment with Germain Racing as the driver of Truck #9. The sponsorship is part of our larger auto racing sponsorship and sports marketing efforts and
+was negotiated at an arms-length basis with terms similar to those of our other auto racing sponsorships. 
+Policy on Transactions with Related Persons 
+Our Business Code of Conduct and Ethics requires that any transaction involving us in which one of our directors, nominees for director, executive officers, or
+greater than five percent stockholders, or their immediate family members, have a material interest be approved or ratified by the Audit Committee if the amount involved exceeds $100,000. The full
+Board reviews ordinary course of business transactions in which directors have an interest as part of the Board's annual director independence review, and our Business Code of Conduct and Ethics
+requires the full board to waive any conflicts of interest between us and any director or officer. In determining whether to approve or ratify any such transaction, the Audit Committee must consider,
+in addition to other factors it deems appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. 
+All
+transactions disclosed above were reviewed and approved in accordance with this policy. 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify our directors and executive officers, in addition to the indemnification provided for in our certificate of
+incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain 
+23 
+expenses
+(including attorneys' fees), judgments, fines and settlement amounts incurred by any such person in any action or proceeding, including any action by or in the right of the Company, arising
+out of such person's services as a director or executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request. We believe
+that these provisions and agreements are necessary to attract and retain qualified persons as directors and executive officers.
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001047469-09-004667/proxy.txt b/raw/proxies/0001334036/0001047469-09-004667/proxy.txt
new file mode 100644
index 0000000000000000000000000000000000000000..9a9bd9cd20d719cd2be0edc89002ddbc7fb0e118
--- /dev/null
+++ b/raw/proxies/0001334036/0001047469-09-004667/proxy.txt
@@ -0,0 +1,1813 @@
+DEF 14A
+1
+a2192536zdef14a.htm
+DEF 14A
+QuickLinks 
+-- Click here to rapidly navigate through this document 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+SCHEDULE 14A 
+Proxy
+Statement Pursuant to Section 14(a) of 
+the Securities Exchange Act of 1934 (Amendment No. ) 
+Filed by the Registrant ý 
+Filed by a Party other than the Registrant o 
+Check the appropriate box: 
+o 
+Preliminary Proxy Statement 
+o 
+Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2)) 
+ý 
+Definitive Proxy Statement 
+o 
+Definitive Additional Materials 
+o 
+Soliciting Material Pursuant to §240.14a-12 
+CROCS, INC. 
+(Name of Registrant as Specified In Its Charter) 
+(Name of Person(s) Filing Proxy Statement, if other than the Registrant) 
+Payment of Filing Fee (Check the appropriate box): 
+ý 
+No fee required. 
+o 
+Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11. 
+(1) 
+Title of each class of securities to which transaction applies: 
+(2) 
+Aggregate number of securities to which transaction applies: 
+(3) 
+Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined): 
+(4) 
+Proposed maximum aggregate value of transaction: 
+(5) 
+Total fee paid: 
+o 
+Fee paid previously with preliminary materials. 
+o 
+Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration
+statement number, or the Form or Schedule and the date of its filing. 
+(1) 
+Amount Previously Paid: 
+(2) 
+Form, Schedule or Registration Statement No.: 
+(3) 
+Filing Party: 
+(4) 
+Date Filed: 
+Crocs, Inc. 
+6328 Monarch Park Place 
+Niwot, Colorado 80503 
+NOTICE OF THE 2008 ANNUAL MEETING OF STOCKHOLDERS TO 
+BE HELD JUNE 25, 2009 
+To
+the Stockholders of Crocs, Inc.: 
+We
+will hold the 2009 Annual Meeting of Stockholders of Crocs, Inc. at the St. Julien Hotel, 900 Walnut Street, Boulder, Colorado, on June 25, 2009, at
+9:00 a.m. Mountain Time. 
+The
+meeting's purpose is to: 
+1. elect
+two Class I directors;
+2. ratify
+the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for fiscal year 2009; and
+3. consider
+any other matters that properly come before the meeting or any postponement or adjournment thereof. 
+Only
+stockholders of record of our common stock at the close of business on April 27, 2009 are entitled to receive notice of and to vote at the meeting. Each share of common stock
+is entitled to one vote. 
+A
+list of the stockholders entitled to vote at the meeting will be available for examination at the meeting by any stockholder for any purpose relevant to the meeting. The list will also
+be available on the same basis for ten days prior to the meeting at our principal executive office, 6328 Monarch Park Place, Niwot, Colorado 80503. 
+All
+stockholders are cordially invited to attend the meeting in person. Whether or not you plan to attend the meeting in person, please vote your shares, as instructed in the Notice of
+Internet Availability of Proxy Materials, over the Internet, or by telephone after your receipt of hard copies of the proxy materials, as promptly as possible. You may also request a paper proxy card,
+which will include a reply envelope, to submit your vote by mail, as described in the Notice of Internet 
+Availability
+of Proxy Materials. Stockholders who are present at the Annual Meeting may withdraw their proxy and vote in person if they so desire. 
+BY ORDER OF THE BOARD OF DIRECTORS 
+John Duerden 
+President and Chief Executive Officer 
+Niwot,
+Colorado 
+April 28, 2009 
+Crocs, Inc. 
+6328 Monarch Park Place 
+Niwot, Colorado 80503 
+2009 ANNUAL MEETING OF STOCKHOLDERS 
+PROXY STATEMENT 
+This proxy statement will first be sent to stockholders on or about May 12, 2009. It is furnished to stockholders of
+Crocs, Inc., a Delaware corporation (the "Company," "we," "us," or "our"), in connection with the solicitation of proxies by our Board of Directors. The proxies being solicited will be voted at
+the 2009 Annual Meeting of Stockholders (the "Annual Meeting"), to be held on June 25, 2009 at 9:00 a.m., Mountain time, at the St Julien Hotel, 900 Walnut Street, Boulder,
+Colorado, or at any postponement or adjournment thereof, for the purpose of voting on proposals as set forth herein as well as other business matters which may properly come before the meeting. 
+Under
+the rules of the Securities and Exchange Commission, we are furnishing proxy materials to our stockholders on the Internet, rather than mailing printed copies to our stockholders.
+If you received a Notice of Internet Availability of Proxy Materials by mail, you will not receive a printed copy of the proxy materials unless you request one as instructed in that notice. Instead,
+the Notice of Internet Availability of Proxy Materials will instruct you as to how you may access and review the proxy materials on the Internet. If you received a Notice of Internet Availability of
+Proxy Materials by mail and would like to receive a printed copy of our proxy materials, please follow the instructions included in the Notice of Internet Availability of Proxy Materials. 
+GENERAL INFORMATION REGARDING ANNUAL MEETING 
+Record Date 
+Stockholders of record at the close of business on April 27, 2009 are entitled to notice of and to vote at the Annual Meeting.
+On the record date, there were 83,780,065 shares of our common stock outstanding. Each such share is entitled to one vote on each matter submitted to a vote at the Annual Meeting. 
+Quorum Requirements 
+A quorum is required to conduct business at the Annual Meeting. The holders of a majority of the outstanding shares entitled to vote
+generally in the election of directors must be present in person or by proxy at the Annual Meeting in order for a quorum to exist. Abstentions and broker non-votes count as present for
+purposes of determining a quorum. A broker non-vote occurs when a broker returns a proxy card but does not vote on one or more matters because the broker does not have the 
+1 
+authority
+to do so without instructions from the beneficial owner. Shares represented by proxies that are marked WITHHOLD with respect to the election of directors will be counted as present in
+determining whether there is a quorum. 
+Vote Requirements 
+If a quorum is present at the Annual Meeting, the following vote is required for approval of each matter to be voted on: 
+Election of Directors: The election of the director nominees will require a plurality of the votes cast in person or by proxy at the
+Annual Meeting.
+"Plurality" means that the nominees who receive the highest number of votes cast are elected as directors up to the maximum number of directors to be elected at the Annual Meeting. Consequently,
+proxies marked WITHHOLD and broker non-votes will have no impact on the election of directors. Cumulative voting is not permitted. 
+Ratification of Appointment of Deloitte & Touche LLP: The affirmative vote of the holders of a majority of the shares of
+our common
+stock present in person or by proxy and entitled to vote at the Annual Meeting is required for the ratification of the appointment of Deloitte & Touche LLP as our independent registered
+public accounting firm for fiscal year 2009. Proxies marked ABSTAIN will have the effect of voting against this proposal. Broker non-votes will have no impact on the proposal. 
+Other Proposals: With respect to any other matters properly brought before the Annual Meeting, the affirmative vote of a majority of
+the shares of
+common stock present in person or by proxy and entitled to vote on the matter will be the act of the stockholders. Broker non-votes will have no effect on these proposals, and abstentions
+will have the effect of voting against these proposals. 
+Your Proxy 
+Whether or not you are able to personally attend the Annual Meeting, you are encouraged to vote your shares as instructed in the Notice
+of Internet Availability of Proxy Materials. Shares represented by properly executed methods, and not revoked prior to the Annual Meeting, will be voted at the Annual Meeting as directed in the proxy. If no directions are
+specified, such proxies will be voted FOR each of the proposals described in this proxy statement and in the best judgment of the proxy holders as to other
+matters that may properly come before the Annual Meeting. 
+If
+your shares are held in the name of a bank or brokerage firm, your bank or broker will send you a separate package describing the procedures and options for voting your shares. You
+should follow the instructions provided by your bank or brokerage firm. If you do not instruct your broker how to vote, your broker will vote your shares for you at his or her discretion on routine
+matters such as the election of directors and ratification of the appointment of our independent registered public accounting firm. 
+Revocation 
+Any stockholder giving a proxy has the power to revoke the proxy, or change the proxy, at any time before the proxy is voted at the
+Annual Meeting by (i) re-voting online at www.proxyvote.com, (ii) sending another properly executed proxy bearing a later date or a written notice of revocation of the proxy
+to Corporate Secretary, Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503 or (iii) voting in person at the Annual Meeting. 
+Attending the Annual Meeting 
+You are invited to personally attend the Annual Meeting. 
+2 
+Cost of Proxy Solicitation 
+We will bear the entire cost of this proxy solicitation. We may reimburse brokers, custodians, nominees and other fiduciaries for
+normal handling charges incurred for forwarding proxy materials to beneficial owners. Solicitation of proxies may be made personally or by mail or telephone by our directors, officers and other
+employees, who will receive no additional compensation for such services. 
+PROPOSAL 1—ELECTION OF DIRECTORS 
+Our Board of Directors currently consists of eight members divided into three classes, with each director elected to a
+three-year term. Class I consists of Ronald L. Frasch and W. Stephen Cannon, whose terms will expire at the Annual Meeting. Class II consists of Raymond D. Croghan, Peter
+Jacobi and Richard L. Sharp, whose terms will expire at the annual meeting to be held in 2010. Class III consists of Thomas J. Smach, Ronald R. Snyder and John Duerden, whose terms will expire
+at the annual meeting to be held in 2011. Under our amended and restated bylaws, each of our directors holds office until his or her successor has been elected and qualified or until such director's
+earlier death, resignation, disqualification or removal. 
+Upon
+recommendation of the Governance and Nominating Committee, the Board of Directors has nominated Messrs. Frasch and Cannon for election as Class I directors to serve
+for a three year term expiring at the 2012 annual meeting of stockholders. 
+Proxies
+cannot vote for more than two nominees. Each of the director nominees has consented to serve for a three-year term. We do not contemplate that any of the nominees
+will be unable to stand for election, but should any nominee become unable to serve or will not serve for any reason, all proxies (except proxies marked to the contrary) will be voted for the election
+of a substitute nominee as our Board of Directors may recommend. 
+Class I Director Nominees 
+Ronald L. Frasch ( Class I ), age
+60, has served as a member of our Board of Directors since October 2006. Since February 2007, Mr. Frasch has served as President and Chief Merchandising Officer of Saks Fifth Avenue, a division
+of Saks, Incorporated, and a NYSE-listed luxury fashion retailer. He held the post of Vice Chairman and Chief Merchant of Saks Fifth Avenue from November 2004 until January 2007. From
+January 2004 to November 2004, Mr. Frasch was employed by Saks in a non-executive capacity. From April 2000 to January 2004, Mr. Frasch served as Chairman and Chief Executive
+Officer of Bergdorf Goodman (a subsidiary of Neiman Marcus Group, Inc.) and served as President of GFT North America (a subsidiary of Gruppo GFT, based in Turin, Italy, a global producer,
+marketer and distributor of fine men's and women's clothing, sportswear and furnishings) from 1996 to 2000. Mr. Frasch also served as President and Chief Executive Officer of Escada USA from
+1994 to 1996. 
+W. Stephen Cannon ( Class I ), age 57, was appointed as a member of our Board of
+Directors in February 2009. Since 2005, he has served as the Chairman of Constantine Cannon LLP, a law firm, and the Managing Partner of Constantine Cannon's Washington D.C. office. From 1994
+to 2005, Mr. Cannon was the Senior Vice President, General Counsel and Secretary of Circuit City Stores, Inc., a retailer of consumer electronics, which, at the time, was publicly traded
+on the New York Stock Exchange. Prior to joining Circuit City Stores, Inc., Mr. Cannon served as a partner at the law firm of Wunder, Diefenderfer, Ryan, Cannon and Thelen and spent
+10 years in government service, including serving as Chief Antitrust Counsel to the United States Senate Judiciary Committee. 
+3 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" ALL 
+OF THE ABOVE-NAMED NOMINEES FOR DIRECTOR. 
+Information About Continuing Directors 
+Peter Jacobi ( Class II ), age 65,
+has served as a member of our Board of Directors since October 2008. Mr. Jacobi was employed by Levi Strauss & Company ("Levi Strauss"), a jeans and casual wear manufacturer, from 1970
+until his retirement in 1999. During his nearly 30 year tenure at Levi Strauss, Mr. Jacobi held various senior levels positions, including President of the Men's Jeans Division,
+President of Global Sourcing, President of Levi Strauss International, and from 1996 until his retirement, President and Chief Operating Officer. 
+Raymond D. Croghan ( Class II ), age 59, has served as a member of our Board of
+Directors since August 2004. Since 1999, Mr. Croghan has been retired. From 1991 to 1999, Mr. Croghan ran Croghan & Associates, Inc., a healthcare information technology
+consulting firm, which merged with Margolis Health Enterprise to form The TriZetto Group. Mr. Croghan serves on the boards of directors of several privately-held companies. 
+Richard L. Sharp ( Class II ), age 62, has served as the Chairman of our Board of
+Directors since April 2005. From 1982 to 2002, Mr. Sharp served in various positions with Circuit City Stores, Inc., a retailer of consumer electronics, most recently as President from
+1984 to 1997, Chief Executive Officer from 1986 to 2000 and Chairman of the Board from 1994 to 2002. Mr. Sharp served as Chairman and Chief Executive Officer of CarMax, Inc., the
+nation's largest specialty retailer of used cars and light trucks, from 1994 to 2000 and Chairman from October 2002 to June 2007. In 1992, he was a founding investor of Flextronics International
+("Flextronics"), a NASDAQ-listed (Nasdaq: FLEX) leading Electronics Manufacturing Services (EMS) provider. He served as a director of Flextronics from 1993 to October 2008 and as Chairman of the Board
+from January 2003 to January 2006. 
+Thomas J. Smach ( Class III ), age 48, has served as a member of our Board of
+Directors since April 2005. Mr. Smach is currently a co-founding partner of Riverwood Capital Management, a private equity firm. From January 2005 to June 2008, Mr. Smach
+served as the Chief Financial Officer of Flextronics. From April 2000 to December 2004, Mr. Smach served as Senior Vice President—Finance of Flextronics. From 1997 to April 2000, he
+served as the Senior Vice President, Chief Financial Officer and Treasurer of The Dii Group, Inc., an EMS provider and publicly-traded company that merged with Flextronics in early 2000 ("The
+Dii Group"). Mr. Smach is a certified public accountant and also serves on the Board of Directors of ADVA AG Optical Networking, a publicly-traded company in Germany. 
+Ronald R. Snyder ( Class III ), age 52, has served as a member of our Board of
+Directors since June 2004. He served as our Chief Executive Officer from January 2005 to March 2009, served as our President from June 2004 to March 2009, and served as a consultant from October 2003
+to June 2004. From March 2004 to December 2004, he was Chief Executive Officer of Vinci Corporation, a home theater equipment company. From April 2000 to December 2003, Mr. Snyder served as a
+senior executive with Flextronics, where he was most recently President of the Flextronics design division. Mr. Snyder joined
+Flextronics upon its acquisition of The Dii Group, of which he was a founder and an officer and where he had previously led various groups, including manufacturing operations, mergers and
+acquisitions, and sales and marketing. 
+John Duerden ( Class III ), age 68, was appointed as our President and Chief
+Executive Officer and a member of our Board of Directors effective in March 2009. Prior to his appointment, Mr. Duerden was the founder and owner of the Chrysallis Group, a consulting firm
+focused on the development and renewal of brands, which he founded in 2006. From 2004 to 2006, Mr. Duerden served as a non-executive director of Telewest plc, a British cable
+TV, telephony and broadband company. From 2002 to 2005, he was the Chief Operating Officer of the development division of Invensys plc, a British engineering conglomerate. From 1995 to 2001,
+Mr. Duerden was the Chairman and Chief Executive 
+4 
+Officer
+of Dictaphone Corp., a maker of dictation, voice management and voice processing hardware and software. From 1990 to 1995, he served as President and Chief Operating Officer of Reebok
+International, a producer of athletic footwear, apparel and accessories. Mr. Duerden currently serves as a director of Obagi Medical Products, Inc. 
+EXECUTIVE OFFICERS 
+In addition to John Duerden, our President and Chief Executive Officer, whose biographical information is disclosed above under
+"Election of Directors," our executive officers as of March 31, 2009 include the following individuals: 
+Name
+Age 
+Position(s) 
+John P. McCarvel 
+52 
+Chief Operating Officer and Executive Vice President 
+Russell C. Hammer 
+52 
+Chief Financial Officer, Senior Vice President—Finance and Treasurer 
+Erik Rebich 
+38 
+Vice President, General Counsel and Secretary 
+John P. McCarvel has served as our Chief Operating Officer and Executive Vice President since February 2007. Previously,
+Mr. McCarvel served as our Senior Vice President—Global Operations from October 2005 to February 2007 and as our Vice President—Asian & Australian Operations from
+January 2005 to September 2005, after providing consulting services to us during 2004. From October 2001 to January 2005, Mr. McCarvel served as Vice President for the Design, Test and
+Semiconductor division of Flextronics, where he was responsible for building Flextronics' engineering infrastructure in Asia and growing Flextronics' business in the region. From 1999 to October 2001,
+he served as President of U.S. Operations and Senior Vice President of Worldwide Sales and Marketing for Singapore Technology Assembly Test Services Ltd., a semiconductor services company. He
+previously worked in executive level positions with Micron Custom Manufacturing Services, Inc., a manufacturer of electronic products for computing and digital applications, and The Dii Group. 
+Russell C. Hammer has served as our Chief Financial Officer, Senior Vice President of Finance and Treasurer since January 2008. Prior to
+joining us, Mr. Hammer was employed for 30 years at Motorola, Inc. ("Motorola"), a global supplier of wireless handsets and mobile communication products. Mr. Hammer served
+as Chief Financial Officer and Corporate Vice President of Motorola's Connected Home Solutions Business from April 2005 to August 2007. From August 2002 to March 2005, he served as Chief Audit Officer
+for Motorola, and from August 1998 to July 2002, he served as the Chief Financial Officer of the Asia Cellular Subscriber Business of Motorola. Mr. Hammer also served in other executive roles
+for Motorola's various divisions during his tenure with the company. 
+Erik Rebich has served as our Vice President, General Counsel and Secretary since January 2005. From 2004 to 2005, Mr. Rebich
+served as Corporate Counsel for Flextronics. From 2000 to 2004, he served as General Counsel for Multilayer Technology, Inc.(Multek), a printed circuit board manufacturing corporation and
+wholly-owned subsidiary of Flextronics. From 1998 to 2000, Mr. Rebich served as Corporate Counsel for The Dii Group. 
+5 
+BENEFICIAL OWNERSHIP OF OUR COMMON STOCK 
+The following table sets forth information with respect to the beneficial ownership of our common stock as of March 31, 2009
+by: 
+• each person (or group of affiliated persons) who is known by us to own beneficially more than 5% of our common stock; 
+• each current director or nominee; 
+• each of the named executive officers listed in the Summary Compensation Table below (each an "NEO"); and 
+• all directors and executive officers as a group. 
+Beneficial
+ownership is determined in accordance with the Securities and Exchange Commission ("SEC") rules. In computing percentage ownership of each person, shares of common stock
+subject to options held by that person that are currently exercisable or convertible, or exercisable or convertible within 60 days after March 31, 2009, are deemed to be outstanding and
+beneficially owned by that person. In addition, shares that are required to be issued by us to any person pursuant to a restricted stock award agreement within 60 days after March 31,
+2009 are also deemed to be outstanding and beneficially owned by that person. None of these shares, however, are deemed outstanding for the purpose of computing the percentage ownership of any other
+person. 
+Except
+as indicated in this table and pursuant to applicable community property laws, each stockholder named in the table has sole voting and investment power with respect to the shares
+set forth opposite such stockholder's name. Percentage ownership is based on 83,717,536 shares of our common stock outstanding on March 31, 2009. Unless otherwise indicated below, the address
+for each person who owns more than 5% of our voting securities and for each director and named executive officer listed below is in care of Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado
+80503. 
+Beneficial Ownership 
+Name of Beneficial Owner
+Shares 
+Percent 
+5% Stockholders: 
+Mazama Capital Management, Inc.(1) 
+7,427,077 
+8.9% 
+William H. Gates III(2) 
+6,000,000 
+7.2% 
+Barclays Global Investors, N.A. and affiliates(3) 
+5,423,485 
+6.4% 
+Directors: 
+Richard L. Sharp(4) 
+1,571,158 
+1.9% 
+Peter Jacobi 
+20,490 
+* 
+Thomas J. Smach(5) 
+250,914 
+* 
+Raymond D. Croghan(6) 
+180,362 
+* 
+W. Stephen Cannon 
+24,398 
+* 
+Ronald L. Frasch(7) 
+41,494 
+* 
+John Duerden(8) 
+— 
+* 
+Officers: 
+Ronald R. Snyder(9) 
+1,916,790 
+2.3% 
+Russell C. Hammer(10) 
+167,000 
+* 
+John P. McCarvel(11) 
+670,070 
+* 
+Erik Rebich (12) 
+276,848 
+* 
+Peter Case (13) 
+124,168 
+* 
+All current directors and executive officers as a group (11 persons)(14) 
+5,642,512 
+6.7% 
+* Less
+than 1% 
+6 
+(1) Based
+solely on a Schedule 13G filed with the SEC on February 13, 2009. The address for Mazama Capital Management, Inc. is One
+Southwest Columbia Street, Suite 1500, Portland, Oregon 97258.
+(2) Based
+solely on a Schedule 13G filed with the SEC on February 13, 2009 by William H. Gates III and Cascade Investment LLC and
+affiliates. The address for William H Gates III is One Microsoft Way, Redmond, WA 98052. Cascade Investment, LLC ("Cascade") reports sole voting and sole dispositive power with respect to
+3,000,000 shares. All shares beneficially owned by Cascade may be deemed to be beneficially owned by William H. Gates III, as the sole member of Cascade. The Bill & Melinda Gates Foundation
+Trust (the "Trust") reports shared voting and shared dispositive power with respect to 3,000,000 shares. All shares beneficially owned by the Trust may be deemed to be beneficially owned by William H.
+Gates III and Melinda French Gates, as co-trustees of the Trust. William H. Gates III reports sole voting and sole dispositive power with respect to the 3,000,000 shares beneficially owned
+by Cascade and shared voting and shared dispositive power with respect to the 3,000,000 shares beneficially owned by the Trust.
+(3) Based
+solely on a Schedule 13G filed with the SEC on February 5, 2009 by Barclays Global Investors, N.A. and its affiliates. The address for
+Barclays Global Investors N.A. is 400 Howard Street, San Francisco, CA 94105. Barclays Global Investors, N.A. reports sole voting power with respect to 1,615,312 shares and sole dispositive power with
+respect to 1,953,815 shares; Barclays Global Fund Advisors reports sole voting power with respect to 2,464,890 shares and sole dispositive power with respect to 3,415,425; Barclays Global
+Investors, LTD reports sole voting power with respect to 1,770 shares and sole dispositive power with respect to 54,245 shares.
+(4) Shares
+beneficially owned include 409,234 shares subject to options exercisable within 60 days of March 31, 2009, 811,494 shares beneficially
+owned by The RLS Trust, 116,810 shares beneficially owned by BES & RS, LLC, 116,810 shares beneficially owned by EGG & RS, LLC, and 116,810 shares beneficially owned by
+RBG & RS, LLC. Mr. Sharp is the sole trustee of The RLS Trust and is the sole manager of each of BES & RS, LLC, EGG & RS, LLC, and RBG &
+RS, LLC, and he exercises voting and investment power over all of the shares beneficially owned by the trust and each company. The address for Mr. Sharp is 9020 Stony Point Parkway,
+#180, Richmond, VA 23235.
+(5) Shares
+beneficially owned include 234,420 shares subject to options exercisable within 60 days of March 31, 2009 and 5,000 shares held as
+custodian for Mr. Smach's two children and nephew under the New York Uniform Gifts to Minors Act. Mr. Smach exercises voting and investment power over the shares.
+(6) Shares
+beneficially owned include 163,908 shares subject to options exercisable within 60 days of March 31, 2009 and an aggregate of 4,960
+shares of common stock beneficially owned by two trusts for the benefit of Mr. Croghan's two daughters. Mr. Croghan's spouse is the trustee of both trusts and she exercises sole voting
+and investment power over the shares. Mr. Croghan disclaims beneficial ownership of such shares.
+(7) Shares
+beneficially owned include 30,000 shares subject to options exercisable within 60 days of March 31, 2009.
+(8) Mr. Duerden
+was appointed as our President and Chief Executive Officer and a director effective March 18, 2009.
+(9) Shares
+beneficially owned include 649,457 shares subject to options exercisable within 60 days of March 31, 2009.
+(10) Shares
+beneficially owned include 50,000 shares subject to options exercisable within 60 days of March 31, 2009. 
+7 
+(11) Shares
+beneficially owned include 295,906 shares subject to options exercisable within 60 days of March 31, 2009 and 254,364 shares held
+jointly with his spouse.
+(12) Shares
+beneficially owned include 61,636 shares subject to options exercisable within 60 days of March 31, 2009.
+(13) Shares
+beneficially owned represent shares subject to options exercisable within 60 days of March 31, 2009.
+(14) Shares
+beneficially owned include 837,562 shares of common stock subject to options issued to seven directors and 1,056,999 shares of common stock subject
+to options issued or restricted stock awards granted to four current executive officers that are exercisable or issuable within 60 days of March 31, 2009. 
+BOARD OF DIRECTORS AND COMMITTEES OF THE BOARD 
+Board Composition 
+Our Board of Directors currently consists of eight members divided into three classes, with each director elected to a
+three-year term. Under our amended and restated bylaws, each of our directors holds office until his or her successor is elected and qualified or until such director's earlier death,
+resignation, disqualification or removal. 
+At
+each annual meeting of stockholders, the successors to directors whose terms expire at such meeting will be elected, or such directors will be re-elected, and will serve
+from the time of election and qualification until the third annual meeting following their election or until their successors are duly elected and qualified. The current authorized number of directors
+is eight. The authorized number of directors may be changed by resolution of the Board. Any additional directorships resulting from an increase in the number of directors will be distributed among the
+three classes so that, as nearly as possible, each class will consist of one-third of the directors. Vacancies on the Board can be filled by resolution of the Board of Directors. 
+NASDAQ
+listing standards require that our Board of Directors have a majority of independent directors. The Board of Directors has determined that all of the current
+non-management members of our Board of Directors, except Mr. Snyder, are independent directors as defined by Rule 4200(a) (15) of the NASDAQ listing standards. The
+Board makes a determination regarding the independence of each director annually based on the relevant facts and circumstances. Applying the standards and independence criteria defined by the NASDAQ
+listing standards, the Board has made a subjective determination as to each independent director that no relationships exist that, in the opinion of the Board, would interfere with the exercise of his
+or her independent judgment in carrying out the responsibilities of a director. 
+During
+2008, the Board of Directors met ten times and acted by written consent on various other occasions. All directors attended 75% or more of the meetings of the Board of Directors
+and the meetings of the committees of the Board on which they serve, with the exception of Messrs. Frasch and Croghan, who each attended 70% or more of the meetings of the Board and the
+committees on which they serve. The outside directors of the Board hold executive sessions without members of management present. We encourage, but do not require, our directors to attend the annual
+meeting. Mr. Snyder and Mr. Croghan attended our 2008 annual meeting of stockholders. 
+Stockholders
+who wish to communicate with the Board of Directors or with specified individual directors may do so by mailing such written communication to: Corporate Secretary,
+Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503. The Corporate Secretary will review all correspondence and will forward to the Board or an individual director a summary of the
+correspondence received and copies of correspondence that the Corporate Secretary determines requires the attention of the Board 
+8 
+or
+such individual director. The Board or an individual director may at any time request copies and review all correspondence received by the Corporate Secretary that is intended for the Board or such
+individual director. 
+Board Committees 
+Our Board of Directors has the authority to appoint committees to perform certain management and administrative functions. Our Board of
+Directors has established the following committees: 
+Audit Committee. Messrs. Smach (Chairman), Frasch and Jacobi are the current members of our Audit Committee. During 2008, the
+members of our
+Audit Committee were Messrs. Smach, Frasch and Croghan. The Audit Committee met seven times in 2008. The functions of the Audit Committee include oversight of the integrity of our financial
+statements, our compliance with legal and regulatory requirements, the performance, qualifications and independence of our independent auditors and the performance of our internal audit function. Our
+Audit Committee is directly responsible, subject to stockholder ratification, for the appointment, retention, compensation, evaluation, termination and oversight of the work of any independent auditor
+engaged for the purpose of preparing or issuing an audit report or related work. The purpose and responsibilities of our Audit Committee are set forth in the Audit Committee Charter, which was amended
+and restated by our Board of Directors on February 18, 2008. The amended and restated Audit Committee Charter can be found on our website at www.crocs.com . 
+All
+of the members of the Audit Committee are independent, as determined in accordance with NASDAQ listing standards and relevant federal securities laws and regulations. Our Board of
+Directors has determined that Mr. Smach qualifies as an "audit committee financial expert" as defined by the applicable regulations of the SEC. 
+Compensation Committee. Messrs Croghan (Chairman), Sharp and Cannon are the current members of our Compensation Committee. During
+2008, our
+Compensation Committee consisted of Messrs. Michael E. Marks, who resigned from the Board effective July 29, 2008, Croghan (Chairman) and Sharp. The Compensation Committee met nine times
+in 2008. The Compensation Committee has overall responsibility for evaluating and approving our executive officer incentive compensation, benefits, severance, equity-based or other compensation plans,
+policies and programs. The Compensation Committee is also responsible for approving our Compensation Discussion and Analysis for inclusion in our proxy statement. The purpose and responsibilities of
+our Compensation Committee are set forth in the Compensation Committee Charter, which was approved by our Board of Directors on June 30, 2005. The Compensation Committee Charter can be found on
+our website at www.crocs.com . All of the current members of the Compensation Committee are independent, as determined in accordance with NASDAQ listing
+standards and relevant federal securities laws and regulations. 
+Role of the Compensation Committee. The Compensation Committee has the authority to establish and monitor the executive compensation
+programs and to
+make decisions regarding the compensation of the NEOs. The Compensation Committee sets the Chief Executive Officer's compensation. The Compensation Committee also reviews the recommendations of the
+Chief Executive Officer with respect to compensation of the other NEOs and, after reviewing such recommendations, sets the compensation of the other NEOs. The Compensation Committee also monitors,
+administers and approves awards under our various incentive compensation plans for all levels of our employees, including awards under our 2007 Equity Incentive Plan and 2008 Cash Incentive Plan. 
+The
+Compensation Committee relies on its judgment in making compensation decisions after reviewing our performance and evaluating each executive's performance against established goals,
+leadership ability and responsibilities, and current compensation arrangements. When setting total 
+9 
+compensation
+for each of the NEOs, the Compensation Committee reviews the NEO's current compensation, which includes equity and non-equity based compensation. The Compensation Committee
+also evaluates surveys and other available data regarding the executive compensation programs of comparative companies. The compensation program for NEOs and the Compensation Committee assessment
+process are designed to be flexible so as to better respond to the evolving business environment and individual circumstances. 
+Role of Consultants. In evaluating 2008 executive compensation, the Compensation Committee and management engaged a third party
+consultant, Mercer,
+to provide an overall evaluation of our NEO compensation, including a comparison against our peers, on elements of compensation including base pay, performance based bonuses and long-term
+equity awards. The peer group information, which includes peers utilized in 2007 (detailed in Executive Compensation and Analysis later in this
+document), was collected and presented to the Compensation Committee by Mercer in March 2008. The use of these market benchmarks, while helpful to the Committee in determining 2008 executive
+compensation, is principally intended to assist the Compensation Committee as a point of reference and is not considered to be determinative in the Compensation Committee's decision-making process.
+The Compensation Committee is granted authority to retain such outside counsel, experts and other advisers as deemed necessary. 
+Employment and Severance Agreements. Certain of our NEOs have employment agreements, as described more fully later in this document. In
+addition,
+unvested options and restricted stock may become vested on a change in control pursuant to individual option or restricted stock award agreements. The NEOs serve at the will of the Board, which
+enables us to terminate their employment with discretion and to determine the terms of any severance. This is consistent with our performance-based employment and compensation philosophy. 
+Governance and Nominating Committee. Our Governance and Nominating Committee currently consists of Messrs. Sharp (Chairman) and
+Cannon. During
+2008, Mr. Sharp and Ms. Marie Holman-Rao were members of our Governance and Nominating Committee. Ms. Holman-Rao resigned from the Board effective
+September 8, 2008. The Governance and Nominating Committee met once in 2008. The Governance and Nominating Committee assists our Board of Directors in promoting the best interests of the
+Company and our stockholders through the implementation of sound corporate governance principles and practices. In furtherance of this purpose, the Governance and Nominating Committee identifies
+individuals qualified to become board members
+and recommends to our Board of Directors the director nominees for each annual meeting of stockholders. It also reviews the qualifications and independence of the members of our Board of Directors and
+its various committees and makes any recommendations the Governance and Nominating Committee members may deem appropriate concerning any recommended changes in the composition of our Board of
+Directors and its committees. The Governance and Nominating Committee also recommends to our Board of Directors the corporate governance guidelines and standards regarding the independence of outside
+directors applicable to us and reviews the provisions of the Governance and Nominating Committee Charter on a regular basis to confirm that such guidelines, standards and charter remain consistent
+with sound corporate governance practices and with any legal or regulatory requirements of NASDAQ. The Governance and Nominating Committee also monitors and leads our Board of Directors in its annual
+review of our Board of Directors' performance. 
+The
+purpose and responsibilities of our Governance and Nominating Committee are set forth in the Governance and Nominating Committee Charter, which was approved by our Board of Directors
+on June 30, 2005. The Governance and Nominating Committee Charter can be found on our website at www.crocs.com . All of the members of the
+Governance and Nominating Committee are independent, as determined in accordance with the NASDAQ listing standards. 
+10 
+Director Nomination Process. In identifying potential director candidates, the Governance and Nominating Committee relies on
+recommendations from a
+number of sources, including current directors and officers. The Governance and Nominating Committee may also hire outside consultants or search firms or other advisors to assist in identifying
+director candidates. The Governance and Nominating Committee will consider director candidates recommended by stockholders on the same basis as it considers other candidates. Any stockholder wishing
+to recommend a candidate for consideration by the Governance and Nominating Committee may do so by submitting a written recommendation to the Governance and Nominating Committee in accordance with the
+procedures set forth under "Stockholder Proposals and Nominations for 2010 Annual Meeting." 
+In
+evaluating a candidate for director, the Governance and Nominating Committee considers, among other things, the candidate's judgment, knowledge, integrity, business and industry
+experience, and expertise, which are likely to enhance the Board of Director's ability to govern our affairs and business. The Governance and Nominating Committee also takes into account independence
+requirements imposed by law or regulations (including the NASDAQ listing standards). In the case of director candidates recommended by stockholders, the Governance and Nominating Committee may also
+consider the number of shares held by the recommending stockholder, the length of time that such shares have been held and the relationship, if any, between the recommending stockholder and the
+recommended director nominee. 
+Code of Business Conduct and Ethics and Committee Charters 
+We have adopted a Code of Business Conduct and Ethics that applies to all directors and employees, including our principal executive,
+financial and accounting officers. The Amended and Restated Code of Business Conduct and Ethics (as of February 18, 2008) is posted on our website at www.crocs.com . We intend to satisfy the
+requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or
+waivers from, provisions of our Amended and Restated Code of Business Conduct and Ethics that apply to our directors and principal executive, financial and accounting officers by posting such
+information on our website. The Audit Committee Charter, Compensation Committee Charter and Governance and Nominating Committee Charter are also available on our website at www.crocs.com . Any person may
+request a copy of the Amended and Restated Code of Business Conduct and Ethics or committee charters free of charge by
+submitting a written request to: Corporate Secretary, Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503. 
+Compensation of Directors 
+The table below summarizes the total compensation paid or earned by each of the non-employee directors for the fiscal year
+ended December 31, 2008. Note that director-nominee W. Stephen Cannon was not appointed until February 24, 2009 and therefore, Mr. Cannon did not receive any director fees or
+equity grants in 2008. 
+Year 
+Fees Earned or 
+Paid in Cash 
+Stock Awards(1) 
+Option Awards(1) 
+Total 
+Raymond D. Croghan 
+2008 
+$ 
+60,000 
+$ 
+99,998 
+$ 
+332,389 
+$ 
+492,387 
+Ronald L. Frasch 
+2008 
+60,000 
+99,998 
+279,620 
+439,618 
+Peter Jacobi 
+2008 
+20,000 
+73,149 
+— 
+93,149 
+Richard L. Sharp 
+2008 
+65,000 
+99,998 
+347,423 
+512,421 
+Thomas J. Smach 
+2008 
+70,000 
+99,998 
+479,064 
+649,062 
+(1) Amounts
+reflect the dollar amount recognized for financial statement reporting purposes for the year ended December 31, 2008, in accordance with
+SFAS 123R and includes amounts from awards granted in and prior to 2008. Assumptions used in the calculations of these amounts are set forth in Footnote 10 to our Consolidated Financial
+Statements included in our Annual Report on Form 10-K for the year ended December 31, 2008. 
+11 
+As of December 31, 2008, each non-employee director had the following number of stock options outstanding. All information regarding options outstanding have been
+restated, as appropriate, to reflect to the 2-for-1 stock split that occurred on June 14, 2007, which was effected as a 100% common stock dividend distributed on that
+date. 
+Options 
+Outstanding at 
+December 31, 2008(1) 
+Raymond D. Croghan 
+203,510 
+Ronald L. Frasch 
+85,000 
+Peter Jacobi 
+— 
+Richard L. Sharp 
+307,024 
+Thomas J. Smach 
+132,210 
+(1) Option
+awards with exercise prices that are equal to or greater than $10.50 are subject to the Tender Offer as described in Compensation Discussion & Analysis. Participation in the Tender Offer is
+voluntary. 
+On
+June 26, 2008, the Board of Directors approved a new compensation arrangement for non-employee directors, effective as of that date. Pursuant to the new Board of
+Directors Compensation Plan, each of our non-employee directors will receive $80,000 in annual cash compensation, payable quarterly in $20,000 installments. Further, the chairperson of the
+Audit Committee will receive an additional $10,000 and each of the chairpersons of the Compensation Committee and the Governance and Nominating Committee will receive an additional $5,000. All
+directors were reimbursed for their reasonable out-of-pocket expenses incurred in attending meetings of the Board of Directors and its committees. Prior to June 26,
+2008, our
+non-employee directors each received cash compensation of $10,000 per quarter plus additional amounts for those directors serving as chairpersons of each of the committees of the Board of
+Directors. 
+Under
+the most recent Board of Directors compensation plan, each non-employee director is awarded an annual grant of $100,000 of Company common stock based on the fair market
+value of the shares at the grant date. The non-employee directors were granted $100,000 of common stock, or a prorated amount if such non-employee director joined the Board
+after June 26, 2008, based on the closing price of the Company's common stock on June 26, 2008. In addition, the Chairman of the Board is awarded an annual option to purchase 10,000
+shares of the Company's common stock at an exercise price equal to the fair market value of the shares at the date of grant. This option will vest and become exercisable in four equal installments on
+the respective dates of the next four annual meetings of stockholders. 
+EXECUTIVE COMPENSATION 
+COMPENSATION DISCUSSION AND ANALYSIS 
+The following discussion and analysis provides information regarding our executive compensation objectives and principles, procedures,
+practices and decisions, and is provided to help give perspective to the numbers and narratives that follow in the tables within this section. This discussion will focus on our objectives, principles,
+practices and decisions with respect to the compensation of the following named executive officers (the "NEOs"): 
+• Ronald R. Snyder, Director and former Chief Executive Officer and President 
+• John P. McCarvel, Chief Operating Officer and Executive Vice President 
+• Peter S. Case, Senior Vice President of the Retail Division and Former Chief Financial Officer 
+• Russell C. Hammer, Chief Financial Officer, Senior Vice President—Finance and Treasurer 
+12 
+• Erik Rebich, Vice President, General Council and Secretary 
+Note
+that Mr. Case served as our Chief Financial Officer until January 16, 2008 and ceased to serve as an executive officer on such date. 
+Executive Compensation Objectives and Principles 
+The overall objective of our executive compensation program is to create long-term value for our stockholders by attracting
+and retaining talented executives, rewarding superior operating and financial performance, and aligning the long-term interests of our executives with those of our stockholders.
+Accordingly, our executive compensation program incorporates the following principles: 
+• Compensation should be based on individual job responsibility, demonstrated leadership ability, management experience,
+individual performance and our performance. Employees in positions of leadership and broad responsibility are generally compensated by elements that are linked to our overall performance and
+stockholder returns. 
+• Compensation should reflect the fair market value of the services received. We believe that a fair and competitive pay
+package for our NEOs is essential to attract and retain talented executives in key positions. 
+• Compensation is designed to reward NEOs based on both our short-term and long-term performance.
+Base pay is tied to individual performance and market conditions for similar positions. Bonuses are tied to achievement of short-term quantitative performance goals that we believe closely
+correlate to share value. Long-term performance is rewarded through equity-based awards such as stock options, the value of which depends on future share prices, and the realization of
+which is contingent on satisfaction of vesting schedules requiring continued service with us. 
+• Compensation should foster long-term focus. Compensation is designed to align executives' interests with those
+of our stockholders. A significant percentage of total compensation is allocated to non-cash compensation as a result of this philosophy. We do not use an exact formula for allocating
+between cash and non-cash compensation. 
+The
+Compensation Committee forms its judgments regarding the levels and component mix of executive compensation by considering the market competition for executive talent, the risk to an
+executive inherent in employment with a company that has a relatively short operating history, and our financial goals. For the year ended December 31, 2008, we did not award any cash incentive
+bonuses due to our financial performance during the year. Specifically, cash incentive bonuses for our NEOs were payable contingent upon the achievement of certain milestones related to growth in our
+diluted earnings per share. For the year ended December 31, 2008, our diluted earnings per share declined 212% from earnings per share of $2.00 in the year ended December 31, 2007 to a
+loss per share of $2.24 in the year ended December 31, 2008. We did, however, grant certain of our NEOs stock options and stock awards in order to retain key talent and foster a
+long-term focus. 
+Elements of Compensation 
+Our executive compensation objectives and principles are implemented through the use of the following elements of compensation, each of
+which is discussed more fully below: 
+• Base Pay 
+• Performance-Based Bonus 
+• Long-Term Equity Awards 
+• Other Personal Benefits 
+13 
+Our
+executive compensation program seeks to attract, retain, and motivate exemplary executive talent who are able to succeed in our fast paced, rapidly evolving company. Our executive
+compensation program also seeks to hold our executives accountable and reward them appropriately for successful business results. We are firmly committed to our stockholders and our executive
+compensation program is structured to align our executives' compensation with our stockholders' interests. To meet each of these objectives, our core executive compensation program encompasses base
+salaries, annual performance-based incentive compensation, and long term equity incentive awards. We believe that the total compensation opportunities offered to our executives are sufficient to
+reduce the need for anything other than limited executive perquisites (which are detailed later in this report) or enhanced benefit programs beyond those that are typically available to all other
+employees. 
+The
+Compensation Committee does not utilize an exact calculation in determining the break-down of NEO compensation among base pay, annual performance-based bonus, and
+long-term equity awards; rather, the Compensation Committee takes into consideration all forms of compensation. Because we are a rapidly evolving company, we believe that a substantial
+portion of each NEO's compensation should be in the form of annual performance-based bonus and equity awards. In general, compensation of the NEOs is set at levels where we are competitive with our
+market peers of the S&P 600 Footwear Index and two similar companies due to either their multi-brand business model or similar growth patterns (collectively, "Peers"), with the expectation that
+shortfalls in base pay, if any, will be recouped through performance bonuses should our performance entitle the NEO to receive performance bonuses. The Peers and the criteria for their inclusion are
+listed below: 
+Company
+Criteria 
+Brown Shoe Co., Inc . 
+S&P 600 Footwear 
+K-Swiss, Inc . 
+S&P 600 Footwear 
+Quiksilver, Inc . 
+Similar Multi-Brand Business Model 
+Skechers USA, Inc . 
+S&P 600 Footwear 
+Stride Rite CP 
+S&P 600 Footwear 
+Timberland Co . 
+S&P 600 Footwear 
+Under Armour, Inc . 
+Similar Growth Pattern 
+Wolverine World Wide, Inc . 
+S&P 600 Footwear 
+Base Pay. The Compensation Committee established base pay in 2008 by considering the size of our operations, the responsibilities of
+the NEOs and the
+competitive marketplace for executive talent in similar positions, in particular that of our Peers. The Compensation Committee sets the base pay of the Chief Executive Officer. Base pay for other NEOs
+is set by the Compensation Committee after reviewing the recommendation of the Chief Executive Officer. Annual adjustments are influenced by growth of our operations, revenues and profitability,
+individual performance, changes in responsibility and other factors. 
+Performance-Based Bonuses. In an effort to encourage achievement of our performance objectives, the amount of potential bonus to be paid
+to the NEOs
+for the year upon achievement of these performance objectives is set at a level which the Compensation Committee believes is in excess of the bonuses paid by our Peers. The combination of base pay and
+performance-based bonuses is intended to result in an aggregate rate of salary and bonus compensation exceeding competitive market standards when we exceed the performance objectives set by the
+Compensation Committee. The Compensation Committee believes that a compensation plan exceeding competitive market standards offers NEOs additional incentive to outperform our Peers and ensures that we
+attract and retain talented NEOs. 
+For
+2008, the bonus amount for each NEO was expressed as a percentage of the NEO's base pay ranging from 50% to 300% contingent on us achieving diluted earnings per share growth in 2008 
+14 
+between
+15% to 35% over our fully diluted earnings per share for the year ended December 31, 2007. None of these performance measures were achieved in 2008. The percentages were determined by
+the Compensation Committee based on the estimated contribution and responsibility of the individual NEO. The Compensation Committee also takes into consideration the inherent employment risk accepted
+by an officer of a rapidly evolving company with a limited operating history. 
+No
+bonuses were earned in 2008 and no bonus-related payments have been made to NEO's in 2009. Information on target and maximum bonus amounts are included in the Grants of Plan Based
+Awards Table below. The Compensation Committee has discretion to depart from the formula in approving the bonuses and decrease bonuses after general results are known. 
+Our
+annual performance-based bonuses are paid pursuant to our 2008 Cash Incentive Plan. This plan qualifies as a performance-based compensation plan in accordance with
+Section 162(m) of the Internal Revenue Code (hereafter referred to as "the Code"). See "Deductibility of Executive Compensation" below for further discussion. 
+No
+bonus metrics have yet been set for the 2009 fiscal year. 
+Senior Executive Deferred Compensation Plan. Certain senior executives, including NEOs, are eligible to participate in the 2008 Senior
+Executive
+Deferred Compensation Plan (the "Senior Executive Plan"). Under the Senior Executive Plan, a participant may defer all or a part of his or her bonus amount exceeding 200% of such participant's target
+bonus in accordance with the applicable deferral agreement executed by the participant. The deferred compensation is credited to a deferral account established for each participant under the Senior
+Executive Plan for recordkeeping purposes. Under the Senior Executive Plan, we established an irrevocable trust into which we are required to deposit cash or other assets as specified in the
+applicable deferral agreement, equal to the aggregate amount required to be credited to the participant's deferral account, less any applicable taxes required to be withheld. In 2008,
+Messrs. Snyder and McCarvel elected to participate in the Senior Executive Plan and deferred $1.6 million and $640,000, respectively, of their 2007 performance-based bonuses. The
+deferred bonus for Mr. McCarvel will vest ratably on a quarterly basis over a three year period, with a pro rata amount vesting on each calendar quarter, providing a long-term
+retention incentive. The deferred bonus for Mr. McCarvel will be 100% vested upon a change of control (as defined in the Senior Executive Plan) if he is employed at that time or if his
+employment is terminated as a result of death or disability. Because Mr. Snyder resigned from his position as President and Chief Executive Officer effective March 2009, he will be paid out the
+vested portion of his deferred compensation six months after the termination date of his employment. As of the termination date, the vested portion of his deferred compensation was $666,666. 
+Long-Term Equity Awards. Discretionary long-term equity awards, in the form of stock options and restricted stock, are
+granted at the Compensation Committee's discretion to the NEOs annually in order to provide long-term performance-based compensation, to encourage the NEOs to continue their employment
+throughout the vesting periods of the awards, and to align management and stockholder interests. The Compensation Committee considers grant size and the appropriate combination of equity-based awards
+in making NEO grant decisions. For 2008 and 2009, the amount of long-term equity awards granted to NEOs was based on the Compensation Committee's assessment of each NEO's expected future
+contributions and the equity award levels of our Peers. In 2008, the 
+15 
+Compensation
+Committee approved stock option grants and restricted stock for the NEOs as listed below: 
+Name
+2008 Stock Option Awards: 
+Number of Securities 
+Underlying Options 
+(#) 
+2008 Restricted Stock Awards: 
+(#) 
+Ronald R. Snyder 
+200,000 
+— 
+John P. McCarvel 
+193,000 
+120,000 
+Peter S. Case 
+30,000 
+22,000 
+Russell C. Hammer 
+335,000 
+117,000 
+Erik Rebich 
+100,000 
+50,000 
+We
+compared our long-term equity award program for 2008 against the equity-based compensation programs of our Peers to assist in determining both the structure and amount of
+awards to be made in 2008. The Compensation Committee believes that the awards made to NEOs in 2008 were made at levels consistent with those of our Peers and the anticipated contribution and
+responsibility of the NEO in future years. The Compensation Committee has not yet made any equity awards to NEOs in 2009, except for a January 2009 grant of 317,000 stock options and 197,000 shares of
+restricted stock to Mr. Snyder and the grants noted below to Mr. Duerden, our new Chief Executive Officer. The grants to Mr. Snyder were intended to provide incentive for
+Mr. Snyder to remain with us as we searched for a new Chief Executive Officer and to assist with the transition. The 197,000 shares of restricted stock and the 317,000 stock options granted to
+Mr. Snyder vest in twelve equal installments, the first eleven occurring in the first eleven successive months after the date of grant, and the twelfth installment occurring 36 months
+after the date of grant. The first six installments are guaranteed to vest and the latter installments will vest provided that Mr. Snyder remains a director or employed by us as of each vesting
+date. In the event that Mr. Snyder ceases to serve as a director or officer of ours, any unvested restricted stock or stock options that are subject to vest during the first six months after
+the
+date of grant will automatically vest and become issuable or exercisable, as applicable, on the date of such separation. 
+Options
+are generally granted with an exercise price equal to the closing price per share on the date of grant and vest pro rata over four-years, with the first year vesting
+on a "cliff" basis followed by monthly vesting for the remaining three years. Stock options only have economic value to the grantee to the extent the market price of the underlying shares on the
+exercise date exceeds the exercise price. Accordingly, options provide compensation only if the underlying share price increases over the option term and the NEO's employment continues until the
+vesting date. The Compensation Committee believes that the granting of stock options with an exercise price equal to the market value on the date of grant represents a preferred method of equity
+incentive compensation when compared to stock awards because the value of the option award to the NEO is based solely on future increases in the market value of our stock. 
+Other Benefits. Other benefits are provided to the NEOs in order to achieve a competitive pay package as detailed in the Summary
+Compensation Table
+below. The Compensation Committee believes that those benefits, which are detailed in the Summary Compensation Table under the heading "All Other Compensation," are reasonable, competitive and
+consistent with our overall executive compensation program. Those benefits consist principally of employer-paid premiums on health insurance and country club dues. In addition, from time
+to time, our directors and executive officers may use our company-owned aircraft for personal purposes, provided they fully reimburse us for related expenses, including fuel and other variable costs. 
+New Chief Executive Officer. On February 24, 2009, John Duerden was appointed as our President and Chief Executive Officer,
+effective
+March 18, 2009. Concurrent with the appointment, we 
+16 
+entered
+into an employment agreement with Mr. Duerden which provided for an annual base salary of $850,000. Mr. Duerden's employment agreement also provided that he would be eligible for
+awards under our 2008 Cash Incentive Plan and established a target bonus rate of 100% of his annual base salary with a possible payout of up to 200% of his annual base salary. (See Employment Agreements 
+later in this document for a more robust description of Mr. Duerden's employment agreement.) In addition,
+Mr. Duerden was paid a $350,000 signing bonus and was granted 400,000 shares of restricted common stock and options to purchase 400,000 shares of common stock at an exercise price of $1.37 per
+share. The terms of Mr. Duerden's employment agreement are more fully described in Employment Agreements later in this document.
+Mr. Duerden's salary and incentive package was set based upon the Compensation Committee's assessment of his expected future contributions and compensation packages offered to those in similar
+positions by our Peers. 
+John McCarvel Employment Agreement. In February 2009, we entered into an employment agreement with John McCarvel, our current Chief
+Operating Officer
+and Executive Vice President. This agreement is intended to provide incentive for Mr. McCarvel to remain with the Company and assist with the transition of the new Chief Executive Officer. (See Employment
+Agreements later in this document for a more robust description of Mr. McCarvel's employment agreement.) 
+Tender Offer. Due to the recent decline in the market price of our common stock, the exercise prices of a substantial number of
+outstanding stock
+options held by our employees far exceed the market price of our common stock (referred to as "underwater options"). This decline in our common stock price substantially eliminates the incentive and
+retention value of the options granted to our employees. Accordingly, after a comprehensive review of our compensation program, we have offered to purchase stock options with exercise prices equal to
+or greater than $10.50 per share for cash from certain eligible employees (the "Tender Offer") in order to restore the incentive value of our long-term performance award programs.
+Individuals eligible to participate in the Tender Offer are those employees, including officers and non-employee directors, who continue to be employees or directors from the
+April 2, 2009 offer date to the offer's expiration date on April 30, 2009, unless extended. Participation in the Tender Offer is voluntary. Any tendered unvested eligible options will
+reduce future compensation expense associated with such eligible options and reduce potential stockholder dilution associated with eligible options with values that have been reduced or eliminated
+because of the decline in our stock price. Additionally, any eligible options tendered that were granted under our 2007 Equity Incentive Plan will increase the pool of shares available for future
+grants under the 2007 Plan. Eligibility for future grants of options and equity awards will remain subject to our discretion. If all eligible options are tendered to us for purchase, the aggregate
+cash payment will be approximately $315,000. 
+Deductibility of Executive Compensation 
+Section 162(m) of the Code imposes a $1 million annual limit on the amount that a public company may deduct for
+compensation paid to the company's chief executive officer during a tax year or to any of the company's four other most highly compensated executive officers who are still employed at the end of the
+tax year. The limit does not apply to compensation that meets the requirements of the Code for "qualified performance-based" compensation (i.e., compensation paid only if the executive meets
+pre-established, objective goals based on performance criteria approved by the company's stockholders). 
+The
+Compensation Committee reviews and considers the deductibility of executive compensation under Section 162(m) of the Code. In certain situations, the Compensation Committee
+may approve compensation that does not meet the requirements of the Code in order to ensure competitive levels of total compensation for our executive officers. Stock option grants in 2008 were
+intended to constitute "qualified performance-based compensation" under Section 162(m). The annual performance bonuses, 
+17 
+if
+any, payable in 2009 under our 2008 Incentive Plan also met the requirements for consideration as "qualified performance-based compensation" under Section 162(m). 
+COMPENSATION COMMITTEE REPORT 
+The Compensation Committee has reviewed the foregoing Compensation Discussion and Analysis required by Item 402(b) of
+Regulation S-K and discussed the Compensation Discussion and Analysis with the Company's management. Based on such review and discussions with management, the Compensation Committee
+recommended to the Board that the foregoing Compensation Discussion and Analysis be included in this proxy statement. 
+THE
+COMPENSATION COMMITTEE 
+Ray Croghan (Chairman) 
+Richard Sharp 
+W. Stephen Cannon 
+18 
+Summary Compensation Table 
+The following summary compensation table indicates the cash and non-cash compensation paid to each of our NEOs during our
+fiscal years ended December 31, 2008, 2007 and 2006. The compensation described in this table does not include benefits that are generally available to all of our salaried employees. All
+information regarding stock and option awards has been restated, as appropriate, to reflect the 2-for-1 stock split that occurred on June 14, 2007, which was effected as
+a 100% common stock dividend distributed on that date. 
+Name and Principal Position
+Year 
+Salary 
+($) 
+Bonus 
+($) 
+Stock 
+Awards 
+($)(1) 
+Option 
+Awards 
+($)(1) 
+Non-Equity 
+Incentive Plan 
+Compensation 
+($)(2) 
+All Other 
+Compensation 
+($)(3) 
+Total 
+($) 
+Ronald R. Snyder 
+2008 
+$ 
+1,000,000 
+$ 
+— 
+$ 
+329,405 
+$ 
+3,077,522 
+$ 
+— 
+$ 
+18,874 
+$ 
+4,425,801 
+Former Chief Executive Officer 
+2007 
+800,000 
+— 
+402,584 
+2,548,659 
+3,200,000 
+19,325 
+6,970,568 
+and President 
+2006 
+500,000 
+500,000 
+344,937 
+1,603,296 
+1,000,000 
+10,711 
+3,958,944 
+John P. McCarvel 
+2008 
+500,000 
+— 
+4,074 
+1,191,953 
+— 
+14,230 
+1,710,257 
+Chief Operating Officer and 
+2007 
+400,000 
+— 
+— 
+768,666 
+1,280,000 
+15,398 
+2,464,064 
+Executive Vice President 
+2006 
+275,000 
+220,000 
+460,333 
+132,655 
+440,000 
+— 
+1,527,988 
+Peter S. Case 
+2008 
+300,000 
+— 
+747 
+598,964 
+— 
+14,465 
+914,176 
+Senior Vice President of the Retail 
+2007 
+300,000 
+225,000 
+— 
+483,392 
+225,000 
+19,381 
+1,252,773 
+Division, Former Chief Financial 
+2006 
+249,000 
+82,500 
+— 
+258,034 
+230,000 
+10,116 
+829,650 
+Officer 
+Russell C. Hammer(4) 
+2008 
+413,221 
+— 
+81,525 
+418,915 
+— 
+66,386 
+980,047 
+Chief Financial Officer, Senior 
+Vice President-Finance 
+and Treasurer 
+Erik Rebich(5) 
+2008 
+250,000 
+— 
+1,697 
+292,191 
+— 
+10,096 
+553,984 
+Vice President, General Counsel 
+and Secretary 
+(1) Amounts
+reflect the dollar amount recognized for financial statement reporting purposes for the years ended December 31, 2008, 2007 and 2006 in
+accordance with SFAS 123R and include amounts from awards granted in and prior to such years. Assumptions used in the calculations of these amounts are included in Footnote 10 to our
+Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2008. Option awards with exercise prices equal to or greater than
+$10.50 per share are subject to the Tender Offer as described in Compensation Discussion & Analysis. Participation in the Tender Offer is
+voluntary.
+(2) Amounts
+for Mr. Snyder and Mr. McCarvel in 2007 include deferred compensation under the Senior Executive Plan of $1.6 million and
+$640,000, respectively, and will vest over a three year period. Because Mr. Snyder resigned from his position as President and Chief Executive Officer effective March 2009, he will be paid out
+the vested portion of his deferred compensation six months after the termination date of his employment. As of the termination date, the vested portion of his deferred compensation was $666,666.
+(3) All
+other compensation represents incremental healthcare premiums paid by us on behalf of the NEO and golf club membership fees. We cover 100% of the
+healthcare premiums for certain executives, a benefit that is not offered to other employees. The golf memberships relating to NEOs were cancelled in 2009. For Mr. Hammer, the amount stated
+above also reflects $52,156 in company-paid costs for a vehicle that has been provided to him for his personal use. In addition, we own, operate and maintain our own aircraft. From time to
+time, our directors and executive officers have used the aircraft for personal purposes. These directors and executive officers have fully reimbursed us for expenses related to their personal use of
+this aircraft during the year ended December 31, 2008, determined based on the cost of fuel and other variable costs associated with the flights under FAR 91-501(d). Accordingly, no
+amounts related to personal aircraft usage has been reflected in the table above.
+(4) Mr. Hammer
+was appointed as our Chief Financial Officer in January 2008. Accordingly, no compensation information is presented for 2006 and 2007.
+(5) Mr. Rebich
+became an executive officer on May 5, 2008. 
+19 
+Grants of Plan-Based Awards Table 
+The table below summarizes the plan-based awards granted during the year ended December 31, 2008 to each of the NEOs
+listed in the Summary Compensation Table. All information regarding stock and option awards account for the 2-for-1 stock split that occurred on June 14, 2007, which was
+effected as a 100% common stock dividend on that date. 
+Estimated Future Payouts 
+Under Non-Equity Incentive 
+Plan Awards(1) 
+All Other 
+Stock Awards: 
+Number of 
+Shares of 
+All Other 
+Option 
+Awards: 
+Number of 
+Securities 
+Underlying 
+Exercise or 
+Base Price 
+of Option 
+Grant Date 
+Fair Value 
+of Stock and 
+Name
+Grant 
+Date 
+Target 
+($) 
+Maximum 
+($) 
+Stock 
+or Units (#) 
+Options 
+(#) 
+Awards 
+($/Sh) 
+Option 
+Awards(2) 
+Ronald R. Snyder 
+3/31/08 
+$ 
+1,000,000 
+$ 
+3,000,000 
+1/4/08 
+200,000 
+$ 
+32.75 
+$ 
+2,950,800 
+John P. McCarvel 
+3/31/08 
+$ 
+400,000 
+$ 
+1,200,000 
+1/4/08 
+150,000 
+$ 
+32.75 
+$ 
+2,213,100 
+11/17/08 
+143,000 
+$ 
+1.14 
+$ 
+71,572 
+11/17/08 
+120,000 
+$ 
+136,800 
+Peter C. Case 
+3/31/08 
+$ 
+—(3 
+) 
+$ 
+—(3 
+) 
+1/4/08 
+30,000 
+$ 
+32.75 
+$ 
+442,620 
+11/17/08 
+35,000 
+$ 
+1.14 
+$ 
+17,518 
+11/17/08 
+22,000 
+$ 
+25,080 
+Russell C. Hammer 
+3/31/08 
+$ 
+270,000 
+$ 
+810,000 
+1/8/08 
+150,000 
+$ 
+30.05 
+$ 
+2,029,455 
+6/2/08 
+100,000 
+$ 
+10.03 
+$ 
+453,190 
+11/17/08 
+85,000 
+$ 
+1.14 
+$ 
+42,543 
+5/28/08 
+50,000 
+$ 
+538,500 
+11/17/08 
+67,000 
+$ 
+76,380 
+Erik Rebich 
+3/31/08 
+$ 
+125,000 
+$ 
+375,000 
+1/4/08 
+30,000 
+$ 
+32.75 
+$ 
+442,620 
+11/17/08 
+70,000 
+$ 
+1.14 
+$ 
+35,035 
+11/17/08 
+50,000 
+$ 
+57,000 
+(1) Awards
+represent possible payments under our 2008 Cash Incentive Plan. Payments are based on specified target levels of diluted earnings per share, as
+described in the Compensation Discussion and Analysis. The target payments were based on achieving the target level of performance with ranges from 50% to 100% of the NEO's base salary. The maximum
+payout amounts were based on the plan maximum, which ranges from 150% to 300% of the NEO's base salary. No bonuses were earned by the NEOs in 2008 because the specified target levels of diluted
+earnings per share were not met.
+(2) Grant
+date fair value for stock and option awards was determined pursuant to SFAS 123R. Assumptions used in the calculations of these amounts are set
+forth in Footnote 10 to our Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2008. Option awards with an exercise
+price equal to or greater than $10.50 are subject to the Tender Offer as described in Compensation Discussion & Analysis. Participation in the
+Tender Offer is voluntary.
+(3) Because
+Mr. Case ceased to be an NEO on January 16, 2008, he was not eligible to participate in the 2008 Cash Incentive Plan. 
+20 
+Narrative to Summary Compensation Table and Grants of Plan-Based Awards Table 
+Employment Arrangements 
+We have entered into employment agreements with Mr. Duerden, Mr. Hammer and Mr. McCarvel as set forth below. 
+John Duerden. On February 24, 2009, John Duerden was appointed as our President and Chief Executive Officer effective
+March 16, 2009.
+Upon his initial appointment in February, we entered into an employment agreement with Mr. Duerden. The employment agreement provides that Mr. Duerden will receive an annual base salary
+of $850,000, subject to annual adjustments. Mr. Duerden's bonus target will be 100% of his base salary, with a possible payout of up to 200% of his annual base salary pursuant to our 2008 Cash
+Incentive Plan. The employment agreement also provides for a $350,000 signing bonus within five business days of commencing his employment with us as well as relocation benefits and reimbursement of
+up to 12 months of housing expenses while he looks for a permanent residence in the Boulder, Colorado metro area. 
+In
+connection with the execution of Mr. Duerden's employment agreement, Mr. Duerden was granted 400,000 shares of restricted common stock and options to purchase 400,000
+shares of our common stock. Twenty-five percent of the restricted stock and options will vest on the first anniversary of the grant date and the remaining options will vest in 36 equal
+monthly installments upon Mr. Duerden's completion of each additional month of continuous employment with us after the first anniversary of the grant date. 
+Mr. Duerden's
+employment agreement also provides that if he is terminated by us involuntarily without cause (as defined in the employment agreement), he will receive: (a) a
+lump sum equal to one year's base salary in effect at the time of termination; (b) the bonus payment that would have been paid to him in accordance with the terms and conditions of the bonus
+plan for the year in which he was terminated, prorated based on the portion of the year he was employed by us; (c) a lump sum annual bonus payment equal to one year's base salary in effect at
+the time of termination; (d) health insurance continuation, such that we will pay the employer portion of premiums for health insurance coverage until the earlier of (i) twelve months
+after the termination, or (ii) the effective date of any subsequent similar coverage that Mr. Duerden obtains by becoming employed by another company; and (e) immediate vesting of
+stock options and restricted stock that would have vested had he remained employed by us for the 12 month period following the termination date. 
+In
+addition, the employment agreement provides that if Mr. Duerden resigns from his employment with us for good reason (as defined in the employment agreement), he will receive
+the severance payments and benefits described above relating to involuntary termination without cause. If Mr. Duerden resigns for good reason within six months of a change in control, the
+unvested stock options and restricted stock then held by Mr. Duerden that would have vested had he remained employed for 24 months after the resignation date, rather that
+12 months, will immediately vest. 
+During
+his employment with us and for eight months after the termination of his employment with us, Mr. Duerden will be restricted from participating in certain competitive
+businesses. During his employment with us and for a period of twelve months after the termination of his employment with us, Mr. Duerden will be restricted from soliciting our employees and
+customers. 
+Russell C. Hammer. In January 2008, we entered into an employment agreement with Mr. Hammer, our current Chief Financial Officer,
+Senior Vice
+President—Finance, and Treasurer. The employment agreement provides that Mr. Hammer will receive a monthly salary of $31,250, subject to annual adjustments. He will also be eligible
+to receive bonuses pursuant to our 2008 Cash Incentive Plan based on performance criteria established by the Compensation Committee. Mr. Hammer's bonus target will be sixty percent of his base
+salary. As of December 31, 2008, Mr. Hammer's base salary was $37,500 per month. 
+21 
+Pursuant
+to his employment agreement, Mr. Hammer will receive reimbursement for relocation and housing expenses when and if he relocates to the Niwot, Colorado area and is
+entitled to participate in all employee benefit plans and programs generally available to our executives, including our Senior Executive Plan. The employment agreement also provides that
+Mr. Hammer will receive a lump sum equal to six months base salary if he is terminated by us involuntarily without cause. During his
+employment with the Company and for a period of six months after the termination of his employment, Mr. Hammer will be restricted from participating in certain competitive businesses. 
+Pursuant
+to our 2007 Equity Incentive Plan and the terms of the employment agreement, we also awarded Mr. Hammer options to purchase 150,000 shares of our common stock at an
+exercise price of $30.05, the closing price of our common stock on the grant date. Twenty-five percent of the options will vest on the first anniversary of the grant date and the remaining
+options will vest in 36 equal monthly installments upon his completion of each additional month of continuous employment with us after the first anniversary of the grant date. 
+During
+Mr. Hammer's employment with us and for a period of six consecutive months from and after the termination of his employment, he will be restricted from participating in any
+competitive businesses. In addition, during his employment with us and for a period of twelve months after the termination of his employment with us, Mr. Hammer will be restricted from
+soliciting our employees and customers. 
+John P. McCarvel. In February 2009, we entered into an employment agreement with Mr. McCarvel, our current Chief Operating Officer
+and
+Executive Vice President, the term of which is two years. The employment agreement provides that Mr. McCarvel will receive an annual base salary of $600,000, subject to annual adjustments. He
+will also be eligible to receive bonuses pursuant to our 2008 Cash Incentive Plan based on performance criteria established by the Compensation Committee. Mr. McCarvel's bonus target will be
+eighty percent of his base salary. Mr. McCarvel will also be eligible to receive equity awards under our 2007 Equity Incentive Plan. He is also entitled to participate in all employee benefits
+plans and programs generally available to our executives, including our Senior Executive Plan. 
+Mr. McCarvel's
+employment agreement also provides that if Mr. McCarvel is terminated by us involuntarily without cause during the two year term of the employment agreement,
+he will receive: (a) all base salary that would have been paid to him had he remained employed by us for the remainder of the two year term, (b) the bonus payment that would have been
+paid to him in accordance with the terms and conditions of the bonus plan for the year in which he was terminated, (c) if the bonus plan payment criteria for Mr. McCarvel were not
+established for a fiscal year at the time of Mr. McCarvel's termination, the target bonus plan payment set forth in the employment agreement, and (d) immediate vesting of all unvested
+stock options held by Mr. McCarvel, which will remain exercisable for one year following the termination. 
+During
+the term of Mr. McCarvel's employment agreement, he will be restricted from participating in certain competitive businesses. During his employment and for a period of
+twelve months after the termination of his employment with us, Mr. McCarvel will be restricted from soliciting our customers. 
+Awards 
+On January 4, 2008, the Compensation Committee granted stock option awards to several of our NEOs. On November 17, 2008,
+the Compensation Committee granted stock option awards and stock awards to Messrs. Case, McCarvel, Hammer and Rebich. The option awards vest one-fourth after the first anniversary
+of the grant date with the remainder vesting in 36 equal and successive monthly installments after the applicable initial vesting date. The stock awards vest thirty-three percent on each of the first,
+second and third anniversary dates of the grant date. 
+22 
+The
+Compensation Committee also granted stock option awards to Mr. Hammer on January 8, 2008 in connection with his appointment as Chief Financial Officer. He also received
+stock option awards on June 2, 2008 and stock awards on May 28, 2008 as a method of retaining Mr. Hammer's services. No other restricted stock or stock options were awarded to
+NEOs in the year ended December 31, 2008. 
+Salary and Bonus in Proportion to Total Compensation 
+In 2008, our NEOs received less than fifty percent of their total compensation reported in the Summary Compensation Table in the form
+of base salary and cash incentive awards. As noted in "Compensation Discussion and Analysis" above, we believe that a substantial portion of each NEO's compensation should be in the form of equity
+awards. Our Compensation Committee believes that our current program substantially aligns the compensation of our NEOs with the compensation of executive officers of our Peers, while also permitting
+our Compensation Committee to provide incentives to the NEOs to pursue performance that increases stockholder value. Please see "Compensation Discussion and Analysis" for a description of the
+objectives of our compensation program and overall compensation philosophy. 
+The
+table below summarizes the unexercised options and unvested stock awards as of December 31, 2008 for each of the NEOs listed in the Summary Compensation Table. The information
+below accounts for the 2-for-1 stock split that occurred on June 14, 2007, which was effected as a 100% common stock dividend on that date. 
+23 
+Outstanding Equity Awards at Fiscal Year End Table 
+Option Awards 
+Stock Awards 
+Name
+Number of 
+Securities 
+Underlying 
+Unexercised 
+Options 
+(#) 
+Exercisable(1) 
+Number of 
+Securities 
+Underlying 
+Unexercised 
+Options 
+(#) 
+Unexercisable 
+Option 
+Exercise 
+Price 
+($) 
+Option 
+Expiration 
+Date 
+Number of 
+Shares or 
+Units of 
+Stock That 
+Have Not 
+Vested 
+(#) 
+Market Value 
+of Shares or 
+Units of 
+Stock That 
+Have Not 
+Vested 
+($) 
+Ronald R. Snyder 
+— 
+200,000(2 
+) 
+$ 
+32.75 
+1/4/2018 
+— 
+— 
+167,710 
+182,290(3 
+) 
+$ 
+22.92 
+1/9/2017 
+175,612 
+253,087(4 
+) 
+$ 
+10.50 
+2/7/2016 
+116,810 
+— 
+$ 
+0.51 
+8/31/2011 
+John P. McCarvel 
+— 
+143,000(5 
+) 
+$ 
+1.14 
+11/17/2018 
+120,000 
+(10) 
+$ 
+148,800 
+— 
+150,000(6 
+) 
+$ 
+32.75 
+1/4/2018 
+119,794 
+130,206(3 
+) 
+$ 
+22.92 
+1/9/2017 
+87,564 
+32,522(4 
+) 
+$ 
+10.50 
+2/7/2016 
+Peter S. Case 
+— 
+35,000(5 
+) 
+$ 
+1.14 
+11/17/2018 
+22,000 
+(10) 
+$ 
+27,280 
+— 
+30,000(6 
+) 
+$ 
+32.75 
+1/4/2018 
+38,335 
+41,665(8 
+) 
+$ 
+22.92 
+1/9/2017 
+44,999 
+70,000(4 
+) 
+$ 
+10.50 
+2/7/2016 
+Russell C. Hammer 
+— 
+85,000(5 
+) 
+$ 
+1.14 
+11/17/2018 
+50,000 
+(10) 
+$ 
+62,000 
+— 
+100,000(7 
+) 
+$ 
+10.03 
+6/2/2018 
+67,000 
+(10) 
+$ 
+83,080 
+— 
+150,000(8 
+) 
+$ 
+30.05 
+1/8/2018 
+Erik Rebich 
+— 
+70,000(5 
+) 
+$ 
+1.14 
+11/17/2018 
+50,000 
+(10) 
+$ 
+62,000 
+— 
+30,000(6 
+) 
+$ 
+32.75 
+1/4/2018 
+9,167 
+20,831(3 
+) 
+$ 
+22.92 
+1/9/2017 
+8,030 
+9,490(4 
+) 
+$ 
+10.50 
+2/7/2016 
+26,697 
+2,427(9 
+) 
+$ 
+0.85 
+1/1/2015 
+(1) Options
+granted from inception through September 20, 2006 are exercisable immediately on the grant date. In order to preserve the vesting provisions
+of the options, the shares of our common stock underlying options that are exercised early are subject to a repurchase right by us at the lower of exercise price or fair market value of the underlying
+stock at the date of repurchase. Option awards with exercise prices greater than or equal to $10.50 are subject to the Tender Offer as described in Compensation
+Discussion & Analysis. Participation in the Tender Offer is voluntary.
+(2) Twenty-five
+percent of the options vested on January 4, 2009. Thereafter, the options vest in 36 successive equal monthly installments
+upon the optionee's completion of each additional month of continuous employment.
+(3) Twenty-five
+percent of the options vested on January 9, 2008. Thereafter, the options vest in 36 successive equal monthly installments
+upon the optionee's completion of each additional month of continuous employment.
+(4) Twenty-five
+percent of the options vested on February 6, 2007. Thereafter, the options vest in 36 successive equal monthly installments
+upon the optionee's completion of each additional month of continuous employment.
+(5) Twenty-five
+percent of the options will vest on November 17, 2009. Thereafter, the options vest in 36 successive equal monthly
+installments upon the optionee's completion of each additional month of continuous employment. 
+24 
+(6) Twenty-five
+percent of the options vested on January 4, 2009. Thereafter, the options vest in 36 successive equal monthly installments
+upon the optionee's completion of each additional month of continuous employment.
+(7) Twenty-five
+percent of the options will vest on June 2, 2009. Thereafter, the options vest in 36 successive equal monthly installments
+upon the optionee's completion of each additional month of continuous employment.
+(8) Twenty-five
+percent of the options vested on January 8, 2009. Thereafter, the options vest in 36 successive equal monthly installments
+upon the optionee's completion of each additional month of continuous employment.
+(9) Twenty-five
+percent of the options vested on January 1, 2006. Thereafter, the options vest in 36 successive equal monthly installments
+upon the optionee's completion of each additional month of continuous employment.
+(10) Thirty-three
+percent of the stock award will vest on November 17, 2009. Thereafter, the awards vest in two successive equal annual installments of
+thirty-three percent upon the grantee's completion of each additional year of continuous employment. 
+Option Exercises and Stock Vested Table 
+The table below summarizes the options exercised and stock awards vested during the year ended December 31, 2008 for each of the
+NEOs listed in the Summary Compensation Table. 
+Option Awards 
+Stock Awards 
+Name
+Number of 
+Shares 
+Acquired 
+on Exercise 
+(#) 
+Value 
+Realized 
+on Exercise 
+($) 
+Number of 
+Shares 
+Acquired on 
+Vesting 
+(#) 
+Value 
+Realized on 
+Vesting 
+($) 
+Ronald R. Snyder 
+155,350 
+$ 
+3,065,091 
+87,558 
+$ 
+1,489,724 
+John P. McCarvel 
+— 
+— 
+— 
+— 
+Peter S. Case 
+45,000 
+398,929 
+— 
+— 
+Russell C. Hammer 
+— 
+— 
+— 
+— 
+Erik Rebich 
+115,212 
+$ 
+2,934,015 
+— 
+— 
+25 
+Nonqualified Deferred Compensation 
+The table below summarizes the non-equity incentive compensation that was deferred relating to the year ended
+December 31, 2008 for each of the NEOs listed in the Summary Compensation Table. 
+Name
+Executive 
+Contributions in 
+Last Fiscal Year(1) 
+$ 
+Crocs, Inc. 
+Contributions 
+in Last Fiscal 
+Year 
+$ 
+Aggregate 
+Earnings 
+in Last 
+Fiscal 
+Year 
+$ 
+Aggregate 
+Withdrawals/Distributions 
+$ 
+Aggregate 
+Balance at 
+Last Fiscal 
+Year End 
+$ 
+Ronald R. Snyder(2) 
+$ 
+1,600,000 
+$ 
+— 
+$ 
+5,717 
+$ 
+— 
+$ 
+1,605,717 
+John P. McCarvel 
+640,000 
+— 
+3,667 
+— 
+643,667 
+Peter S. Case 
+— 
+— 
+— 
+— 
+— 
+Russell C. Hammer 
+— 
+— 
+— 
+— 
+— 
+Erik Rebich 
+— 
+— 
+— 
+— 
+— 
+(1) Under
+our Senior Executive Plan, participants have the option to defer any bonus amount exceeding 200% of the participant's target bonus. The deferred
+amount will vest ratably on a quarterly basis over a three year period, with a pro rata amount vesting on each calendar quarter. Any unvested balance will vest immediately upon the death or disability
+of the participant or upon a Change in Control, as defined in the plan. The total amounts shown above for Messrs. Snyder and McCarvel are included in the Non Equity Incentive Compensation Plan
+column of the Summary Compensation Table in 2007.
+(2) Because
+Mr. Snyder resigned from his position as President and Chief Executive Officer effective March 2009, he will be paid out the vested portion
+of his deferred compensation six months after the termination date of his employment. As of the termination date, the vested portion of his deferred compensation was $666,666. 
+Potential Payments on Terminations or Change in Control 
+Certain of our NEOs have employment agreements with us that provide for special guaranteed payments upon a change in control or
+involuntarily termination for other than "cause" (as described in each respective NEO's employment agreement, summarized previously). Likewise, all stock option and restricted stock awards made under
+the 2005 Equity Incentive Plan have an acceleration clause that provides that all unvested outstanding equity awards will immediately vest in the event of a change in control (the 2007 equity
+incentive plan does not have any acceleration provisions). A summary of the potential payments that each of our NEOs would have received upon involuntary termination for other 
+26 
+than
+"cause" and upon a termination related to change in control, assuming that each triggering event occurred on December 31, 2008, follows: 
+Involuntary Termination for Other Than Cause 
+Change in 
+Control(1) 
+Stock Options 
+and Awards 
+Unvested and 
+Accelerated(1) 
+Severance 
+Bonus 
+Perquisites 
+Total 
+Stock Options and 
+Awards Unvested 
+and Accelerated(1) 
+Ronald R. Snyder 
+— 
+— 
+— 
+— 
+— 
+— 
+John P. McCarvel 
+$ 
+1,041,667 
+$ 
+1,200,000 
+— 
+$ 
+14,300 
+$ 
+2,241,667 
+— 
+Peter S. Case 
+— 
+— 
+— 
+— 
+— 
+— 
+Russell C. Hammer 
+$ 
+225,000 
+— 
+— 
+— 
+— 
+— 
+Erik Rebich 
+— 
+— 
+— 
+— 
+— 
+$ 
+947 
+(1) All
+stock options and restricted stock granted under the 2005 Equity Incentive Plan vests on a change in control pursuant to individual option or restricted
+stock award agreements. In addition, Mr. McCarvel's employment agreement provides for an acceleration of vesting for all unvested stock options as of the date of termination, inclusive of
+options granted under our 2007 Equity Incentive Plan, for involuntary termination for other than cause. The calculation of the amount shown herein is based on the number of unvested shares at
+December 31, 2008 multiplied by the closing price of our common stock on the Nasdaq Global Select Market on December 31, 2008, less the exercise price for such stock options. Where the
+aggregate exercise price of the option was more than the market value of the underlying stock, those amounts have been excluded from the calculation of the net benefit shown above. 
+27 
+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+Related Party Transactions 
+In 2008, we sponsored Germain Racing Truck #9 in the NASCAR Craftsman Truck Series. Justin Marks is employed by Germain Racing as the
+driver of Truck #9. Justin Marks is the son of Michael Marks who, at the time we entered into the sponsorship agreement, was a director. Mr. Marks resigned as a director on July 29,
+2008. The total amount of our sponsorship of Germain Racing for 2008 was $480,000. We believe that Justin Marks, a related person, had a material interest in the sponsorship by virtue of his
+employment with Germain Racing as the driver of Truck #9. The sponsorship was part of our larger auto racing sponsorship and sports marketing efforts and was negotiated at an arms-length
+basis with terms similar to those of our other auto racing sponsorships. The sponsorship agreement ended in the fourth quarter of 2008 and was not renewed. 
+Policy on Transactions with Related Persons 
+Our Business Code of Conduct and Ethics requires that any transaction involving us in which one of our directors, nominees for
+director, executive officers, or greater than five percent stockholders, or their immediate family members (each, a "related person"), have a material
+interest be approved or ratified by the Audit Committee if the amount involved, when aggregated with the amount of all other transactions between the related person and us, exceeds $100,000 in a
+fiscal year. The full Board reviews ordinary course of business transactions in which directors have an interest as part of the Board's annual director independence review, and our Business Code of
+Conduct and Ethics permits the full Board to waive any conflicts of interest between us and any director or officer. In determining whether to approve or ratify any such transaction, the Audit
+Committee must consider, in addition to other factors it deems appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. 
+All
+transactions disclosed above were reviewed and approved in accordance with this policy. 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify our directors and executive officers, in addition to the indemnification provided for in
+our certificate of incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain expenses (including attorneys' fees),
+judgments, fines and settlement amounts incurred by any such person in any action or proceeding, including any action by or in the right of the Company, arising out of such person's services as a
+director or executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request. We believe that these provisions and agreements
+are necessary to attract and retain qualified persons as directors and executive officers. 
+SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE 
+Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors and executive officers, and persons who
+own more than ten percent of our common stock, to file with the SEC and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes
+in ownership of our common stock. 
+To
+our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all required
+reports of our officers, directors and greater than ten percent stockholders under Section 16(a) were timely filed during the year ended December 31, 2008, except for the following: one
+Form 4 for each of Ronald R. Snyder, Michael C. Margolis, John P. McCarvel, Peter S. Case and Russell C. Hammer reporting a grant of stock options to each officer, and one Form 4
+reporting open market sales by Michael E. Marks, a former director. 
+28 
+REPORT OF THE AUDIT COMMITTEE 
+The Audit Committee has reviewed and discussed the audited financial statements for the fiscal year ended December 31, 2008 with
+the Company's management and Deloitte & Touche LLP, the Company's independent registered public accounting firm. Management is responsible for the preparation, presentation and integrity
+of the financial statements, accounting and financial reporting principles and internal control over financial reporting. Deloitte & Touche LLP is responsible for performing an
+independent audit of the financial statements in accordance with generally accepted auditing standards and for expressing opinions on the conformity of the financial statements with accounting
+principles generally accepted in the United States. 
+The
+Audit Committee has discussed with Deloitte & Touche LLP the matters required to be discussed by Statement on Auditing Standards No. 61, Communication with Audit Committees, as
+amended, and has received the written disclosures and the letter from Deloitte & Touche LLP
+required by applicable requirements of the Public Company Accounting Oversight Board regarding the independent auditor's communications with the Audit Committee concerning independence. The Audit
+Committee has also discussed with Deloitte & Touche LLP their independence. 
+Based
+on its reviews and discussions referred to above, the Audit Committee has recommended to the Board of Directors that the audited financial statements be included in the Company's
+Annual Report on Form 10-K for the year ended December 31, 2008, for filing with the SEC. 
+The
+Audit Committee: 
+Thomas
+J. Smach (Chairman) 
+Peter A. Jacobi 
+Ronald L. Frasch 
+PROPOSAL 2—RATIFICATION OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+The Audit Committee has appointed Deloitte & Touche LLP, as the independent registered public accounting firm for the
+fiscal year ending December 31, 2009. Deloitte & Touche LLP has served as our independent public accounting firm since 2005. We are not required to submit this appointment to the
+stockholders for approval but the Board believes it is desirable as a matter of policy. 
+If
+the stockholders do not ratify this appointment, the Audit Committee will investigate the reasons for the rejection and consider other independent registered public accounting firms.
+Even if the appointment is ratified, the Audit Committee may, in its discretion, appoint a different independent registered public accounting firm. 
+PRINCIPAL ACCOUNTING FIRM FEES AND SERVICES 
+The following table sets forth the aggregate fees we paid to Deloitte & Touche LLP, our independent registered public
+accounting firm, and other member firms of Deloitte Touche Tohmatsu and their respective affiliates, which we refer to collectively as Deloitte entities, for professional services provided during 2007
+and 2008 and billed through the date of this filing. The Audit Committee is required to pre-approve all non-audit services provided by Deloitte & Touche LLP. All
+fees paid to the Deloitte entities were pre-approved by the Audit Committee, which concluded that the provision of such services by the Deloitte entities was compatible with the
+maintenance of that firm's independence in the conduct of its auditing functions. We expect that a representative of Deloitte & Touche LLP will 
+29 
+attend
+the Annual Meeting and will have the opportunity to make any statements if he or she so desires and to respond to appropriate stockholder questions. 
+2008 
+2007 
+Audit fees(1) 
+$ 
+2,276,922 
+$ 
+2,772,645 
+Audit-related fees 
+— 
+— 
+Tax fees(2) 
+467,926 
+57,194 
+All other fees 
+— 
+— 
+Total fees 
+$ 
+2,744,848 
+$ 
+2,829,839 
+(1) Audit
+fees relate to professional services rendered in connection with the audit of our annual financial statements and internal controls over financial
+reporting, both of which are included in our Annual Report on Form 10-K and services attendant to, or required by, statute or regulation, such as: (i) comfort letters,
+consents and other audit services related to SEC and other regulatory filings; and (ii) accounting consultation related to the audit. Audit fees consisted of audit work performed and billed
+through the date of this filing.
+(2) Tax
+fees include professional services rendered in connection with tax compliance, tax advice, tax consulting and tax planning. 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" THE RATIFICATION OF DELOITTE & 
+TOUCHE LLP AS THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR 
+FISCAL YEAR 2009. 
+STOCKHOLDER PROPOSALS AND NOMINATIONS FOR 2010 ANNUAL MEETING 
+Any proposal of a stockholder intended to be included in our proxy statement for the 2010 Annual Meeting of Stockholders pursuant to
+Rule 14a-8 of the SEC's rules, must be received by us no later than January 12, 2010, unless the date of our 2010 annual meeting is more than 30 days before or after
+June 25, 2010, in which case the proposal must be received a reasonable time before we begin to print and mail our proxy materials. All proposals should be addressed to the Corporate Secretary,
+Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503. 
+In
+order for a stockholder to nominate a candidate for director for election or to bring other business before the 2010 annual meeting, we must receive timely notice of the nomination or
+business in writing by the close of business not later than 90 days nor earlier than 120 days prior to the anniversary date of the immediately preceding annual meeting of stockholders.
+However, in the event that the annual meeting is called for a date that is not within 30 days before or 60 days after such anniversary date, notice by the stockholder to be timely must
+be received not earlier than the close of business on the 120th day prior to such annual meeting and not later than the close of business on the later of the 90th day prior to such
+annual meeting or the tenth day following the date on which notice of the date of the annual meeting was made public. 
+OTHER MATTERS 
+We do not intend to bring before the Annual Meeting any matters other than the proposals specifically described above, and we know of
+no matters other than those to come before the Annual Meeting. If any other matters properly come before the Annual Meeting, it is the intention of the persons named in the accompanying proxy to vote
+such proxy in accordance with the recommendation of the our management on such matters, including any matters dealing with the conduct of the Annual Meeting. 
+30 
+VOTE BY INTERNET— www.proxyvote.com 
+Use the Internet to transmit your voting instructions and for electronic delivery of information up until 11:59 P.M. Eastern Time the day before the cut-off date or meeting date. Have your proxy card in hand when you access the web site and
+follow the instructions to obtain your records and to create an electronic voting instruction form. 
+6328 MONARCH PARK PLACE 
+NIWOT, CO 80503 
+ELECTRONIC DELIVERY OF FUTURE STOCKHOLDER COMMUNICATIONS 
+If you would like to reduce the costs incurred by Crocs, Inc. in mailing proxy materials, you can consent to receiving all future proxy statements, proxy cards and annual reports electronically via e-mail or the Internet. To sign up for
+electronic delivery, please follow the instructions above to vote using the Internet and, when prompted, indicate that you agree to receive or access stockholder communications electronically in future years. 
+VOTE BY PHONE—1-800-690-6903 
+Use any touch-tone telephone to transmit your voting instructions up until 11:59 P.M. Eastern Time the day before the cut-off date or meeting date. Have your proxy card in hand when you call and then follow the instructions. 
+VOTE BY MAIL 
+Mark, sign and date your proxy card and return it in the postage-paid envelope we have provided or return it to Crocs, Inc., c/o Broadridge, 51 Mercedes Way, Edgewood, NY 11717. 
+TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS: 
+CROCS1 KEEP THIS PORTION FOR YOUR RECORDS 
+DETACH AND RETURN THIS PORTION ONLY 
+THIS PROXY CARD IS VALID ONLY WHEN SIGNED AND DATED. 
+CROCS, INC. 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" PROPOSALS 1 AND 2. 
+Vote on Directors 
+For 
+All 
+o 
+Withhold 
+All 
+o 
+For All 
+Except 
+o 
+To withhold authority to vote for any individual nominee(s), mark "For All Except" and write the number(s) of the nominee(s) on the line below. 
+1. 
+ELECTION OF DIRECTORS 
+Nominees: 
+01) Ronald L. Frasch 
+02) W. Stephen Cannon 
+Vote on Proposal 
+For 
+Against 
+Abstain 
+2. 
+Ratification of the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for fiscal year 2009. 
+o 
+o 
+o 
+3. 
+Such other business as may properly come before the meeting or any postponement or adjournment thereof. 
+The shares represented by this proxy when properly executed will be voted in the manner directed herein by the undersigned Stockholder(s). If no direction is made, this proxy will be voted FOR Proposals 1 and
+2. 
+For address changes and/or comments, please check this box and write them on the back where indicated. 
+o 
+Please indicate if you plan to attend this meeting. 
+o 
+o 
+Yes 
+No 
+(NOTE: Please sign exactly as your name(s) appear(s) hereon. All holders must sign. When signing as attorney, executor, administrator, or other fiduciary, please give full title as such. Joint owners should each sign personally. If a corporation,
+please sign in full corporate name, by authorized officer. If a partnership, please sign in partnership name by authorized person.) 
+Signature [PLEASE SIGN WITHIN o BOX] 
+Date 
+Signature (Joint Owners)
+Date 
+Important Notice Regarding Internet Availability of Proxy Materials for the Annual Meeting: The Notice and Proxy Statement and Annual Report are
+available at www.proxyvote.com. 
+CROCS, INC. 
+THIS PROXY IS SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS 
+ANNUAL MEETING OF STOCKHOLDERS 
+June 25, 2009 
+The undersigned hereby appoints John Duerden and Russell C. Hammer, and each of them, with power of substitution, as proxies of the undersigned, to attend the Annual
+Meeting of Stockholders of Crocs, Inc. (the "Company"), to be held at the St. Julien Hotel, 900 Walnut Street, Boulder, Colorado, on June 25, 2009 at 9:00 a.m., Mountain
+Time, and all adjournments thereof, and to vote, as indicated on the reverse side, the shares of Common Stock of the Company which the undersigned is entitled to vote with all the powers the
+undersigned would possess if present at the meeting. 
+THIS PROXY, WHEN PROPERLY EXECUTED, WILL BE VOTED AS DIRECTED HEREIN BY THE UNDERSIGNED STOCKHOLDER(S). IF NO SPECIFIC DIRECTIONS ARE GIVEN, THIS PROXY WILL BE VOTED FOR
+PROPOSALS 1 AND 2. 
+PLEASE MARK, SIGN, DATE AND RETURN THIS PROXY CARD PROMPTLY USING THE ENCLOSED REPLY ENVELOPE 
+Address Changes/Comments: 
+(If
+you noted any Address Changes/Comments above, please mark corresponding box on the reverse side.) 
+CONTINUED AND TO BE SIGNED ON REVERSE SIDE 
+QuickLinks 
+Crocs, Inc. 
+6328 Monarch Park Place Niwot, Colorado 80503 
+NOTICE OF THE 2008 ANNUAL MEETING OF STOCKHOLDERS TO BE HELD JUNE 25, 2009 
+Crocs, Inc. 
+6328 Monarch Park Place Niwot, Colorado 80503 
+2009 ANNUAL MEETING OF STOCKHOLDERS 
+PROXY STATEMENT 
+GENERAL INFORMATION REGARDING ANNUAL MEETING 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" ALL OF THE ABOVE-NAMED NOMINEES FOR DIRECTOR. 
+EXECUTIVE OFFICERS 
+BENEFICIAL OWNERSHIP OF OUR COMMON STOCK 
+BOARD OF DIRECTORS AND COMMITTEES OF THE BOARD 
+EXECUTIVE COMPENSATION COMPENSATION DISCUSSION AND ANALYSIS 
+COMPENSATION COMMITTEE REPORT 
+Summary Compensation Table 
+Grants of Plan-Based Awards Table 
+Outstanding Equity Awards at Fiscal Year End Table 
+Option Exercises and Stock Vested Table 
+Nonqualified Deferred Compensation 
+Potential Payments on Terminations or Change in Control 
+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE 
+REPORT OF THE AUDIT COMMITTEE 
+PRINCIPAL ACCOUNTING FIRM FEES AND SERVICES 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" THE RATIFICATION OF DELOITTE & TOUCHE LLP AS THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR FISCAL YEAR 2009. 
+STOCKHOLDER PROPOSALS AND NOMINATIONS FOR 2010 ANNUAL MEETING 
+OTHER MATTERS
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001047469-09-004667/proxy_rpt.txt b/raw/proxies/0001334036/0001047469-09-004667/proxy_rpt.txt
new file mode 100644
index 0000000000000000000000000000000000000000..cd56fa164c9bc5848b9db695058dc832bbebc04e
--- /dev/null
+++ b/raw/proxies/0001334036/0001047469-09-004667/proxy_rpt.txt
@@ -0,0 +1,22 @@
+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+Related Party Transactions 
+In 2008, we sponsored Germain Racing Truck #9 in the NASCAR Craftsman Truck Series. Justin Marks is employed by Germain Racing as the
+driver of Truck #9. Justin Marks is the son of Michael Marks who, at the time we entered into the sponsorship agreement, was a director. Mr. Marks resigned as a director on July 29,
+2008. The total amount of our sponsorship of Germain Racing for 2008 was $480,000. We believe that Justin Marks, a related person, had a material interest in the sponsorship by virtue of his
+employment with Germain Racing as the driver of Truck #9. The sponsorship was part of our larger auto racing sponsorship and sports marketing efforts and was negotiated at an arms-length
+basis with terms similar to those of our other auto racing sponsorships. The sponsorship agreement ended in the fourth quarter of 2008 and was not renewed. 
+Policy on Transactions with Related Persons 
+Our Business Code of Conduct and Ethics requires that any transaction involving us in which one of our directors, nominees for
+director, executive officers, or greater than five percent stockholders, or their immediate family members (each, a "related person"), have a material
+interest be approved or ratified by the Audit Committee if the amount involved, when aggregated with the amount of all other transactions between the related person and us, exceeds $100,000 in a
+fiscal year. The full Board reviews ordinary course of business transactions in which directors have an interest as part of the Board's annual director independence review, and our Business Code of
+Conduct and Ethics permits the full Board to waive any conflicts of interest between us and any director or officer. In determining whether to approve or ratify any such transaction, the Audit
+Committee must consider, in addition to other factors it deems appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. 
+All
+transactions disclosed above were reviewed and approved in accordance with this policy. 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify our directors and executive officers, in addition to the indemnification provided for in
+our certificate of incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain expenses (including attorneys' fees),
+judgments, fines and settlement amounts incurred by any such person in any action or proceeding, including any action by or in the right of the Company, arising out of such person's services as a
+director or executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request. We believe that these provisions and agreements
+are necessary to attract and retain qualified persons as directors and executive officers.
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001047469-10-004586/proxy_rpt.txt b/raw/proxies/0001334036/0001047469-10-004586/proxy_rpt.txt
new file mode 100644
index 0000000000000000000000000000000000000000..814cc4de34ac93c09b96e3fbc5dc528986fa6dc3
--- /dev/null
+++ b/raw/proxies/0001334036/0001047469-10-004586/proxy_rpt.txt
@@ -0,0 +1,19 @@
+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+Related Party Transactions 
+None. 
+Policy on Transactions with Related Persons 
+Our Business Code of Conduct and Ethics requires that any transaction involving us in which one of our directors, nominees for
+director, executive officers, or greater than five percent stockholders, or one of the aforementioned's immediate family members (each, a "related person"), have a material interest be approved or
+ratified by the Audit Committee if the amount involved, when aggregated with the amount of all other transactions between the related person and us, exceeds $100,000 in a fiscal year. The full Board
+reviews ordinary course of business transactions in which directors have an interest as part of the Board's annual director independence review, and our Business Code of Conduct and Ethics permits the
+full Board to waive any conflicts of interest between us and any director or officer. In determining whether to approve or ratify any such transaction, the Audit Committee must consider, in addition
+to other factors it deems appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. 
+All
+transactions disclosed above were reviewed and approved in accordance with this policy. 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify certain directors and executive officers in addition to the indemnification provided for
+in our certificate of incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain expenses (including attorneys'
+fees), judgments, fines and settlement amounts incurred by any such person in any action or proceeding, including any action by or in the right of the Company, arising out of such person's services as
+a director or executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request. We believe that these provisions and agreements
+are necessary to attract and retain qualified persons as directors and executive officers. 
+29
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001047469-11-004301/proxy.txt b/raw/proxies/0001334036/0001047469-11-004301/proxy.txt
new file mode 100644
index 0000000000000000000000000000000000000000..8db1abaacda68ba1a68079d37552d373e13e0c83
--- /dev/null
+++ b/raw/proxies/0001334036/0001047469-11-004301/proxy.txt
@@ -0,0 +1,2553 @@
+DEF 14A
+1
+a2203666zdef14a.htm
+DEF 14A
+Use these links to rapidly review the document 
+TABLE OF CONTENTS 
+Table of Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+SCHEDULE 14A 
+Proxy
+Statement Pursuant to Section 14(a) of 
+the Securities Exchange Act of 1934 (Amendment No. ) 
+Filed by the Registrant ý 
+Filed by a Party other than the Registrant o 
+Check the appropriate box: 
+o 
+Preliminary Proxy Statement 
+o 
+Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2)) 
+ý 
+Definitive Proxy Statement 
+o 
+Definitive Additional Materials 
+o 
+Soliciting Material under §240.14a-12 
+CROCS, INC. 
+(Name of Registrant as Specified In Its Charter) 
+(Name of Person(s) Filing Proxy Statement, if other than the Registrant) 
+Payment of Filing Fee (Check the appropriate box): 
+ý 
+No fee required. 
+o 
+Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11. 
+(1) 
+Title of each class of securities to which transaction applies: 
+(2) 
+Aggregate number of securities to which transaction applies: 
+(3) 
+Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined): 
+(4) 
+Proposed maximum aggregate value of transaction: 
+(5) 
+Total fee paid: 
+o 
+Fee paid previously with preliminary materials. 
+o 
+Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration
+statement number, or the Form or Schedule and the date of its filing. 
+(1) 
+Amount Previously Paid: 
+(2) 
+Form, Schedule or Registration Statement No.: 
+(3) 
+Filing Party: 
+(4) 
+Date Filed: 
+Table of Contents 
+Crocs, Inc. 
+6328 Monarch Park Place 
+Niwot, Colorado 80503 
+NOTICE OF THE 2010 ANNUAL MEETING OF STOCKHOLDERS 
+TO BE HELD JUNE 28, 2011 
+To the Stockholders of Crocs, Inc.: 
+We
+will hold the 2011 Annual Meeting of Stockholders of Crocs, Inc. at the St. Julien Hotel, 900 Walnut Street, Boulder, Colorado, on June 28, 2011 at
+2 p.m. Mountain Time. 
+The
+meeting's purpose is to: 
+1. elect
+two Class III directors;
+2. ratify
+the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for fiscal year 2011;
+3. approve
+the Amendment and Restatement of our 2007 Equity Incentive Plan;
+4. hold
+an advisory vote on the compensation of our named executive officers;
+5. hold
+an advisory vote on the frequency of future advisory votes on the compensation of our named executive officers; and
+6. consider
+any other matters that properly come before the meeting or any postponement or adjournment thereof. 
+Only
+stockholders of record of our common stock at the close of business on April 29, 2011 are entitled to receive notice of and to vote at the meeting. Each share of common stock
+is entitled to one vote. 
+A
+list of the stockholders entitled to vote at the meeting will be available for examination at the meeting by any stockholder for any purpose relevant to the meeting. The list will also
+be available on the same basis for ten days prior to the meeting at our principal executive office, 6328 Monarch Park Place, Niwot, Colorado 80503. 
+All
+stockholders are cordially invited to attend the meeting in person. Whether or not you plan to attend the meeting in person, please vote your shares as instructed in the Notice of
+Internet Availability of Proxy Materials, over the Internet, or by telephone after your receipt of hard copies of the proxy materials, as promptly as possible. You may also request a paper proxy card,
+which will include a reply envelope, to submit your vote by mail, as described in the Notice of Internet Availability of Proxy Materials. Stockholders who are present at the Annual Meeting may
+withdraw their proxy and vote in person if they so desire. 
+BY ORDER OF THE BOARD OF DIRECTORS 
+John McCarvel 
+President and Chief Executive Officer 
+Niwot,
+Colorado 
+April 29, 2011 
+Table of Contents 
+TABLE OF CONTENTS 
+Page 
+Proxy Statement 
+1 
+General Information Regarding Annual
+Meeting 
+1 
+Proposal 1—Election of Directors 
+3 
+Corporate Governance 
+6 
+Board of Directors and Committees of the
+Board 
+7 
+Executive Officers 
+9 
+Beneficial Ownership of Our Common Stock 
+10 
+Certain Relationships and Related Person
+Transactions 
+12 
+Director Compensation 
+13 
+Executive Compensation 
+14 
+Compensation Committee Report 
+20 
+Report of the Audit Committee 
+26 
+Independent Registered Public Accounting
+Firm 
+27 
+Proposal 2—Ratification of the Appointment of
+Independent Registered Public Accounting Firm 
+27 
+Proposal 3—Approval of the Amendment and Restatement of
+the 2007 Equity Incentive Plan 
+28 
+Proposal 4—Advisory Vote on the Compensation of our
+Named Executive Officers 
+35 
+Proposal 5—Advisory Vote on the Frequency of Stockholder
+Votes on the Compensation of our Named Executive Officers 
+35 
+Other Matters 
+36 
+Appendix A 
+37 
+Table of Contents 
+Crocs, Inc. 
+6328 Monarch Park Place 
+Niwot, Colorado 80503 
+2011 ANNUAL MEETING OF STOCKHOLDERS 
+PROXY STATEMENT 
+This proxy statement will first be made available to stockholders on or about April 29, 2011. It is furnished to stockholders of
+Crocs, Inc., a Delaware corporation ("we," "us," or "our"), in connection with the solicitation of proxies by our Board of Directors. The proxies being solicited will be voted at the 2011
+Annual Meeting of Stockholders (the "Annual Meeting"), to be held on June 28, 2011 at the St. Julien Hotel, 900 Walnut Street, Boulder, Colorado at 2 p.m. Mountain Time, or at any
+postponement or adjournment thereof, for the purpose of voting on the proposals as set forth herein as well as other business matters which may properly come before the meeting. 
+Under
+the rules of the Securities and Exchange Commission (the "SEC"), we are furnishing proxy materials to our stockholders on the Internet, rather than mailing printed copies. If you
+received a Notice of Internet Availability of Proxy Materials by mail, you will not receive a printed copy of the proxy materials unless you request one as instructed in that notice. Instead, the
+Notice of Internet Availability of Proxy Materials will instruct you as to how you may access and review the proxy materials on the Internet. This proxy statement and our 2010 annual report to
+stockholders are available at www.proxyvote.com. 
+GENERAL INFORMATION REGARDING ANNUAL MEETING 
+Record Date. Stockholders of record at the close of business on April 29, 2011 are entitled to notice of and to vote at the Annual
+Meeting. On
+the record date, there were 88,519,710 shares of our common stock outstanding. Each such share is entitled to one vote on each matter submitted to a vote at the Annual Meeting. 
+Quorum Requirements. A quorum is required to conduct business at the Annual Meeting. The holders of a majority of the outstanding shares
+entitled to
+vote generally in the election of directors must be present in person or by proxy at the Annual Meeting in order for a quorum to exist. Abstentions and broker non-votes count as present
+for purposes of determining a quorum. A broker non-vote occurs when a broker returns a proxy card but does not vote on one or more matters because the broker does not have the authority to
+do so without instructions from the beneficial owner. Shares represented by proxies that are marked withhold with respect to the election of our Class III directors will be counted as present
+in determining whether there is a quorum. 
+Vote Requirements. If a quorum is present at the Annual Meeting, the following vote is required for approval of each matter to be voted
+on. 
+Election of Directors. The two director nominees receiving the highest number of "for" votes cast in person or by proxy at
+the Annual Meeting will be elected as directors. Proxies marked 
+1 
+Table of Contents 
+withhold
+and broker non-votes will have no effect on the outcome of this proposal. Cumulative voting is not permitted. 
+Ratification of Appointment of Deloitte & Touche LLP. The affirmative vote of the holders of a majority of the
+shares of our common stock present in person or by proxy and entitled to vote on the proposal is required for the ratification of the appointment of Deloitte & Touche LLP as our
+independent registered public accounting firm for fiscal year 2011. Abstentions will have the effect of voting against this proposal. Broker non-votes will have no impact on this proposal. 
+Approval of the Amendment and Restatement of the 2007 Equity Incentive Plan. The affirmative vote of the holders of a
+majority of the shares of our common stock present in person or by proxy and entitled to vote on the proposal is required for the approval of the amendment. Abstentions will have the effect of voting
+against this proposal. Broker non-votes will have no effect on the outcome of this proposal. 
+Advisory Vote on Named Executive Officer Compensation. The affirmative vote of the holders of a majority of the shares of our
+common stock present in person or by proxy and entitled to vote on the proposal is required to approve the advisory resolution approving the compensation of our named executive officers. Abstentions
+will have the effect of voting against this proposal. Broker non-votes will have no effect on the outcome of this proposal. 
+Advisory Vote on Frequency of Future Advisory Votes on Named Executive Officer Compensation. At the annual meeting you will
+be asked to vote to approve the frequency—every year, every two years or every three years—of the advisory vote on the compensation of our named executive officers. The voting
+frequency option that receives the highest number of votes cast by the holders of the shares of our common stock present in person or by proxy and entitled to vote on the proposal will be deemed the
+frequency for the advisory vote on executive compensation that has been selected by stockholders. Abstentions and broker non-votes will have no effect on the outcome of this proposal. 
+Approval of all Other Proposals. With respect to any other matters properly brought before the Annual Meeting, the
+affirmative vote of the holders of a majority of the shares of our common stock present in
+person or by proxy and entitled to vote on the proposals will be the act of the stockholders. Abstentions will have the effect of voting against these proposals. Broker non-votes will have
+no effect on these proposals. 
+Board Recommendations. Our Board of Directors' recommendation is set forth together with the description of each proposal. In summary,
+our Board of
+Directors recommends a vote: 
+• FOR election of each of the Class III director nominees (see
+Proposal 1); 
+• FOR the ratification of the appointment of Deloitte &
+Touche LLP as our independent registered public accounting firm for our fiscal year ending December 31, 2011 (see Proposal 2); 
+• FOR the approval of the Amendment and Restatement of our 2007 Equity
+Incentive Plan (see Proposal 3); 
+• FOR the approval of the compensation of our named executive officers as
+disclosed in this proxy statement (see Proposal 4); and 
+• FOR a frequency of every three
+years for future advisory votes on the compensation of our named executive officers (see Proposal 5). 
+Your Proxy. Whether or not you are able to personally attend the Annual Meeting, you are encouraged to vote your shares as instructed
+in the Notice
+of Internet Availability of Proxy Materials. Shares represented by properly executed methods, and not revoked prior to the Annual Meeting, will be voted at the Annual Meeting as directed in the
+proxy. If no directions are specified, such proxies 
+2 
+Table of Contents 
+will be voted FOR each of the proposals described in this proxy statement and for a frequency of "every three years" for Proposal 5 and in the best judgment of the proxy holders as to other matters
+that may properly come before the Annual Meeting. 
+If
+your shares are held in the name of a bank or brokerage firm, your bank or broker will send you a separate package describing the procedures and options for voting your shares. You
+should follow the instructions provided by your bank or brokerage firm. On routine matters, such as the ratification of the appointment of our independent registered public accounting firm, your
+broker will vote your shares for you at his or her discretion if you do not instruct your broker how to vote. For non-routine matters, which include all other matters to be voted upon at
+the Annual Meeting, your broker may not vote your shares without specific voting instructions from you. 
+Revocation. Any stockholder giving a proxy has the power to revoke the proxy, or change the proxy, at any time before the proxy is voted
+at the
+Annual Meeting by (i) re-voting online at www.proxyvote.com, (ii) sending another properly executed proxy bearing a later date or a written notice of revocation of the proxy
+to Corporate Secretary, Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503 or (iii) voting in person at the Annual Meeting. 
+Cost of Proxy Solicitation. Our Board of Directors is soliciting the proxies. We will bear the entire cost of this proxy solicitation.
+We have
+retained the services of Georgeson, Inc., a professional proxy solicitation firm, to aid in the solicitation of proxies. Georgeson, Inc. may solicit proxies by personal interview, mail,
+telephone, facsimile, email or otherwise. We will pay Georgeson, Inc. its customary fee, estimated to be approximately $20,000, plus reasonable out-of-pocket expenses
+incurred in the process of soliciting proxies. We may also reimburse brokers, custodians, nominees and other fiduciaries for normal handling charges incurred for forwarding proxy materials to
+beneficial owners. Solicitation of proxies may be made personally or by mail or telephone by our directors, officers and other employees, who will receive no additional compensation for such services. 
+PROPOSAL 1—ELECTION OF DIRECTORS 
+Our Board of Directors (the "Board") currently consists of seven members divided into three classes, with each director elected to a
+three-year term. Class III consists of Thomas J. Smach and John P. McCarvel, whose terms will expire at the Annual Meeting. Class I consists of Ronald L. Frasch
+and W. Stephen Cannon, whose terms will expire at the annual meeting to be held in 2012. Class II consists of Raymond D. Croghan, Peter A. Jacobi and Richard L. Sharp, whose terms will expire
+at the annual meeting to be held in 2013. Under our amended and restated bylaws, each of our directors holds office until his or her successor has been elected and qualified or until such director's
+earlier resignation or removal. 
+At
+each annual meeting of stockholders, the successors to directors whose terms expire at such meeting will be elected, or such directors will be re-elected, and will serve
+from the time of election and qualification until the third annual meeting following their election or until their successors are duly elected and qualified. The current authorized number of directors
+is eight. The authorized number of directors may be changed by resolution of the Board. Any additional directorships resulting from an increase in the number of directors will be distributed among the
+three classes so that, as nearly as possible, each class will consist of one-third of the directors. Vacancies on the Board can be filled by resolution of the Board. 
+Upon
+the recommendation of the Nominating and Governance Committee, the Board has nominated Messrs. Smach and McCarvel for re-election as Class III directors to
+serve for a three-year term expiring at the 2014 annual meeting of stockholders. 
+A
+stockholder cannot vote for more than two nominees. Each of the director nominees has consented to serve for a three-year term. We do not contemplate that any of the
+nominees will be 
+3 
+Table of Contents 
+unable
+to stand for election, but should any nominee become unable to serve or will not serve for any reason, all proxies (except proxies marked to the contrary) will be voted for the election of a
+substitute nominee as the Board may recommend. 
+Class III Director Nominees 
+Thomas J. Smach ( Class III ), age
+50, has served as a member of the Board since April 2005 and is currently serving as our Acting Chairman. Mr. Smach is currently a co-founding partner of Riverwood Capital
+Management, a private equity firm. From January 2005 to June 2008, Mr. Smach served as the Chief Financial Officer of Flextronics International ("Flextronics") a NASDAQ-listed electronics
+manufacturing services (EMS) provider. From April 2000 to December 2004, Mr. Smach served as Senior Vice President—Finance of Flextronics. From 1997 to April 2000, he served as the
+Senior Vice President, Chief Financial Officer and Treasurer of The Dii Group, Inc., an EMS provider and publicly-traded company that merged with Flextronics in early 2000 ("The Dii Group").
+Mr. Smach is a certified public accountant and also serves on the Board of Directors of ADVA AG Optical Networking, a publicly-traded company in Germany. Mr. Smach has extensive
+accounting and financial management experience having served as the chief financial officer of global public companies. In addition, Mr. Smach has significant experience with international
+manufacturing and business from his leadership positions at Flextronics. This experience is useful as we continue to expand our international operations. Mr. Smach is also well versed in SEC
+compliance and risk oversight, which makes him particularly well suited to serve as the chairman of the Audit Committee and as the Board's Acting Chairman. 
+John P. McCarvel (Class III) , age 54, was appointed as a director effective March 1, 2010. He has
+served as our President and Chief Executive Officer since March 1, 2010. Prior to this appointment, he served as our Chief Operating Officer and Executive Vice President since February 2007.
+Previously, Mr. McCarvel served as our Senior Vice President—Global Operations from October 2005 to February 2007 and as our Vice President—Asian & Australian
+Operations from January 2005 to September 2005, after providing consulting services to us during 2004. From October 2001 to January 2005, Mr. McCarvel served as Vice President for the Design,
+Test and Semiconductor division of Flextronics, where he was responsible for building Flextronics' engineering infrastructure in Asia and growing Flextronics' business in the region. From 1999 to
+October 2001, he served as President of U.S. Operations and Senior Vice President of Worldwide Sales and Marketing for Singapore Technology Assembly Test Services Ltd., a semiconductor services
+company. He previously worked in executive level positions with Micron Custom Manufacturing Services, Inc., a manufacturer of electronic products for computing and digital applications, and The
+Dii Group. Mr. McCarvel has served us as an executive since 2005. He has been our chief operating officer and has extensive knowledge of our day-to-day operations along
+with a strategic vision as our chief executive officer. Mr. McCarvel's leadership, extensive knowledge of our business and previous manufacturing expertise provide significant value and
+insights to the Board. 
+THE BOARD RECOMMENDS A VOTE "FOR" EACH OF THE ABOVE-NAMED NOMINEES FOR DIRECTOR. 
+Information About Continuing Directors 
+Raymond D. Croghan ( Class II ),
+age 61, has served as a member of the Board since August 2004. Since 1999, Mr. Croghan has been retired. From 1991 to 1999, Mr. Croghan managed Croghan & Associates, Inc.,
+a healthcare information technology consulting firm, which merged with Margolis Health Enterprise to form The TriZetto Group. Mr. Croghan serves on the boards of directors of several
+privately-held companies. Mr. Croghan has successfully operated and grown private companies and has served on the boards of several companies in a variety of industries. His
+experience successfully operating companies in different industries provides us with a unique perspective as does his board 
+4 
+Table of Contents 
+experience.
+In addition, Mr. Croghan is our longest serving director and has extensive knowledge of our company and its operations. 
+Peter A. Jacobi ( Class II ), age 67, has served as a member of the Board since
+October 2008. Mr. Jacobi was employed by Levi Strauss & Company ("Levi Strauss"), a jeans and casual wear manufacturer, from 1970 until his retirement in 1999. During his 29 years
+of tenure at Levi Strauss, Mr. Jacobi held various senior levels positions, including President of the Men's Jeans Division, President of Global Sourcing, President of Levi Strauss
+International, and from 1996 until his retirement, President and Chief Operating Officer. Mr. Jacobi has extensive executive experience in the apparel industry gained through his tenure at Levi
+Strauss. The apparel industry is similar and complementary to the footwear industry and Mr. Jacobi has provided us significant insights from this industry. In addition, Levi Strauss is an
+established international brand. Mr. Jacobi's experience with a global brand has helped us as we continue to build our brand internationally. 
+Richard L. Sharp ( Class II ), age 64, has served as the Chairman of the Board since
+April 2005. From 1982 to 2002, Mr. Sharp served in various positions with Circuit City Stores, Inc., a retailer of consumer electronics, most recently as President from 1984 to 1997,
+Chief Executive Officer from 1986 to 2000 and Chairman of the Board from 1994 to 2002. Mr. Sharp served as Chairman and Chief Executive Officer of CarMax, Inc., the nation's largest
+specialty retailer of used cars and light trucks, from 1994 to 2000 and Chairman from October 2002 to June 2007. In 1992, he was a founding investor of Flextronics. He served as a director of
+Flextronics from 1993 to October 2008 and as Chairman of the Board from January 2003 to January 2006. Mr. Sharp is currently a director of Star Scientific, Inc., a publicly-traded
+smokeless tobacco company. Mr. Sharp has founded and successfully operated large public companies in diverse businesses such as retail consumer electronics, used car retail and electronics
+manufacturing. He brings a unique perspective to the Board both as an entrepreneur and a former chief executive and chairman of other publicly traded companies. His business leadership and experience
+with large companies in retail industries make him well suited to serve as the Chairman of our Board. As previously disclosed, Mr. Sharp is currently on a leave of absence from the Board for
+personal reasons. 
+Ronald L. Frasch (Class I) , age 62, has served as a member of the Board since October 2006. Since February
+2007, Mr. Frasch has served as President and Chief Merchandising Officer of Saks Fifth Avenue, a division of Saks, Incorporated, a NYSE-listed luxury fashion retailer. From November
+2004 until January 2007, he held the post of Vice Chairman and Chief Merchant of Saks Fifth Avenue. From January 2004 to November 2004, he was employed by Saks in a non-executive capacity.
+From April 2000 to January 2004, Mr. Frasch served as Chairman and Chief Executive Officer of Bergdorf Goodman (a subsidiary of Neiman Marcus Group, Inc.) and served as President of GFT
+North America (a subsidiary of Gruppo GFT, based in Turin, Italy, a global producer, marketer and distributor of fine men's and women's clothing, sportswear and furnishings) from 1996 to 2000.
+Mr. Frasch also served as President and Chief Executive Officer of Escada USA from 1994 to 1996. Mr. Frasch has extensive executive expertise in the fashion retail industry, most notably
+demonstrated by his current position at Saks Fifth Avenue. Mr. Frasch's experience and insight into this industry is invaluable to the Board and management in understanding the consumer retail
+and fashion industry, including current buying trends by our wholesale customers. 
+W. Stephen Cannon ( Class I ), age 59, has served as a member of the Board since
+February 2009. Since 2005, he has served as the Chairman of Constantine Cannon LLP, a law firm, and the Managing Partner of Constantine Cannon's Washington D.C. office. From 1994 to 2005,
+Mr. Cannon was the Senior Vice President, General Counsel and Secretary of Circuit City Stores, Inc., a retailer of consumer electronics, which, at the time, was publicly traded on the
+New York Stock Exchange. Prior to joining Circuit City Stores, Inc., Mr. Cannon served as a partner at the law firm of Wunder, Diefenderfer, Ryan, Cannon and Thelen and spent ten years
+in government service, including serving as Chief Antitrust Counsel to the United States Senate Judiciary Committee. Mr. Cannon has 
+5 
+Table of Contents 
+demonstrated
+significant legal and business expertise through his role as general counsel of Circuit City, a public company with significant retail operations. This experience assists the Board with
+its risk oversight and retail expansion plans. Mr. Cannon's legal expertise also allows him to effectively chair the Nominating and Governance Committee and understand corporate governance and
+SEC developments. 
+CORPORATE GOVERNANCE 
+Crocs, Inc. is committed to maintaining sound corporate governance practices. The Board has formalized several policies,
+procedures and standards of corporate governance some of which are described below. We continue to monitor best practices and legal and regulatory developments with a view to further revising our
+governance policies and procedures, as appropriate. 
+Director Independence. NASDAQ listing standards require that the Board consist of a majority of
+independent directors. The Board has determined that all of its current non-management members of the Board (Messrs. Cannon, Croghan, Frasch, Jacobi, Smach and Sharp) are
+independent directors as defined by NASDAQ listing standards. The Board makes a determination regarding the independence of each director annually based on relevant facts and circumstances. Applying
+the standards and independence criteria defined by the NASDAQ listing standards, the Board has made a subjective determination as to each independent director that no relationships exist which, in the
+opinion of the Board, would interfere with the exercise of his independent judgment in carrying out the responsibilities of a director. The independent directors of the Board regularly hold executive
+sessions without members of management present. 
+Communicating with Directors. Stockholders who wish to communicate with the Board or with specified individual directors may do so by
+mailing such
+written communication to: Corporate Secretary, Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503. The Corporate Secretary will review all correspondence and will forward to the Board
+or an individual director a summary of the correspondence received and copies of correspondence that the Corporate Secretary determines requires the attention of the Board or such individual director.
+The Board and any individual director may at any time request copies and review all correspondence received by the Corporate Secretary that is intended for the Board or such individual director. 
+Board Leadership. The Board does not have a policy regarding separation of the roles of Chief Executive Officer and Chairman of the
+Board. The Board
+believes it is in our best interests to make that determination based on current circumstances. The Board has determined that an independent director serving as Chairman is in the best interests of
+our stockholders at this time. This structure ensures a greater role of independent directors in the active oversight of our business, including risk management oversight, and in setting agendas and
+establishing Board priorities and procedures. This structure also allows the Chief Executive Officer to focus to a greater extent on the management of our day-to-day
+operations. 
+Risk Oversight. The Board oversees our risk management activities. The Board implements its risk oversight function both as a whole and
+through
+delegation to its committees. These committees meet regularly and report back to the full Board. The Audit Committee has primary oversight responsibility with respect to financial risks as well as
+oversight responsibility for our overall risk assessment and risk management policies and systems. The Audit Committee oversees our procedures for the receipt, retention and treatment of complaints
+relating to accounting and auditing matters and oversees our management of legal and regulatory compliance systems. The Compensation Committee oversees risks relating to our compensation plans and
+programs. The Compensation Committee also has reviewed and considered our compensation policies and programs in light of the Board's risk assessment and management responsibilities and will do so in
+the future on an annual basis. The Compensation Committee believes that we have no compensation policies and programs that give rise to risks reasonably likely to have a material adverse effect on us. 
+6 
+Table of Contents 
+The Chief Legal and Administrative Officer serves as our chief compliance officer and chairs an inter-disciplinary Compliance Council which is charged with
+assessing and managing our legal and other compliance obligations on a global basis. The Chief Legal and Administrative Officer reports to the Audit Committee regularly on our legal and compliance
+obligations. 
+The
+Director of Internal Audit coordinates the day-to-day risk management process and reports directly to the Chief Financial Officer and to the Audit Committee.
+The Director of Internal Audit performs a risk assessment annually, and updates the Audit Committee at least quarterly regarding our risk analyses, assessments, risk mitigation strategies and
+activities. The Treasury Director updates the Audit Committee at least annually, or more frequently as needed, regarding our directors and officers insurance coverage and on matters regarding certain
+financial risks. 
+Code of Business Conduct and Ethics and Committee Charters. We have adopted a Code of Business Conduct and Ethics that applies to all
+directors and
+employees, including our principal executive, financial and accounting officers. The Amended and Restated Code of Business Conduct and Ethics is posted on our website at www.crocs.com. We intend to
+satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of our Amended and Restated Code of Business Conduct
+and Ethics that apply to our directors and principal executive, financial and accounting officers by posting such information on our website. The Audit Committee Charter, Compensation Committee
+Charter and Nominating and Governance Committee
+Charter are also available on our website at www.crocs.com. Any person may request a copy of the Amended and Restated Code of Business Conduct and Ethics or committee charters free of charge by
+submitting a written request to: Corporate Secretary, Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503. 
+BOARD OF DIRECTORS AND COMMITTEES OF THE BOARD 
+During 2010, the Board met six times. All directors attended 75% or more of the Board's meetings and the meetings of the Board
+committees on which they served. We encourage, but do not require, our directors to attend the annual meeting of stockholders. Messrs. Cannon, Frasch, Jacobi, McCarvel, Smach and Sharp attended
+our 2010 Annual Meeting of Stockholders. 
+Board Committees. The Board has the authority to appoint committees to perform certain management and administrative functions and has
+established
+the following committees. 
+Audit Committee. Messrs. Smach (Chairman), Frasch and Jacobi are the current members of the Audit Committee. The
+Audit Committee met eight times in 2010. The functions of the Audit Committee include oversight of the integrity of our financial statements, our compliance with legal and regulatory requirements, the
+performance, qualifications and independence of our independent auditors and the performance of our internal audit function. The Audit Committee is directly responsible for the appointment, retention,
+compensation, evaluation, termination and oversight of the work of any independent auditor engaged for the purpose of preparing or issuing an audit report or related work. The purpose and
+responsibilities of the Audit Committee are set forth in the Audit Committee Charter. The Audit Committee Charter can be found on our website at www.crocs.com. 
+All
+of the members of the Audit Committee are independent, as determined in accordance with NASDAQ listing standards and relevant federal securities laws and regulations. The Board has
+determined that Mr. Smach qualifies as an "audit committee financial expert" as defined by the applicable regulations of the SEC. 
+Compensation Committee. Messrs Croghan (Chairman), Cannon and Sharp are the current members of the Compensation
+Committee. The Compensation Committee, which met six times in 2010, has overall responsibility for evaluating and approving our executive officer compensation, benefits, severance, equity-based or
+other compensation plans, policies and programs. The Compensation 
+7 
+Table of Contents 
+Committee
+is also responsible for approving our Compensation Discussion and Analysis for inclusion in this proxy statement. The purpose and responsibilities of our Compensation Committee are set forth
+in the Compensation Committee Charter. The Compensation Committee Charter can be found on our website at www.crocs.com. All of the current members of the Compensation Committee are independent, as
+determined in accordance with NASDAQ listing standards and relevant federal securities laws and regulations. 
+The
+Compensation Committee has the authority to establish and monitor our executive compensation programs and to make decisions regarding the compensation of each of the executive
+officers named in the Summary Compensation Table set forth later in this document ("named executive officer" or "NEO"). The Compensation Committee sets the Chief Executive Officer's compensation. The
+Compensation Committee also reviews the recommendations of the Chief Executive Officer with respect to compensation of the other NEOs and, after reviewing such recommendations, sets the compensation
+of the other NEOs. In addition, the Compensation Committee also monitors, administers and approves awards under our various incentive compensation plans for all levels of our employees, including
+awards under our 2007 Equity Incentive Plan and 2008 Cash Incentive Plan. 
+The
+Compensation Committee relies on its judgment when making compensation decisions after reviewing our performance and evaluating each executive's performance against established
+goals, leadership ability and responsibilities, and current compensation arrangements. When setting total compensation for each of the NEOs, the Compensation Committee reviews the NEO's current
+compensation, including equity and non-equity-based compensation. The Compensation Committee also evaluates surveys and other available data regarding the executive compensation programs
+of comparative companies. The compensation program for NEOs and the Compensation Committee assessment process are designed to be flexible so as to better respond to the evolving business environment
+and individual circumstances. 
+Role of Consultants. In 2010, the Compensation Committee and management engaged a third party consultant, Buck Consultants, to provide
+an evaluation
+of the 2010 executive bonus plan, long-term incentives and other executive compensation matters. Please see "Compensation Discussion and Analysis" for further description of 2010 bonus
+metrics and long-term incentives. 
+Nominating and Governance Committee. Our Nominating and Governance Committee currently consists of Messrs. Cannon
+(Chairman) and Croghan. Mr. Sharp served as chairman of the Nominating and Governance Committee until his leave of absence in December 2010. The Nominating and Governance Committee met twice in
+2010. The Nominating and Governance Committee assists the Board in promoting our best interests and that of our stockholders through the implementation of sound corporate governance principles and
+practices. In furtherance of this purpose, the Nominating and Governance Committee identifies individuals qualified to become board members and recommends to the Board the director nominees for
+election at each annual meeting of stockholders. It also reviews the qualifications and independence of the members of the Board and its various committees and makes any recommendations the Nominating
+and Governance Committee members may deem appropriate concerning any changes in the composition of the Board and its committees. The Nominating and Governance Committee also recommends to the Board
+the corporate governance guidelines and standards regarding the independence of outside directors applicable to us and reviews the provisions of the Nominating and Governance Committee Charter on a
+regular basis to confirm that such guidelines, standards and charter remain consistent with sound corporate governance practices and with any applicable legal or regulatory requirements and the NASDAQ
+listing standards. The Nominating and Governance Committee also monitors and leads the Board in its annual review of the Board's performance. 
+The
+purpose and responsibilities of our Nominating and Governance Committee are set forth in the Nominating and Governance Committee Charter. The Nominating and Governance Committee 
+8 
+Table of Contents 
+Charter
+can be found on our website at www.crocs.com. All of the members of the Nominating and Governance Committee are independent, as determined in accordance with the NASDAQ listing standards. 
+Director Nomination Process and Director Qualifications. In identifying potential director candidates, the Nominating and Governance
+Committee relies
+on recommendations from a number of sources, including current directors and officers. The Nominating and Governance Committee may also hire outside consultants, search firms or other advisors to
+assist in identifying director candidates. The Nominating and Governance Committee will consider director candidates recommended by stockholders on the same basis as it considers other candidates. Any
+stockholder wishing to recommend a candidate for consideration by the Nominating and Governance Committee may do so by submitting a written recommendation to the Nominating and Governance Committee in
+accordance with the procedures set forth under "Stockholder Proposals and Nominations for 2012 Annual Meeting." 
+In
+evaluating a candidate for director, our Nominating and Governance Committee considers, among other things, the candidate's judgment, knowledge, integrity, diversity, expertise and
+business and industry experience, and expertise, which are likely to enhance the Board's ability to govern our affairs and business. We do not have a separate policy regarding consideration of
+diversity in identifying
+director nominees but the Nominating and Governance Committee strives to nominate directors with a variety of complementary skills and backgrounds so that, as a group, the Board will possess a broad
+perspective and the appropriate talent, skills and expertise to oversee our business. The Nominating and Governance Committee also takes into account independence requirements imposed by law or
+regulations (including the NASDAQ listing standards). In the case of director candidates recommended by stockholders, the Nominating and Governance Committee may also consider the number of shares
+held by the recommending stockholder, the length of time that such shares have been held and the relationship, if any, between the recommending stockholder and the recommended director nominee. 
+EXECUTIVE OFFICERS 
+In addition to John McCarvel, our President and Chief Executive Officer, whose biographical information is disclosed above under
+"Election of Directors," our executive officers as of March 31, 2011 include the following individuals: 
+Name
+Age 
+Position(s) 
+Daniel P. Hart 
+52 
+Executive Vice President, Chief Legal and Administrative Officer 
+Jeffrey J. Lasher 
+46 
+Corporate Controller, Chief Accounting Officer and interim Principal Financial Officer 
+Scott E. Crutchfield 
+49 
+Senior Vice President of World Wide Operations 
+Daniel P. Hart has served as our Executive Vice President, Chief Legal and Administrative Officer since January 2010. From June 2009
+through December 2009, he served as our Executive Vice President of Administration and Corporate Development. Prior to joining us, Mr. Hart was employed by Océ North America, a
+digital printing and document management division of Océ, N.V., a manufacturing and engineering company publicly traded on the Euronext Amsterdam stock exchange, where he served
+as Senior Vice President and General Counsel from 2006 to 2009. From 2004 to 2006, Mr. Hart served as Senior Vice President—General Counsel and Human Resources for Invensys
+Controls, a global manufacturing and engineering operation within Invensys plc, a public U.K. conglomerate. From 2002 to 2004, Mr. Hart served as Chief Staff Officer for the Development
+Division of Invensys, a large portfolio of disposal companies within Invensys plc. Previously, Mr. Hart's experience included service in senior legal positions at Dictaphone Corporation
+and Brooke Group Ltd. and private legal practice in New York City. He was an executive officer of Dictaphone Corporation in November 2000 when it filed for protection under Chapter 11 of
+the U.S. bankruptcy code. 
+9 
+Table of Contents 
+Jeffrey J. Lasher has served as our Corporate Controller and Chief Accounting Officer since June 2009. In January 2011, Mr. Lasher
+was appointed as our principal accounting officer and interim principal financial officer and effective April 28, 2011, Mr. Lasher was appointed as our Chief Financial Officer. Prior to joining
+us, Mr. Lasher was a Senior Consultant for Connelly Consulting, a privately-held financial services company, from October 2008 to June 2009. From December 2005 to September 2008, he
+was the Vice President—Corporate Controller for Corporate Express Inc., a publicly-held business supplies and equipment company.
+Mr. Lasher was also the Vice President—Finance of AutoNation, Inc., a publicly-held automotive retail company, from December 2000 to December 2005. 
+Scott E. Crutchfield has served as our Senior Vice President of World Wide Operations since May 2010. From February 2006 to May 2010, he
+served as our Vice President for World Wide Operations. Prior to joining us, he served as Senior Director, U.S. and South America Operations for Jabil Circuit, a publicly-held design and
+manufacturing company from May 2004 to January 2006. Mr. Crutchfield was also Vice President, General Manager Central/Eastern U.S. and South America for Flextronics from March 2000 to April
+2004. Previously, Mr. Crutchfield also held senior leadership positions at Dovatron International, a subsidiary of the Dii Group, and at Square D, a subsidiary of Schneider Electric. 
+BENEFICAL OWNERSHIP OF OUR COMMON STOCK 
+Ownership by Our Directors, Executive Officers and Greater than 5% Stockholders 
+The following table sets forth information with respect to the beneficial ownership of our common stock as of March 31, 2011
+by: 
+• each person (or group of affiliated persons) who is known by us to own beneficially more than 5% of our common stock; 
+• each current director or nominee; 
+• each of the named executive officers listed in the Summary Compensation Table below; and 
+• all directors and executive officers as a group. 
+Beneficial
+ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, shares of common stock subject to options held by that person that are
+currently exercisable, or exercisable within 60 days after March 31, 2011, are deemed to be outstanding and beneficially owned by that person. None of these shares, however, are deemed
+outstanding for the purpose of computing the percentage ownership of any other person. 
+Except
+as indicated and pursuant to applicable community property laws, each stockholder named in the table has sole voting and investment power with respect to the shares set forth
+opposite such stockholder's name. Percentage ownership is based on 88,410,942 shares of our common stock outstanding on March 31, 2011. Unless otherwise indicated below, the address for each
+director and 
+10 
+Table of Contents 
+named
+executive officer listed below is in care of Crocs, Inc., 6328 Monarch Park Place, Niwot, Colorado 80503. 
+Beneficial Ownership 
+Name of Beneficial Owner
+Shares 
+Percent 
+5% Stockholders: 
+Blackrock, Inc.(1) 
+6,520,840 
+7.4 
+% 
+The Vanguard Group, Inc(2) 
+4,497,234 
+5.1 
+% 
+Directors: 
+Richard L. Sharp(3) 
+1,185,319 
+1.3 
+% 
+Peter A. Jacobi(4) 
+49,584 
+* 
+Thomas J. Smach(5) 
+195,719 
+* 
+Raymond D. Croghan(6) 
+70,720 
+* 
+W. Stephen Cannon(7) 
+61,746 
+* 
+Ronald L. Frasch 
+50,588 
+* 
+Officers: 
+John P. McCarvel(8) 
+466,364 
+* 
+Daniel P. Hart(9) 
+137,943 
+* 
+John Duerden(10) 
+51,912 
+* 
+Russell C. Hammer(11) 
+24,100 
+* 
+All current directors and executive officers as a group (10 persons)(12) 
+2,293,995 
+2.6 
+% 
+* Less
+than 1%
+(1) Based
+solely on a Schedule 13G/A filed with the SEC on February 3, 2011. The address for Blackrock, Inc. is 40 East
+52 nd Street, New York, New York, 10022.
+(2) Based
+solely on a Schedule 13G filed with the SEC on February 10, 2011. The address for The Vanguard Group, Inc. is 100 Vanguard Blvd.,
+Malvern, PA 19355.
+(3) Shares
+beneficially owned include 357,930 shares subject to options exercisable within 60 days of March 31, 2011, 666,507 shares beneficially
+owned by The RLS Trust, 39,610 shares beneficially owned by BES & RS, LLC, 39,610 shares beneficially owned by EGG & RS, LLC, 39,610 shares beneficially owned by
+RBG & RS, LLC, 39,600 and shares beneficially owned by CSS & RS, LLC. Mr. Sharp is the sole trustee of The RLS Trust and is the sole manager of each of BES &
+RS, LLC, EGG & RS, LLC, and RBG & RS, LLC and CSS & RS, LLC, and he exercises voting and investment power over all of the shares beneficially owned by
+each trust and each company. The address for Mr. Sharp is 9020 Stony Point Parkway, #180, Richmond, VA 23235.
+(4) Shares
+beneficially owned include 47,249 shares held in trust by Peter A Jacobi & Mary Louise Jacobi Living Trust.
+(5) Shares
+beneficially owned include 151,813 shares subject to options exercisable within 60 days of March 31, 2010 and 4,400 shares held as
+custodian for Mr. Smach's two children under the New York Uniform Gifts to Minors Act. Mr. Smach exercises voting and investment power over the shares.
+(6) Shares
+beneficially owned include 58,406 shares subject to options exercisable within 60 days of March 31, 2010 and an aggregate of 4,960
+shares of common stock beneficially owned by two trusts for the benefit of Mr. Croghan's two daughters. Mr. Croghan's spouse is the trustee of both trusts and she exercises sole voting
+and investment power over the shares. Mr. Croghan disclaims beneficial ownership of such shares. 
+11 
+Table of Contents 
+(7) Shares
+beneficially owned are held in trust by The W. Stephen Cannon Revocable Trust.
+(8) Shares
+beneficially owned include 146,915 shares subject to options exercisable within 60 days of March 31, 2011 and 208,964 shares held
+jointly with his spouse.
+(9) Shares
+beneficially owned include 8,333 shares subject to options exercisable within 60 days of March 31, 2011.
+(10) Mr. Duerden
+retired as President and Chief Executive Officer effective March 1, 2010.
+(11) Mr. Hammer
+resigned as our Chief Financial Officer, Senior Vice President—Finance and Treasurer effective December 31, 2010.
+(12) Shares
+beneficially owned include 568,149 shares of common stock subject to options issued to directors and 155,248 shares of common stock subject to
+options issued to named executive officers that are exercisable or issuable within 60 days of March 31, 2011. 
+Section 16 Beneficial Ownership and Compliance 
+Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors and executive officers and persons who
+own more than ten percent of our common stock
+to file with the SEC and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common stock. 
+To
+our knowledge, based solely on a review of the copies of such reports furnished to us and written representations from certain of our officers and directors that no other reports were
+required, we believe that all required reports of our officers, directors and greater than ten percent stockholders under Section 16(a) were timely filed during the year ended
+December 31, 2010. 
+CERTAIN RELATIONSHIPS AND RELATED PERSON TRANSACTIONS 
+Related Person Transactions 
+We had no transactions with related persons during 2010 which are required to be disclosed by the rules of the SEC. 
+Policy on Transactions with Related Persons 
+Our Business Code of Conduct and Ethics requires that any transaction involving us in which one of our directors, nominees for
+director, executive officers, or greater than five percent stockholders, or one of the aforementioned's immediate family members (each, a "related person"), have a material interest be approved or
+ratified by the Audit Committee if the amount involved, when aggregated with the amount of all other transactions between the related person and us, exceeds $100,000 in a fiscal year. The full Board
+reviews ordinary course of business transactions in which directors have an interest as part of the Board's annual director independence review, and our Business Code of Conduct and Ethics permits the
+full Board to waive any conflicts of interest between us and any director or officer. In determining whether to approve or ratify any such transaction, the Audit Committee must consider, in addition
+to other factors it deems appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify certain directors and executive officers in addition to the indemnification provided for
+in our certificate of incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain 
+12 
+Table of Contents 
+expenses
+(including attorneys' fees), judgments, fines and settlement amounts incurred by any such person in any action or proceeding, including any action by us or in our right, arising out of such
+person's services as a director or executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request. We believe that these
+provisions and agreements are necessary to attract and retain qualified persons as directors and executive officers. 
+DIRECTOR COMPENSATION 
+The table below summarizes the total compensation paid to each non-employee directors during the fiscal year ended
+December 31, 2010. 
+Name
+Fees Earned or 
+Paid in Cash 
+Stock Awards(1) 
+Option Awards(1) 
+Total 
+W. Stephen Cannon 
+$ 
+90,000 
+$ 
+99,999 
+$ 
+— 
+$ 
+189,999 
+Raymond D. Croghan 
+3,125 
+291,017 
+— 
+294,142 
+Ronald L. Frasch 
+— 
+280,623 
+— 
+280,623 
+Peter A. Jacobi 
+— 
+280,623 
+— 
+280,623 
+Richard L. Sharp 
+— 
+291,017 
+62,262 
+353,279 
+Thomas J. Smach 
+$ 
+90,000 
+$ 
+204,010 
+$ 
+— 
+$ 
+294,010 
+(1) Represents
+the grant date fair value. Assumptions used in to calculate these values are included in Note 9 to the Consolidated Financial Statements
+included in our Annual Report on Form 10-K for the year ended December 31, 2010. 
+As
+of December 31, 2010, each non-employee director had the following number of stock options and unvested shares of restricted stock outstanding: 
+Options 
+Outstanding at 
+December 31, 2010 
+Unvested Restricted 
+Stock Awards 
+Outstanding at 
+December 31, 2010 
+Raymond D. Croghan 
+58,406 
+4,903 
+Ronald L. Frasch 
+— 
+4,669 
+Peter A. Jacobi 
+— 
+4,669 
+Richard L. Sharp 
+380,430 
+4,903 
+Thomas J. Smach 
+151,813 
+2,335 
+On
+June 29, 2010, the Board approved a new compensation plan for non-employee directors, effective as of that date. Pursuant to the plan, each of our
+non-employee directors was granted $100,000 in annual compensation payable in (a) cash (in quarterly installments of $25,000), (b) shares of restricted stock (based on the
+fair market value of our common stock on the date of grant) which vest in four successive quarterly installments from the date of grant or (c) a combination of cash and restricted stock, at the
+election of each non-employee director. During 2010, Messrs. Croghan, Frasch, Jacobi and Sharp elected to receive their director compensation in stock, and Messrs. Cannon and
+Smach elected to receive their director compensation in cash. Also pursuant to the new compensation plan, each non-employee director was awarded an annual grant of $100,000 of our common
+stock based on the fair market value of our common stock on the date of grant. This annual grant was awarded on the date of our 2010 annual meeting of stockholders. 
+In
+addition to the annual compensation and annual grant of common stock described above, the Chairman of the Board was awarded an annual option to purchase 10,000 shares of our common
+stock at an exercise price equal to the fair market value of the shares on the date of grant. These options
+vest and become exercisable in four equal installments on the respective dates of each of the four annual meetings of stockholders following the year of grant. 
+13 
+Table of Contents 
+The chairperson of the Audit Committee receives an additional $50,000 and each of the chairpersons of the Compensation Committee and the Nominating and Governance
+Committee receives an additional $5,000 in annual compensation. Similar to the annual compensation plan for non-employee directors described above, each chairperson may elect to receive
+his or her additional annual compensation in cash, in restricted stock or a combination thereof. During 2010, Mr. Smach elected to receive his Audit Committee chairperson compensation in stock,
+Mr. Croghan elected to receive his Compensation Committee chairperson compensation in stock and Mr. Sharp elected to receive his Nominating and Governance Committee chairperson
+compensation in stock. 
+All
+directors are reimbursed for their reasonable out-of-pocket expenses incurred in attending meetings of the Board and its committees. 
+EXECUTIVE COMPENSATION 
+COMPENSATION DISCUSSION AND ANALYSIS 
+The following discussion and analysis provides information regarding our executive compensation objectives and principles, procedures,
+practices and decisions, and is provided to help give perspective to the numbers and narratives that follow in the tables within this section. This discussion will focus on the following named
+executive officers (the "NEOs"): 
+• John P. McCarvel, Chief Executive Officer and President 
+• John H. Duerden, former Chief Executive Officer and President 
+• Daniel P. Hart, Executive Vice President, Chief Legal and Administrative Officer 
+• Russell C. Hammer, former Chief Financial Officer, Senior Vice President—Finance and Treasurer 
+Executive Compensation Objectives and Principles 
+The overall objective of our executive compensation program is to create long-term value for our stockholders by attracting
+and retaining talented executives, rewarding superior operating and financial performance, and aligning the long-term interests of our executives with those of our stockholders.
+Accordingly, our executive compensation program incorporates the following principles: 
+• Performance: Compensation should be based on individual job responsibility,
+demonstrated leadership ability, management experience, individual performance and our performance. Employees in positions of leadership and broad responsibility are generally compensated by elements
+that are linked to our overall performance and stockholder returns. 
+• Fair and
+Competitive: Compensation should reflect the fair market value of the services received. We believe that a fair and competitive pay
+package for our NEOs is essential to attract and retain talented executives in key positions. 
+• Short and Long-Term
+Incentives: Compensation is designed to reward NEOs based on both our short-term and long-term performance. Base
+pay is tied to individual performance and market conditions for similar positions. Bonuses are tied to achievement of short-term quantitative performance goals that we believe closely
+correlate to share value. Long-term performance is rewarded through equity-based awards such as stock options and restricted stock, the value of which depends on future share prices, and
+the realization of which is contingent on satisfaction of vesting schedules requiring continued service with us. 
+• Align NEO Interests with Stockholder
+Interests: Compensation should foster long-term focus. Compensation is designed to align executives' interests with those of
+our stockholders. A significant percentage of total compensation is allocated to non-cash compensation as a result of 
+14 
+Table of Contents 
+this
+philosophy. We do not use an exact formula for allocating between cash and non-cash compensation. 
+The
+Compensation Committee forms its judgments regarding the levels and component mix of executive compensation by considering the market competition for executive talent, the risk to an
+executive inherent in employment with a company that has a relatively short operating history and our financial goals. For the year ended December 31, 2010, we awarded cash incentive bonuses
+due to our financial performance during the year. Specifically, reflective of our pay for performance philosophy, cash incentive bonuses for our NEOs were payable contingent upon the achievement of
+certain milestones related to growth in our diluted earnings per share. 
+Elements of Compensation 
+Our executive compensation objectives and principles are implemented through the use of the following elements of compensation, each of
+which is discussed more fully below. 
+• Base Pay 
+• Performance-Based Bonus 
+• Long-Term Equity Awards 
+• Other Personal Benefits 
+Our
+executive compensation program seeks to attract, retain, and motivate exemplary executive talent who are able to succeed in our fast paced, rapidly evolving company. Our executive
+compensation program also seeks to hold our executives accountable and reward them appropriately for successful business results. We are firmly committed to our stockholders and our executive
+compensation program is structured to align our executives' compensation with our stockholders' interests. To meet each of these objectives, our core executive compensation program encompasses base
+salaries, annual performance-based incentive compensation and long-term equity incentive awards. We believe that the total compensation opportunities offered to our executives are
+sufficient to reduce the need for anything other than limited executive perquisites (which are detailed later in this report) or enhanced benefit programs beyond those that are typically available to
+all other employees. 
+The
+Compensation Committee does not utilize an exact calculation in determining the break-down of NEO compensation among base pay, annual performance-based bonus and
+long-term equity awards; rather, the Compensation Committee takes into consideration all forms of compensation. Because we are a rapidly evolving company, we believe that a substantial
+portion of each NEO's compensation should be in the form of annual performance-based bonus and equity awards. In general, base pay of the NEOs is set at levels that the Compensation Committee believes
+are competitive with our market peers of the S&P 600 Footwear Index and similar companies due to either their multi-brand business model or similar growth patterns (collectively, "Peers"), with
+the expectation that shortfalls in base pay, if any, will be recouped through performance bonuses should our performance entitle the NEO to receive performance bonuses and through the value of equity
+awards. While the Compensation Committee does not benchmark compensation to a specific percentage of the compensation of our Peers, it does use Peer data to guide its review of the total compensation
+of our officers and executives 
+15 
+Table of Contents 
+and
+generally reviews the compensation data of our Peers to understand market competitive compensation. The Peers and the criteria for their inclusion are listed below: 
+Company
+Criteria 
+American Apparel, Inc. 
+Similar Multi-Brand Business Model 
+Brown Shoe Co., Inc. 
+S&P 600 Footwear 
+Cole Kenneth Productions, Inc. 
+S&P 600 Footwear 
+Columbia Sportswear Co. 
+Similar Multi-Brand Business Model 
+Deckers Outdoor Corp. 
+Similar Multi-Brand Business Model 
+Delta Apparel, Inc. 
+Similar Multi-Brand Business Model 
+G III Apparel Group, Ltd. 
+Similar Multi-Brand Business Model 
+K-Swiss, Inc. 
+S&P 600 Footwear 
+Lululemon Athletica, Inc. 
+Similar Multi-Brand Business Model 
+Oxford Industries, Inc. 
+S&P 600 Footwear 
+Perry Ellis International, Inc. 
+S&P 600 Footwear 
+Quiksilver, Inc. 
+S&P 600 Footwear 
+Skechers USA, Inc. 
+S&P 600 Footwear 
+Steven Madden, LTD 
+S&P 600 Footwear 
+Timberland Co. 
+Similar Multi-Brand Business Model 
+True Religion Apparel, Inc. 
+S&P 600 Footwear 
+Under Armour, Inc. 
+Similar Growth Pattern 
+Volcom, Inc. 
+S&P 600 Footwear 
+Wolverine World Wide, Inc. 
+S&P 600 Footwear 
+Base Pay. With the exception of Mr. McCarvel, the Compensation Committee established current base pay for our NEOs in 2009 by
+considering the
+size of our operations, the responsibilities of the NEOs and the competitive marketplace for executive talent in similar positions. The base pay for Messrs. Hart and Hammer was not increased in
+2010. The Compensation Committee sets the base pay of the Chief Executive Officer. Base pay for other NEOs is set by the Compensation Committee after reviewing the recommendation of the Chief
+Executive Officer. Annual adjustments are influenced by growth of our operations, revenues and profitability, individual performance, changes in responsibility and other factors. During 2009, we
+entered into employment agreements with each of Messrs. Duerden, Hart and McCarvel which set forth base pay and performance-based bonus targets, among other things. The salary and bonus targets
+set forth in those agreements were determined based on our needs, the level of responsibility of each NEO's position, and the amount required to attract (in the case of Messrs. Duerden and
+Hart) and retain (in the case of Mr. McCarvel) talented NEOs. Following Mr. McCarvel's promotion to Chief Executive Officer in March 2010, the Compensation Committee increased
+Mr. McCarvel's salary to reflect the additional responsibilities of his position and to make his base pay competitive with the chief executive officers of our Peers. While there were no merit
+adjustments to base pay in 2010, individual performance is considered by the Compensation Committee in any merit raises for our NEOs. 
+Performance-Based Bonuses. In an effort to encourage achievement of our performance objectives, the amount of potential bonus to be
+paid to the NEOs
+for the year upon achievement of these performance objectives is set at a level which the Compensation Committee believes is in excess of the bonuses paid by our Peers. The combination of base pay and
+performance-based bonuses is intended to result in an aggregate rate of salary and bonus compensation exceeding competitive market standards when we exceed the performance objectives set by the
+Compensation Committee. The Compensation Committee believes that a compensation plan exceeding competitive market standards offers NEOs additional incentive to outperform our Peers and ensures that we
+attract and retain talented NEOs. 
+16 
+Table of Contents 
+For
+2010, the bonus amount for each NEO was expressed as a percentage of up to 175% of the NEO's bonus target contingent on us achieving certain annual threshold revenue, earnings per
+share, inventory turnover and net unrestricted cash targets. These targets are weighted, with 50% of the target bonus
+contingent upon achieving our earnings per share target, 20% contingent upon achieving our sales growth target, and 15% each contingent upon achieving our inventory turnover and net unrestricted cash
+targets. Each of these targets has a threshold payout of 75% of the NEO's bonus target and a maximum payout of 175% of the NEO's bonus target. If we did not reach the threshold targets, the NEOs would
+not have been eligible for that portion of the bonus. The bonus targets were determined in early 2010 by the Compensation Committee based on the estimated contribution and responsibility of the
+individual NEO. Mr. McCarvel's target bonus amount was 100%, Mr. Hammer's 60% and Mr. Hart's 60% of their respective annual base pay. When setting the bonus targets and maximums,
+the Compensation Committee also takes into consideration the inherent employment risk accepted by an officer of a rapidly evolving company with a volatile and relatively limited operating history. The
+Compensation Committee has discretion to depart from the formula in approving the bonuses and decrease bonuses after general results are known. 
+After
+reviewing 2010 actual results, the Compensation Committee determined that our NEOs would be paid bonuses at 118% of their respective target bonus amounts because our 2010
+performance results, in the aggregate, exceeded the aggregate weighted performance targets by 18%. Our annual performance-based bonuses are paid pursuant to our 2008 Cash Incentive Plan. This plan
+qualifies as a performance-based compensation plan in accordance with Section 162(m) of the Internal Revenue Code (hereafter referred to as the "Code"). Please see "Deductibility of Executive
+Compensation" below for further discussion. Mr. McCarvel declined to take any bonus amounts above his target (100% of base pay) in respect to 2010. 
+In
+March 2011, the Compensation Committee approved bonus metrics for 2011. Under the approved 2011 bonus metrics, the bonus amount for each NEO is expressed as a percentage of the NEO's
+bonus target ranging up to 175% contingent upon us achieving certain sales growth, earnings per share, inventory turnover and net unrestricted cash targets (net of short- and long-term
+debt). These targets are weighted, with 50% of the target bonus contingent upon achieving our GAAP earnings per share target, 20% contingent upon achieving our sales growth target, and 15% each
+contingent upon achieving our inventory turnover and net unrestricted cash targets. 
+Senior Executive Deferred Compensation Plan. Certain senior executives, including NEOs, are eligible to participate in the 2007 Senior
+Executive
+Deferred Compensation Plan (the "Senior Executive Plan"). Under the Senior Executive Plan, a participant may defer all or a part of his or her bonus amount exceeding 200% of such participant's target
+bonus in accordance with the applicable deferral agreement executed by the participant. The deferred compensation is credited to a deferral account established for each participant under the Senior
+Executive Plan for recordkeeping purposes. Under the Senior Executive Plan, we established an irrevocable trust into which we are required to deposit cash or other assets as specified in the
+applicable deferral agreement, equal to the aggregate amount required to be credited to the participant's deferral account, less any applicable taxes required to be withheld. In 2008,
+Mr. McCarvel elected to participate in the Senior Executive Plan and deferred $640,000 of his 2007 performance-based bonus. The deferred bonus for Mr. McCarvel will vest ratably on a
+quarterly basis over a three year period, with a pro rata amount vesting on each calendar quarter, providing a long-term retention incentive. The deferred bonus for Mr. McCarvel
+will be 100% vested upon a change of control (as defined in the Senior Executive Plan) if he is employed at that time or if his employment is terminated as a result of death or disability. No NEOs
+contributed to our Senior Executive Plan in 2009 or 2010. 
+Long-Term Equity Awards. Discretionary long-term equity awards, in the form of restricted stock, are granted annually, at the
+Compensation Committee's discretion, to the NEOs in order to provide long-term performance-based compensation, to encourage the NEOs to continue their employment 
+17 
+Table of Contents 
+throughout
+the vesting periods of the awards, and to align management and stockholder interests. As noted above, we believe that a substantial portion of each NEO's compensation should be in the form
+of equity awards. The Compensation Committee considers the number of shares to grant and the appropriate combination of equity-based awards in making NEO grant decisions. 
+During
+2010, the Board approved grants of restricted stock awards to our NEO's as part of a performance incentive plan. Half of such grants vest ratably on each of the first four
+anniversaries of the grant date. The remaining half vest on a cliff basis on the fourth anniversary of the grant date, provided that the NEO is still employed by us and certain corporate performance
+metrics relating to free cash flow are achieved over such four year period. Free cash flow was selected as the performance measure by the Compensation Committee as it is viewed as a primary driver of
+enhanced stockholder value. The Compensation Committee had previously granted restricted stock awards that only vested based on years of service. The performance-based vesting component to the
+restricted stock awards was included in 2010 to further demonstrate our pay for performance philosophy and better align the interests of our NEOs with those of our stockholders. During the year ended
+December 31, 2010, 535,600 of these performance-based restricted stock awards and units were granted to our employees, 119,384 of which were granted to our NEOs. For 2010, the amount of
+restricted stock awards granted to NEOs was based on a review of the equity compensation of our Peers, input from Buck Consulting and the Compensation Committee's assessment of each NEO's expected
+future contributions. 
+No
+stock options awards were granted to our NEOs in 2010. The Compensation Committee believes that full value awards such as restricted stock offer a stronger retention incentive than do
+stock options. In addition, restricted stock awards are less dilutive to our current stockholders and to the 2007 Equity Incentive Plan than are stock options, as fewer restricted stock awards are
+necessary to provide the same equity benefit compared to stock options. 
+Other Benefits. Other benefits are provided to the NEOs in order to achieve a competitive pay package. The Compensation Committee
+believes that those
+benefits, which are detailed in the Summary Compensation Table under the heading "All Other Compensation," are reasonable, competitive and consistent with our overall executive compensation program.
+Those benefits consist principally of employer-paid premiums on health insurance, relocation expenses, company vehicles and travel and other costs for NEOs in the process of relocating to
+the Niwot, Colorado area. 
+John P. McCarvel Employment Agreement. Effective March 1, 2010, John P. McCarvel was appointed as our President and Chief
+Executive Officer.
+Prior to his appointment as President and Chief Executive Officer, Mr. McCarvel served as our Executive Vice President and Chief Operating Officer. We entered into an employment agreement with
+Mr. McCarvel in February 2009. The employment agreement was intended to provide incentive for Mr. McCarvel to remain employed with us and such employment agreement expired in February
+2011. Unlike Messrs Duerden and Hart where an employment agreement was necessary for inducement purposes, the Compensation Committee does not currently believe that an employment agreement with
+Mr. McCarvel is necessary. The Compensation Committee believes that as a long time employee of our company Mr. McCarvel will have sufficient incentive to stay with us due to his
+long-term equity awards and significant bonus potential. In addition, given the opportunity, the Compensation Committee would also generally prefer to negotiate a severance package, if
+any, based on the particular circumstances of an NEO's departure rather than pursuant to a prearranged severance arrangement in an employment agreement. Upon his appointment as our President and Chief
+Executive Officer, Mr. McCarvel's base pay was increased to $800,000, his target bonus was increased to 100% of his base pay, and he was reimbursed for reasonable costs related to his
+relocation from Singapore to the Niwot, Colorado area and awarded an additional amount of relocation expenses to facilitate his move and domestic reintegration after more than a decade abroad. 
+18 
+Table of Contents 
+John H. Duerden Employment and Separation Agreements. John H. Duerden served as our President and Chief Executive Officer from
+March 18, 2009
+to March 1, 2010. Concurrent with his appointment as our President and Chief Executive Officer, we entered into an employment agreement with Mr. Duerden on February 24, 2009. On
+March 31, 2010, we and Mr. Duerden entered into a separation agreement whereby we agreed to pay Mr. Duerden a cash severance payment and accelerate the vesting of certain equity
+awards in exchange for Mr. Duerden's compliance with noncompetition, nonsolicitation, confidentiality, invention assignment and certain other covenants. Both agreements are described in detail
+in "Employment Arrangements" below. 
+Daniel P. Hart Employment Agreement. In May 2009, we entered into an employment agreement with Daniel P. Hart concurrent with his
+appointment as an
+officer effective June 15, 2009. This agreement provides certain minimum compensation levels and severance upon certain termination events. The agreement was intended to incentivize
+Mr. Hart to join and remain with us. 
+Russell C. Hammer Employment Agreement. In January 2008, we entered into an employment agreement with Russell Hammer in connection with
+his
+appointment as our Chief Financial Officer. The agreement provides for certain minimum compensation amounts and severance upon our termination of Mr. Hammer's employment without cause.
+Mr. Hammer resigned as our Chief Financial Officer, Senior Vice President-Finance and Treasurer effective December 31, 2010. No severance amounts were triggered under the agreement by
+Mr. Hammer's departure 
+Deductibility of Executive Compensation 
+Section 162(m) of the Code imposes a $1.0 million annual limit on the amount that a public company may deduct for
+compensation paid to the company's chief executive officer during a tax year or to any of the company's four other most highly compensated executive officers who are still employed at the end of the
+tax year. The limit does not apply to compensation that meets the requirements of the Code for "qualified performance-based" compensation (i.e., compensation paid only if the executive meets
+pre-established, objective goals based on performance criteria approved by the company's stockholders). 
+The
+Compensation Committee reviews and considers the deductibility of executive compensation under Section 162(m) of the Code. In certain situations, the Compensation Committee
+may approve compensation that does not meet the requirements of the Code in order to ensure competitive levels of total compensation for our executive officers. Stock grants in 2010 were intended to
+constitute "qualified performance-based compensation" under Section 162(m). The annual performance bonuses paid in 2011 under our 2008 Cash Incentive Plan also met the requirements for
+consideration as "qualified performance-based compensation" under Section 162(m). 
+19 
+Table of Contents 
+COMPENSATION COMMITTEE REPORT 
+The Compensation Committee has reviewed the foregoing Compensation Discussion and Analysis required by Item 402(b) of
+Regulation S-K and discussed the Compensation Discussion and Analysis with our management. Based on such review and discussions with management, the Compensation Committee
+recommended to the Board that the foregoing Compensation Discussion and Analysis be included in this proxy statement. 
+THE
+COMPENSATION COMMITTEE 
+Ray Croghan (Chairman) 
+W. Stephen Cannon 
+SUMMARY COMPENSATION TABLE 
+The following summary compensation table indicates the cash and non-cash compensation during the fiscal years ended
+December 31, 2010, 2009 and 2008 of (i) the individuals who served as our Chief Executive Officer during 2010, (ii) our Chief Financial Officer, and (iii) our other
+executive officer who was serving as an executive officer at the end of 2010. The compensation described in this table does not include benefits that are generally available to all of our salaried
+employees. 
+Name and 
+Principal Position
+Year 
+Salary 
+($) 
+Bonus 
+($) 
+Stock 
+Awards(1) 
+($) 
+Option 
+Awards(1) 
+($) 
+Non-Equity 
+Incentive Plan 
+Compensation(2) 
+($) 
+All Other 
+Compensation(3) 
+($) 
+Total 
+($) 
+John P. McCarvel(4) 
+2010 
+$ 
+766,667 
+$ 
+— 
+$ 
+831,723 
+$ 
+— 
+$ 
+800,000 
+$ 
+233,451 
+$ 
+2,631,841 
+President and Chief 
+2009 
+595,833 
+240,000 
+— 
+— 
+— 
+42,211 
+878,044 
+Executive Officer 
+2008 
+500,000 
+— 
+136,800 
+2,284,672 
+— 
+14,230 
+2,935,702 
+Daniel P. Hart(5) 
+2010 
+475,000 
+— 
+296,298 
+— 
+339,150 
+32,046 
+1,142,494 
+Executive Vice 
+2009 
+259,119 
+208,220 
+598,500 
+403,680 
+— 
+130,565 
+1,600,084 
+President, Chief Legal and Administrative Officer 
+John H. Duerden(6) 
+2010 
+144,936 
+— 
+— 
+— 
+— 
+1,777,096 
+1,922,032 
+Former Chief 
+2009 
+670,191 
+338,836 
+548,000 
+237,440 
+— 
+434,535 
+2,229,002 
+Executive Officer and President 
+Russell C. Hammer(7) 
+2010 
+450,000 
+— 
+280,710 
+— 
+— 
+19,581 
+750,291 
+Former Chief 
+2009 
+450,000 
+135,000 
+— 
+— 
+— 
+80,739 
+665,739 
+Financial Officer, 
+2008 
+$ 
+413,221 
+$ 
+— 
+$ 
+614,880 
+$ 
+2,525,188 
+— 
+$ 
+66,386 
+$ 
+3,619,675 
+Senior Vice President—Finance and Treasurer 
+(1) Amounts
+reflect the aggregate grant date fair value of grants made in each respective fiscal year. Assumptions used in the calculations of these amounts are
+included in Note 9 to our Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2010.
+(2) Amounts
+reflect bonuses earned in 2010 which were paid in 2011.
+(3) All
+other compensation in 2010 represents the following: 
+• Incremental healthcare premiums paid by us on behalf of the NEO. We cover 100% of
+the healthcare premiums for certain executives, a benefit that is not offered to other employees. In 2010, the annual value of this incremental benefit to each NEO was approximately $6,263. 
+• For Mr. Duerden, approximately $1.8 million in cash severance
+payments. 
+20 
+Table of Contents 
+• For Mr. McCarvel, $222,788 in relocation and reintegration costs and for
+Mr. Hart, $25,593 in relocation and moving costs. 
+• For Mr. Hammer, $13,318 in travel costs to and from his respective places of
+residence in Illinois and Colorado and certain living costs such as rent for a temporary place of residence near our headquarters.
+(4) Mr. McCarvel
+was appointed as our President and Chief Executive Officer effective March 1, 2010. During 2008 and 2009, he served as our
+Executive Vice President and Chief Operating Officer.
+(5) Mr. Hart
+was appointed as our Executive Vice President of Administration and Corporate Development in June 2009. Effective January 1, 2010,
+Mr. Hart was appointed as our Executive Vice President, Chief Legal and Administrative Officer.
+(6) On
+February 24, 2009, Mr. Duerden was appointed as our President and Chief Executive Officer effective March 16, 2009.
+Mr. Duerden retired as President and Chief Executive Officer effective March 1, 2010.
+(7) Mr. Hammer
+resigned as our Chief Financial Officer, Senior Vice President—Finance and Treasurer effective December 31, 2010. 
+GRANTS OF PLAN-BASED AWARDS TABLE 
+The table below summarizes the plan-based awards granted during the year ended December 31, 2010 to each of the NEOs
+listed in the Summary Compensation Table. 
+Estimated Future 
+Payouts Under 
+Non-Equity Incentive 
+Plan Awards(1) 
+All Other 
+Stock 
+Awards: 
+Number of 
+Shares of 
+Stock or 
+Units 
+(#)(2) 
+Grant Date Fair 
+Value of Stock 
+and Option 
+Awards(3) 
+Name
+Grant Date 
+Target 
+($) 
+Maximum 
+($) 
+John P. McCarvel 
+6/15/10 
+$ 
+— 
+$ 
+— 
+70,485 
+$ 
+831,723 
+3/29/2010 
+800,000 
+1,400,000 
+— 
+— 
+Daniel P. Hart 
+6/15/10 
+— 
+— 
+25,110 
+296,298 
+3/29/2010 
+285,000 
+498,750 
+John H. Duerden 
+— 
+— 
+— 
+— 
+— 
+Russell C. Hammer(4) 
+6/15/10 
+— 
+— 
+23,789 
+$ 
+280,710 
+3/29/2010 
+$ 
+270,000 
+$ 
+472,500 
+— 
+— 
+(1) Awards
+represent possible payments under our 2008 Cash Incentive Plan. Payments are based on specified target levels of revenue, earnings per share,
+inventory turnover and net unrestricted cash targets, as described in "Compensation Discussion and Analysis" above. The target payments were based on achieving the target level of performance with
+ranges up to 175% of the NEO's bonus target. Actual amounts paid in 2011 related to 2010 performance are reflected in the "Summary Compensation Table" set forth above.
+(2) On
+June 15, 2010, the Compensation Committee approved grants of restricted stock awards to certain of our NEOs as part of a performance incentive
+plan. Half of such grants vest ratably on each of the first four anniversaries of the grant date. The remaining half vest on a cliff basis on the fourth anniversary of the grant date, provided that
+the executive is still employed by us on such date and certain corporate performance metrics are achieved.
+(3) Assumptions
+used in the calculations of grant date fair values are set forth in Note 9 to our Consolidated Financial Statements included in our
+Annual Report on Form 10-K for the year ended December 31, 2010.
+(4) Mr. Hammer
+was no longer employed by us as of December 31, 2010. Consequently, no potential bonus amount was paid and all outstanding unvested
+stock awards were forfeited. 
+21 
+Table of Contents 
+Employment Arrangements 
+The following employment agreements with Messrs. McCarvel, Hart and Hammer were effective during 2010. We also entered into a
+separation agreement with Mr. Duerden in connection with his retirement in March 2010. 
+John P. McCarvel. In February 2009, we entered into an employment agreement with Mr. McCarvel, our current President and
+Chief Executive
+Officer and former Chief Operating Officer and Executive Vice President, ("Mr. McCarvel's Agreement"). Mr. McCarvel's Agreement expired pursuant to its terms in February 2011. 
+Upon
+Mr. McCarvel's appointment as our President and Chief Executive Officer, Mr. McCarvel's base compensation was increased to $800,000, his target bonus was increased to
+100% of base pay, and he was reimbursed for reasonable costs related to his relocation from Singapore to the Niwot, Colorado area. 
+Daniel P. Hart. In May 2009, we entered into an employment agreement with Mr. Hart ("Mr. Hart's Agreement"), our
+current Executive Vice
+President, Chief Legal and Administrative Officer. Mr. Hart's Agreement provides that Mr. Hart will receive an annual base pay of $475,000, subject to annual adjustments.
+Mr. Hart's base pay in 2010 remained at $475,000. The Board may reduce Mr. Hart's base pay only if such reduction is a uniformly applied reduction affecting all senior executives and is
+no greater than 10% of Mr. Hart's base pay. In any case, the Board may not reduce Mr. Hart's base pay by greater than $47,500 in total during his employment with us. Mr. Hart is
+also eligible for a bonus pursuant to our 2008 Cash Incentive Plan. Mr. Hart's bonus target was 60% of his base pay in 2010. He is also entitled to participate in all employee benefit plans and
+programs generally available to our executives, including our Senior Executive Plan. Any and all stock options granted to Mr. Hart during his employment shall remain exercisable for
+10 years after the date of grant, including if Mr. Hart ceases to be employed by us for any reason other than termination for "cause," as defined in Mr. Hart's Agreement. In the
+event of a "Change of Control," all unvested stock options and unvested restricted stock then held by Mr. Hart, and which are scheduled to vest over the 24 months following such event,
+shall immediately vest upon the effective date of such Change in Control. 
+Mr. Hart's
+Agreement also provides that if he is terminated by us involuntarily without cause (as defined in Mr. Hart's Agreement), or if he resigns for good reason (as
+defined in Mr. Hart's Agreement), he will receive: (a) a lump sum payment equal to one year of his base pay as of the termination date; (b) a lump sum payment equal to 80% of his
+base pay in effect as of the termination date, pro-rated to equal the proportion of the year that he was employed by us; (c) a lump sum payment equal to 80% of his base pay as of
+the termination date, and (d) immediate vesting of any unvested stock options or unvested restricted stock then held by him that would have been vested had he remained employed for
+24 months after the termination date. 
+Mr. Hart's
+Agreement requires him to maintain confidential information regarding us and to assign certain inventions and intellectual property to us. During his employment with us
+and for twelve months after the termination of his employment with us, Mr. Hart will be restricted from participating in certain competitive businesses and from soliciting our employees and
+customers. 
+Russell C. Hammer. In January 2008, we entered into an employment agreement with Mr. Hammer, our former Chief Financial
+Officer, Senior Vice
+President—Finance, and Treasurer ("Mr. Hammer's Agreement"). Mr. Hammer's Agreement provided that he receive a base pay of $31,250 per month, subject to annual adjustments.
+Mr. Hammer's base pay in 2010 was $37,500 per month ($450,000 per year). He was also eligible to receive bonuses pursuant to our 2008 Cash Incentive Plan based on performance criteria
+established by the Compensation Committee. Mr. Hammer's bonus target was 60% of his base pay in 2010. 
+22 
+Table of Contents 
+Effective
+December 31, 2010, Mr. Hammer resigned as Chief Financial Officer, Senior Vice President—Finance and Treasurer. He is restricted from participating in
+certain competitive businesses for a period of six months from the date of his resignation. He is also restricted from soliciting our employees and customers for a period of twelve months from the
+date of his resignation. 
+John Duerden. On February 24, 2009, John Duerden was appointed as our President and Chief Executive Officer effective
+March 16, 2009.
+Upon his initial appointment in February, we entered into an employment agreement with Mr. Duerden ("Mr. Duerden's Agreement"). Mr. Duerden's Agreement provided that
+Mr. Duerden would receive an annual base pay of $850,000, subject to annual adjustments. Mr. Duerden's bonus target was 100% of his base pay, with a possible payout of up to 200% of his
+annual base pay pursuant to our 2008 Cash Incentive Plan. 
+On
+March 31, 2010, we entered into a separation agreement (the "Separation Agreement") with Mr. Duerden. The Separation Agreement provided that we (i) pay
+Mr. Duerden lump sum payments totaling approximately $1.8 million on our first regular payroll date after September 1, 2010; (ii) accelerate the vesting of 100,000 unvested
+options to purchase our common stock and 100,000 unvested restricted shares of our common stock previously granted to Mr. Duerden, which would have vested if Mr. Duerden had remained
+employed by us for one year following his retirement date; and (iii) pay the employer portion of Mr. Duerden's health insurance until the earlier of February 28, 2011 or until
+Mr. Duerden is no longer eligible for COBRA continuation. Mr. Duerden was permitted to exercise any of such vested options within three months after March 1, 2010. 
+The
+payments pursuant to the Separation Agreement are conditioned upon Mr. Duerden's compliance with the noncompetition, nonsolicitation, confidentiality, invention assignment and
+certain other
+covenants in Mr. Duerden's Agreement. Mr. Duerden also agreed to release us from all claims relating to Mr. Duerden's service to us through the date of the Separation Agreement. 
+Salary and Bonus in Proportion to Total Compensation 
+As noted in "Compensation Discussion and Analysis" above, we believe that a substantial portion of each NEO's compensation should be in
+the form of performance-based bonuses and equity awards. Base pay of the NEOs is set at levels that the Compensation Committee believes are competitive with our Peers, with the expectation that
+shortfalls in base pay, if any, will be recouped through performance bonuses. The Compensation Committee believes that our current program substantially aligns the compensation of our NEOs with the
+compensation of executive officers of our Peers, while also permitting the Compensation Committee to provide incentives to the NEOs to pursue performance that increases stockholder value. Please see
+"Compensation Discussion and Analysis" for a description of the objectives of our compensation program and overall compensation philosophy. 
+23 
+Table of Contents 
+OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END 
+The following table sets forth outstanding options and stock awards of our NEOs as of December 31, 2010. 
+Option Awards 
+Stock Awards 
+Name
+Number of 
+Securities 
+Underlying 
+Unexercised 
+Options 
+(#) 
+Exercisable 
+Number of 
+Securities 
+Underlying 
+Unexercised 
+Options 
+(#) 
+Unexercisable 
+Option 
+Exercise 
+Price 
+($) 
+Option 
+Expiration 
+Date 
+Number of 
+Shares or 
+Units of Stock 
+That Have 
+Not Vested 
+(#) 
+Market Value of 
+Shares or 
+Units of Stock 
+That Have 
+Not Vested 
+($)(1) 
+John P. McCarvel 
+11,933 
+68,521 
+(2) 
+$ 
+1.14 
+11/17/2018 
+110,485 
+(3) 
+$ 
+1,891,503 
+120,086 
+— 
+10.50 
+2/7/2016 
+— 
+— 
+Daniel P. Hart 
+— 
+125,000 
+(5) 
+3.99 
+6/15/2019 
+125,110 
+(6) 
+2,141,883 
+Russell C. Hammer(4) 
+1,778 
+— 
+1.14 
+11/17/2018 
+— 
+— 
+4,169 
+— 
+10.03 
+6/2/2018 
+— 
+— 
+John H. Duerden 
+— 
+— 
+$ 
+— 
+— 
+— 
+$ 
+— 
+(1) Based
+on a price of $17.12 per share, which was the closing price of our common stock on the NASDAQ Global Select Market on December 31, 2010.
+(2) Represents
+the unvested portion of stock options to purchase 143,000 shares of common stock, which were granted on November 17, 2008. This stock
+option award has a four year vesting period with 25% vesting on the first anniversary of the grant date and the remaining options vesting in 36 equal monthly installments thereafter, based on
+continued employment.
+(3) Represents
+the unvested portion of two restricted stock grants: one for 120,000 shares granted on November 17, 2008 which vest annually in equal
+installments on the next three grant date anniversaries, based on continued employment; and one for 70,485 shares awarded on June 15, 2010 of which 35,243 shares vest ratably on each of the
+first four anniversaries of the grant date based on continued employment and the remaining 35,242 shares vest on a cliff basis on the fourth anniversary of the grant date, provided that the executive
+is still employed by us on such date and certain corporate performance metrics are achieved.
+(4) Mr. Hammer's
+unvested stock awards were forfeited upon his resignation, effective December 31, 2010.
+(5) Represents
+the unvested portion of a stock option to purchase 200,000 shares of common stock, which was granted on June 15, 2009. This stock option
+vests over four years with 25% vesting on the first anniversary of the grant date and the remaining options vesting in 36 equal monthly installments thereafter, based on continued employment.
+(6) Represents
+the unvested portion of two restricted stock grants: one for 150,000 shares granted on June 15, 2009 which vest annually in equal
+installments on the next three grant date anniversaries, based on continued employment; and 25,110 shares awarded on June 15, 2010 of which half vest ratably on each of the first four
+anniversaries of the grant date based on continued employment and the remaining half vest on a cliff basis on the fourth anniversary of the grant date, provided that the executive is still employed by
+us on such date and certain corporate performance metrics are achieved. 
+24 
+Table of Contents 
+OPTION EXERCISES AND STOCK VESTED 
+The table below sets forth options exercised and stock awards vested for our NEOs during the year ended December 31, 2010. 
+Option Awards 
+Stock Awards 
+Name
+Number of 
+Shares Acquired 
+on Exercise 
+(#) 
+Value 
+Realized on 
+Exercise 
+($) 
+Number of 
+Shares Acquired 
+on Vesting 
+(#) 
+Value 
+Realized on 
+Vesting 
+($) 
+John P. McCarvel 
+62,546 
+$ 
+791,244 
+40,000 
+$ 
+636,400 
+Daniel P. Hart 
+75,000 
+704,890 
+50,000 
+590,000 
+John H. Duerden(1) 
+200,000 
+1,572,386 
+200,000 
+1,635,083 
+Russell C. Hammer 
+100,824 
+$ 
+579,198 
+39,000 
+$ 
+527,821 
+(1) Includes
+100,000 shares of restricted stock and 100,000 stock options subject to accelerated vesting pursuant to Mr. Duerden's separation agreement. 
+NONQUALIFIED DEFERRED COMPENSATION 
+Under our Senior Executive Plan, participants have the option to defer any bonus amount exceeding 200% of the participant's target
+bonus. The deferred amount will vest ratably on a quarterly basis over a three-year period, with a pro rata amount vesting on each calendar quarter. Any unvested balance will vest
+immediately upon the death or disability of the participant or upon a Change in Control, as defined in the plan. None of the NEOs deferred any compensation in 2010. The table below summarizes the 2010
+accrued earnings and balances at December 31, 2010 under our Senior Executive Plan for each of the NEOs listed in the Summary Compensation Table. 
+Name
+Executive 
+Contributions 
+in Last Fiscal 
+Year 
+$ 
+Crocs, Inc. 
+Contributions 
+in Last Fiscal 
+Year 
+$ 
+Aggregate 
+Earnings in 
+Last Fiscal 
+Year(1) 
+$ 
+Aggregate 
+Withdrawals/ 
+Distributions 
+$ 
+Aggregate 
+Balance at 
+Last Fiscal 
+Year End 
+$ 
+John P. McCarvel 
+$ 
+— 
+$ 
+— 
+$ 
+57,020 
+$ 
+— 
+$ 
+708,767 
+Daniel P. Hart 
+— 
+— 
+— 
+— 
+— 
+John H. Duerden 
+— 
+— 
+— 
+— 
+— 
+Russell C. Hammer 
+— 
+— 
+— 
+— 
+— 
+(1) Each
+participant in the Senior Executive Plan may choose, at his or her discretion, a portfolio of investments in which their contributions may be
+hypothetically invested. We are not obligated to invest the participant's contributions into these accounts; however, upon the participant's withdrawal, we are obligated to pay the amount, inclusive
+of earnings, interest, and capital gains, that the participant's contributions would have earned had we actually invested the money as the participant directed. The aggregate earnings on each
+individual's contribution varies widely depending on the portfolio of investments the participant chooses. We received investment direction from Mr. McCarvel and the aggregate earnings from
+those hypothetical investments are reflected in the table above. 
+25 
+Table of Contents 
+POTENTIAL PAYMENTS ON TERMINATIONS OR CHANGE IN CONTROL 
+Certain of our NEOs have employment agreements with us that provide for guaranteed payments upon a change in control or involuntary
+termination for other than "cause" (as described in each respective NEO's employment agreement). A summary of the potential payments that each of our NEOs would have received upon involuntary
+termination for other than "cause" or upon a change in control, assuming that each triggering event occurred on December 31, 2010 and the actual payments made upon the retirement of
+Mr. Duerden and the resignation of Mr. Hammer, follows: 
+Involuntary Termination for Other Than Cause 
+Change in Control 
+Severance 
+Bonus 
+Stock Options and 
+Awards Unvested 
+and Accelerated 
+Total 
+Stock Options and 
+Awards Unvested 
+and Accelerated 
+John P. McCarvel 
+$ 
+86,154 
+$ 
+640,000 
+$ 
+47,620 
+(1) 
+$ 
+773,774 
+$ 
+— 
+Daniel P. Hart(2) 
+855,000 
+380,000 
+3,132,472 
+(1) 
+4,367,472 
+3,132,472 
+(1) 
+John H. Duerden(3) 
+1,770,833 
+— 
+1,646,146 
+3,416,979 
+— 
+Russell C. Hammer(4) 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+(1) The
+calculation of the amount shown herein is based on the number of unvested shares at December 31, 2010 multiplied by the closing price of our
+common stock on the NASDAQ Global Select Market on December 31, 2010, less the exercise price for such stock options. Where the aggregate exercise price of the option was more than the market
+value of the underlying stock, those amounts have been excluded from the calculation of the net benefit shown above.
+(2) Pursuant
+to Mr. Hart's Agreement, the payments due to Mr. Hart upon an involuntary termination for other than cause would also be due upon
+Mr. Hart's resignation for "good reason" (as defined in Mr. Hart's Agreement).
+(3) Mr. Duerden
+retired from his position as President and Chief Executive Officer effective March 1, 2010. The amounts indicated in the table
+reflect actual payments made to Mr. Duerden pursuant to his Separation Agreement.
+(4) Mr. Hammer
+resigned as our Chief Financial Officer, Senior Vice President—Finance and Treasurer effective December 31, 2010. He
+received no payments in connection with his resignation. 
+REPORT OF THE AUDIT COMMITTEE 
+The Audit Committee has reviewed and discussed the audited financial statements for the fiscal year ended December 31, 2010 with
+our management and Deloitte & Touche LLP, our independent registered public accounting firm. Management is responsible for the preparation, presentation and integrity of the financial
+statements, accounting and financial reporting principles and internal control over financial reporting. Deloitte & Touche LLP is responsible for performing an independent audit of the
+financial statements in accordance with generally accepted auditing standards and for expressing opinions on the conformity of the financial statements with accounting principles generally accepted in
+the United States. 
+The
+Audit Committee has discussed with Deloitte & Touche LLP the matters required to be discussed by Statement on Auditing Standards No. 114, Communication With Those Charged With Governance , and PCAOB AU Section 380, Communications with Audit
+Committees , and has received the written disclosures and the letter from Deloitte & Touche LLP required by applicable requirements of the Public Company
+Accounting Oversight Board regarding the independent auditor's communications with the Audit Committee concerning independence. The Audit Committee has also discussed with Deloitte &
+Touche LLP their independence. 
+26 
+Table of Contents 
+Based
+on its reviews and discussions referred to above, the Audit Committee recommended to the Board that the audited financial statements be included in our Annual Report on
+Form 10-K for the year ended December 31, 2010 for filing with the SEC. 
+The
+Audit Committee: 
+Thomas
+J. Smach (Chairman) 
+Peter A. Jacobi 
+Ronald L. Frasch 
+INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+The following table sets forth the aggregate fees for professional services provided during 2010 and 2009 by Deloitte &
+Touche LLP, our independent registered public accounting firm and its affiliates. The Audit Committee is required to pre-approve all non-audit services provided by
+Deloitte & Touche LLP. All of the fees paid to Deloitte & Touche LLP and disclosed in the following table were pre-approved by the Audit Committee. 
+2010 
+2009 
+Audit fees(1) 
+$ 
+1,654,000 
+$ 
+1,648,901 
+Audit-related fees 
+— 
+— 
+Tax fees(2) 
+280,502 
+518,413 
+All other fees 
+— 
+— 
+Total fees 
+$ 
+1,934,502 
+$ 
+2,167,314 
+(1) Audit
+fees relate to professional services rendered in connection with the audit of our annual financial statements and internal controls over financial
+reporting, both of which are included in our Annual Report on Form 10-K and services attendant to, or required by, statute or regulation, such as: (i) comfort letters,
+consents and other audit services related to SEC and other regulatory filings; (ii) accounting consultation related to the audit; and (iii) statutory audit requirements in foreign
+countries.
+(2) Tax
+fees include professional services rendered in connection with tax compliance, tax advice, tax consulting and tax planning. 
+PROPOSAL 2—RATIFICATION OF THE APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+The Audit Committee has appointed Deloitte & Touche LLP as the independent registered public accounting firm for the
+fiscal year ending December 31, 2011. Deloitte & Touche LLP has served as our independent public accounting firm since 2005. We are not required to submit this appointment to the
+stockholders for approval, but the Board believes it is desirable as a matter of policy. We expect that a representative of Deloitte & Touche LLP will attend the Annual Meeting and will
+have the opportunity to make any statements if he or she so desires and to respond to appropriate stockholder questions. 
+If
+the stockholders do not ratify this appointment, the Audit Committee will investigate the reasons for the rejection and consider other independent registered public accounting firms.
+Even if the appointment is ratified, the Audit Committee may, in its discretion, appoint a different independent registered public accounting firm. 
+27 
+Table of Contents 
+THE BOARD RECOMMENDS A VOTE "FOR" THE RATIFICATION OF DELOITTE & TOUCHE LLP AS THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR FISCAL YEAR
+2011. 
+PROPOSAL 3—APPROVAL OF THE AMENDMENT AND RESTATEMENT OF THE 2007 EQUITY INCENTIVE PLAN 
+The Board has adopted, and is submitting to stockholders for approval, an Amended and Restated 2007 Equity Incentive Plan (the "Plan"). 
+Background and Reasons for Amending and Restating the Plan 
+The Board and the Compensation Committee believe that to enhance long-term stockholder value we need to maintain
+competitive employee compensation, incentive and retention programs. An equity stake in our success is a vital component of these programs. The proposed increase in the number of authorized shares
+under the Plan is intended to ensure that we have sufficient shares available to attract and retain employees and to further our growth and development. For a discussion of awards under the Plan as
+components of our executive compensation program, please refer to the "Compensation Discussion and Analysis" section above. 
+In
+addition, to address potential stockholder concerns regarding the number of equity awards we intend to grant in a given year, the Board determined it will take appropriate steps over
+the next three years (commencing with 2011) to control the granting of shares subject to equity awards under the Plan at an average rate not greater than 3.26% of the number of shares of our common
+stock that we believe will be outstanding over such three year period. The 3.26% equity burn rate is a guideline established by Institutional Shareholder Services, or ISS, for the Consumer Durables
+and Apparel sector for 2011. For purposes of calculating the number of shares granted in a year, any full-value awards will count as equivalent to 1.5 shares, as discussed below. 
+Highlights of the Proposed Plan 
+We are asking stockholders to approve the proposed Plan to: 
+• Increase the number of shares available for issuance pursuant to awards
+under the Plan. The Plan was initially approved by stockholders at the 2007 annual meeting of stockholders. As originally approved by
+stockholders, the Plan authorized the issuance of up to 9,000,000 shares of common stock pursuant to awards, adjusted for the 2-for-1 stock split that occurred on
+June 14, 2007, which was effected as a 100% common stock dividend on that date. The proposed Plan authorizes the issuance of up to an additional 6,300,000 shares. As of March 31, 2011,
+and excluding the requested share increase, there were approximately 1,573,635 shares remaining available for future grants of awards under the Plan. By increasing the number of shares authorized
+under the Plan, we believe we will have the flexibility to continue to provide equity incentives in amounts determined appropriate by the Compensation Committee over the next three to four years. If
+stockholders approve the Plan, as proposed, including the request for 6,300,000 additional shares, the total number of shares available for grant under the Plan, plus the number of shares subject to
+outstanding options under the Plan as of March 31, 2011, would be approximately 10,842,194 shares. As of March 31, 2011, the total number of shares of common stock outstanding was
+approximately 88,410,942. 
+Under
+the proposed Plan, shares granted as awards other than options or stock appreciation rights (restricted stock, restricted stock units and performance units, also known as "full value awards")
+will be counted against the overall Plan limit as 1.5 shares for every one share subject to such award, and shares granted under options or stock appreciation rights will be counted against the
+overall Plan limit on a one-for-one basis. This method of share counting replaces the 
+28 
+Table of Contents 
+current
+Plan provision limiting the aggregate number of shares that may be the subject of awards other than stock options and stock appreciation rights to 3,000,000 shares. 
+As
+of March 31, 2011 there are approximately 4,800,000 options outstanding with a weighted average exercise price of $9.48 and a weighted average remaining term of 6.49 years.
+Outstanding options include 1,800,000 shares from our 2005 Equity Incentive Plan, but no additional grants can be made from that plan. The Plan is the only equity plan under which options and awards
+can be granted. All restricted stock awards and restricted stock units currently outstanding (approximately 1,000,000 shares) have been granted under the Plan. 
+• Extend the term of the
+Plan. As approved by stockholders in 2007, the Plan has a termination date of July 9, 2017. The proposed Plan would extend the
+term of the Plan to June 28, 2021. 
+• Re-approve the material terms of performance goals for
+performance-based awards. In connection with approval of the Plan as proposed, our Board also is asking stockholders to
+re-approve the material terms of the performance goals for performance-based awards set forth in the Plan. This re-approval will provide us with the continued flexibility to
+grant awards under the Plan that qualify as "performance-based" compensation under Code Section 162(m). Code Section 162(m) generally provides that we are prohibited from deducting
+compensation paid to our principal executive officer and our three other most highly compensated executive officers (other than our principal financial officer) in excess of $1.0 million per
+person in any year. Compensation that qualifies as "performance-based" is excluded for purposes of calculating the amount of compensation subject to the $1.0 million limit. In general, one of
+the requirements that must be satisfied to qualify as "performance-based" compensation is that the material terms of the performance goals under which the compensation may be paid must be disclosed to
+and approved by a majority vote of our stockholders, generally at least once every five years. For purposes of Code Section 162(m), the material terms of the performance goals generally include
+(a) the individuals eligible to receive compensation upon achievement of performance goals, (b) a description of the business criteria on which the performance goals may be based and
+(c) the maximum amount that can be paid to an individual upon attainment of the performance goals. By approving the Plan as proposed, stockholders also will be re-approving the
+material terms of the performance goals under the Plan. 
+Highlights of Certain Current Provisions 
+The Plan continues to provide the following terms: 
+• all stock options must be issued at fair market value; as a result, the Plan prohibits discounted awards; 
+• repricing of stock options and stock appreciation rights is prohibited without stockholder approval; 
+• awards that are not subject to the satisfaction of performance measures, such as restricted stock awards and stock
+options, must have a minimum vesting period of three years, except in limited circumstances; 
+• awards that are subject to the satisfaction of performance measures, such as performance units, must have a performance
+period of at least one year; 
+• awards will generally terminate immediately if a Participant's employment is terminated for cause; 
+• shares tendered to us or retained by us in settlement of an award may not become available again for issuance under the
+Plan because we have prohibited liberal share counting provisions; and 
+29 
+Table of Contents 
+• the Compensation Committee administers the Plan. 
+Summary of the Plan 
+The Plan as proposed will be effective when approved by our stockholders at the Annual Meeting. A copy of the Plan is attached to this
+proxy statement as Appendix A , and this discussion is qualified in its entirety by reference to the full text of the Plan. 
+Purpose of the Plan 
+The purpose of the Plan is to promote our interests by aligning the interests of Participants in the Plan with those of our
+stockholders; to provide Participants with
+incentive to put forth maximum efforts for our continued growth and success; and to assist us in attracting, motivating and retaining the best available individuals. 
+Administration 
+The Plan will be administered by the Compensation Committee, which is composed of independent directors who are also
+"non-employee" directors for purposes of Section 16 of the Exchange Act and "outside directors" for purposes of Section 162(m) of the Code. The Compensation Committee has the
+authority to establish, amend and waive rules relating to the Plan and to determine the identity of Participants, the timing and amount of any awards and other terms and conditions of awards. The
+Compensation Committee may delegate to one or more of our officers the authority to grant awards under the Plan within specifically prescribed limits to employees who are not executive officers or
+directors. 
+Eligibility 
+All of our employees and those of our affiliates are eligible to receive awards under the Plan. As of December 31, 2010, we had
+approximately 4,000 employees. Awards other than incentive stock options (see "Types of Awards" below) also may be awarded by the Compensation Committee to individuals who are not employees but who
+provide services to us or our affiliates in the capacity of a non-employee director or an independent contractor. 
+Number of Shares Available for Issuance under the Plan 
+The total number of shares of our common stock available for distribution under the Plan is 15.3 million, subject to adjustment
+for future stock splits, stock dividends and similar changes in the our capitalization. Any shares of our common stock subject to an award under the Plan that is forfeited or expires or terminates
+unexercised or unearned, that is settled in cash or other property, or otherwise does not result in the issuance of shares of common stock, may again be used for an award under the Plan; provided that
+the gross number of shares with respect to which a stock appreciation right has been exercised may not again be awarded under the Plan if such exercise is settled in shares. 
+Any
+shares granted under options or stock appreciation rights will be counted against the overall Plan limit on a one-for-one basis and any shares granted as
+awards other than options or stock appreciation rights (restricted stock, restricted stock units and performance units) will be counted against this limit as 1.5 shares for every one share subject to
+such award. The closing sale price of a share of our common stock on the NASDAQ Global Select Market on April 29, 2011 was $20.11 per share. 
+Subject
+to adjustment for future stock splits, stock dividends and similar changes in the our capitalization, no Participant may receive awards of stock options, stock appreciation
+rights, restricted 
+30 
+Table of Contents 
+stock
+or restricted stock units relating to more than 1.0 million shares in any calendar year under the Plan. 
+Types of Awards 
+The types of awards that may be granted under the Plan include incentive and non-qualified stock options, stock
+appreciation rights, restricted stock, restricted stock units, performance units, and other stock-based awards. Subject to certain restrictions applicable to incentive stock options, awards will be
+exercisable by the recipients at such times as are determined by the Compensation Committee, but in no event may the term of an award be longer than ten years after the date of grant. 
+In
+addition to the general characteristics of all of the awards described in this proxy statement, the basic characteristics of awards that may be granted under the Plan are as follows: 
+Incentive and Non-Qualified Stock Options. Both incentive and non-qualified stock options may be granted to recipients at
+such exercise prices as the Compensation Committee may determine but not less than 100% of the fair market value of a share of our common stock as of the date the option is granted. We determine fair
+market value of our common stock based on the closing price of our common stock on the NASDAQ Global Select Market on the date of grant; however, if no sale of our stock occurs on that date, we will
+use the closing price on the next preceding date on which a sale of our stock occurred. Stock options may be granted and exercised at such times as the Compensation Committee may determine, except
+that the aggregate fair market value of the shares of our common stock with respect to which incentive stock options may first become exercisable in any calendar year for any employee may not exceed
+$100,000 under the Plan and
+any other plan we have in effect. Additional restrictions apply to an incentive stock option granted to an individual who beneficially owns more than 10% of the combined voting power of all classes of
+our stock. 
+The
+purchase price payable upon exercise of options may be paid in cash, or, if the Compensation Committee permits, by reducing the number of shares delivered to the Participant or by
+delivering stock already owned by the Participant (where the fair market value of the shares withheld or delivered on the date of exercise is equal to the option price of the stock being purchased),
+or in a combination of cash and such stock, unless otherwise provided in the related agreement. The Participants may also simultaneously exercise options and sell the stock purchased upon such
+exercise pursuant to brokerage or similar relationships and use the sale proceeds to pay the purchase price. 
+Stock Appreciation Rights. The value of a stock appreciation right granted to a recipient is determined by the appreciation in our
+common stock,
+subject to any limitations upon the amount or percentage of total appreciation that the Compensation Committee may determine at the time the right is granted. The recipient receives all or a portion
+of the amount by which the fair market value of a specified number of shares, as of the date the stock appreciation right is exercised, exceeds a base price specified by the Compensation Committee at
+the time the right is granted. The base price specified by the Compensation Committee must be at least 100% of the fair market value (determined as described above) of the specified number of shares
+of our common stock to which the right relates determined as of the date the stock appreciation right is granted. A stock appreciation right may be granted in connection with a previously or
+contemporaneously granted option, or independent of any option. 
+Performance Units. Performance units entitle the recipient to payment in amounts determined by the Compensation Committee based upon
+the achievement
+of specified performance measures during a specified term. With respect to recipients who are "covered employees" under Section 162(m) of the Code, the performance measures are set by the
+Compensation Committee at the start of each performance period and are based on one or a combination of two or more of the following performance criteria: net sales; net earnings; earnings before
+income taxes; earnings before interest and taxes; earnings before interest, taxes, depreciation and amortization; earnings per share (basic or 
+31 
+Table of Contents 
+diluted);
+profitability as measured by return ratios (including return on assets, return on equity, return on investment and return on net sales) or by the degree to which any of the foregoing
+earnings measures exceed a percentage of net sales; cash flow; market share; margins (including one or more of gross, operating and net earnings margins); stock price; total stockholder return; asset
+quality; non-performing assets; revenue growth; operating income; pre- or after-tax income; cash flow per share; operating assets; improvement in or attainment of
+expense levels or cost savings; economic value added; and improvement in or attainment of working capital levels. 
+Any
+performance measure utilized may be expressed in absolute amounts, on a per share basis, as a change from preceding performance periods, as a percentage of other criteria, or as a
+comparison to the performance of specified companies or other external measures, and may relate to corporate, group, unit, division, affiliate or individual performance. No Participant may receive
+awards of performance units relating to more than 1,000,000 shares in any year under the Plan. 
+Payments
+with respect to stock appreciation rights and performance units may be paid, as determined by the Compensation Committee, in cash, shares of our common stock, or a combination
+of cash and shares. 
+Restricted Stock, Restricted Stock Units and Other Stock-Based Awards. Our common stock granted to recipients may contain such
+restrictions as the
+Compensation Committee may determine, including provisions requiring forfeiture and imposing restrictions upon stock transfer. Awards of restricted stock may, in the discretion of the Compensation
+Committee, provide the Participant with dividends and voting rights prior to vesting. Restricted stock unit awards entitle the recipient to receive a number of shares of our common stock equal to the
+number of units awarded (or the fair market value of such shares in cash) following the lapse of any forfeiture conditions and the satisfaction of any performance measures that may be imposed by the
+Compensation Committee. The Compensation Committee may also from time to time grant awards of unrestricted stock or other stock-based awards such as awards denominated in stock units, securities
+convertible into stock, and phantom securities. 
+No Grants of Reload Options. The Plan prohibits the issuance of "reload" options, which involve the automatic grant of a new option when
+the payment
+of the exercise price of the original option, or the payment of tax withholdings, is made through the delivery to us of shares held by the option holder. 
+Acceleration of Awards, Lapse of Restrictions. Consistent with the terms of the Plan, the Compensation Committee may accelerate vesting
+requirements,
+performance periods, and the expiration of the applicable term or restrictions, and adjust performance targets and payments, upon such terms and conditions as are set forth in the Participant's award
+agreement, or otherwise in the Compensation Committee's discretion, which may include, without limitation, acceleration resulting from a "change of control" or a "fundamental change" (as those terms
+are defined in the Plan), or the Participant's death, disability, or retirement. 
+Duration, Adjustments, Modifications, Terminations. The Plan provides that all awards are subject to agreements containing the terms
+and conditions
+of the awards. Such agreements will be entered into by
+the recipients of the awards and us on or after the time the awards are granted and are subject to amendment, including unilateral amendment by the Compensation Committee, unless any such amendment is
+determined by the Compensation Committee to be materially adverse to the Participant and not required as a matter of law. No amendment shall reduce the exercise price of, or "reprice," any outstanding
+award, without stockholder approval. 
+The
+Plan will remain in effect until the tenth anniversary of its effectiveness, which will occur upon stockholder approval of the proposed Plan, or such earlier date on which the Plan
+is terminated. The Plan also gives the Board the right to amend, modify, terminate or suspend the Plan, except that amendments to the Plan are subject to stockholder approval if needed to comply with
+the NASDAQ rules. 
+32 
+Table of Contents 
+In the event of any "equity restructuring" within the meaning of FASB ASC Topic 718, such as a stock dividend or a stock split, the Plan requires the Compensation
+Committee to adjust the number and type of shares available for awards or subject to outstanding awards, and the exercise or strike price of such awards. In the event of any other change in corporate
+capitalization, which may include a merger or consolidation, the Compensation Committee has the discretion to make such equitable adjustments similar to those described above as it deems appropriate
+to prevent enlargement or diminution of Participants' rights. Adjustments in performance targets and payments on performance units are also permitted upon the occurrence of such events as may be
+specified in the related agreements, which may include a "change of control." Under the Plan, the Compensation Committee may cancel outstanding options and stock appreciation rights generally in
+exchange for cash payments to the recipients in the event of a "fundamental change" (defined as certain dissolutions, liquidations, mergers, consolidations or other similar events involving us). 
+U. S. Federal Income Tax Considerations 
+The following is a brief summary of the U.S. federal income tax consequences of the Plan generally applicable to us and to Participants
+in the Plan who are subject to U.S. federal taxes. The summary is based on the U.S. Internal Revenue Code of 1986, as amended, applicable Treasury Regulations and administrative and judicial
+interpretations thereof, each as in effect on the date of this proxy statement and is, therefore, subject to future changes in the law, possibly with
+retroactive effect. The summary is general in nature and does not purport to be legal or tax advice. Furthermore, the summary does not address issues relating to any U.S. gift or estate tax
+consequences or the consequences of any state, local or foreign tax laws. 
+Nonqualified Stock Options. A Participant generally will not recognize taxable income upon the grant or vesting of a nonqualified stock
+option with
+an exercise price at least equal to the fair market value of the common stock on the date of grant and no additional deferral feature. When a nonqualified stock option is exercised, a Participant
+generally will recognize compensation taxable as ordinary income in an amount equal to the difference between the fair market value of the shares underlying the option on the date of exercise and the
+option exercise price. When a Participant sells the shares, the Participant will have short-term or long-term capital gain or loss, as the case may be, equal to the difference
+between the amount the Participant received from the sale and the tax basis of the shares sold. The tax basis of the shares generally will be equal to the greater of the fair market value of the
+shares on the exercise date or the option exercise price. 
+Incentive Stock Options. A Participant generally will not recognize taxable income upon the grant of an incentive stock option. If a
+Participant
+exercises an incentive stock option during employment as an employee or within three months after his or her employment ends (12 months in the case of permanent and total disability), the
+Participant will not recognize taxable income at the time of exercise for regular U.S. federal income tax purposes (although the Participant generally will have taxable income for alternative minimum
+tax purposes at that time as if the option were a nonqualified stock option). If a Participant sells or otherwise disposes of the shares acquired upon exercise of an incentive stock option after the
+later of (a) one year from the date the Participant exercised the option and (b) two years from the grant date of the option, the Participant generally will recognize
+long-term capital gain or loss equal to the difference between the amount the Participant received in the disposition and the option exercise price. If a Participant sells or otherwise
+disposes of shares acquired upon exercise of an incentive stock option before these holding period requirements are satisfied, the disposition will constitute a "disqualifying disposition," and the
+Participant generally will recognize taxable ordinary income in the year of disposition equal to the excess of the fair market value of the shares on the date of exercise over the option exercise
+price (or, if less, the excess of the amount realized on the disposition of the shares over the option exercise price). The balance of the 
+33 
+Table of Contents 
+Participant's
+gain on a disqualifying disposition, if any, will be taxed as short-term or long-term capital gain, as the case may be. 
+With
+respect to both nonqualified stock options and incentive stock options, special rules apply if a Participant uses shares of common stock already held by the Participant to pay the
+exercise price. 
+Stock Appreciation Rights. A Participant generally will not recognize taxable income upon the grant or vesting of an SAR with a grant
+price at least
+equal to the fair market value of the common stock on the date of grant and no additional deferral feature. Upon the exercise of an SAR, a Participant generally will recognize compensation taxable as
+ordinary income in an amount equal to the difference between the fair market value of the shares underlying the SAR on the date of exercise and the grant price of the SAR. 
+Unrestricted Stock Awards. Upon receipt of an unrestricted stock award, a Participant generally will recognize compensation taxable as
+ordinary
+income in an amount equal to the excess of the fair market value of the shares at such time over the amount, if any, paid by the Participant with respect to the shares. 
+Restricted Stock Awards, Stock Units, Performance Shares and Performance Units. A Participant generally will not have taxable income
+upon the grant
+of restricted stock, stock units, performance shares or performance units. Instead, the Participant will recognize ordinary income at the time of vesting or payout equal to the fair market value (on
+the vesting or payout date) of the shares or cash received minus any amount paid. For restricted stock only, a Participant may instead elect to be taxed at the time of grant. 
+Tax Consequences to Us. In the foregoing cases, we generally will be entitled to a deduction at the same time, and in the same amount,
+as a
+Participant recognizes ordinary income, subject to certain limitations imposed under the Code. 
+Code Section 409A. We intend that awards granted under the Plan comply with, or otherwise be exempt from, Code Section 409A,
+but make
+no representation or warranty to that effect. 
+Tax Withholding. We are authorized to deduct or withhold from any award granted or payment due under the Plan, or require a Participant
+to remit to
+us, the amount of any withholding taxes due in respect of the award or payment and to take such other action as may be necessary to satisfy all obligations for the payment of applicable withholding
+taxes. We are not required to issue any shares of
+common stock or otherwise settle an award under the Plan until all tax withholding obligations are satisfied. 
+Plan Benefits 
+All awards to employees, officers and consultants under the Plan are made at the discretion of the Compensation Committee. Therefore,
+the benefits and amounts that will be received or allocated to such individuals under the Plan are not determinable at this time. However, please refer to the description of grants made to our named
+executive officers in the last fiscal year described in the "2010 Grants of Plan-Based Awards" table above. Grants made to our non-employee directors in the last fiscal year
+are described under "Director Compensation" above. 
+The
+approval of the Plan requires the affirmative vote of the majority of shares present in person or represented by proxy at the meeting and entitled to vote on the proposal. 
+THE BOARD RECOMMENDS A VOTE "FOR" THE APPROVAL OF THE AMENDMENT AND RESTATEMENT OF THE 2007 EQUITY INCENTIVE PLAN 
+34 
+Table of Contents 
+PROPOSAL 4—ADVISORY VOTE ON THE COMPENSATION OF OUR NAMED 
+EXECUTIVE OFFICERS 
+The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, or the Dodd-Frank Act, gives
+stockholders an opportunity to cast an advisory vote on compensation of our named executive officers as disclosed in this proxy statement. This proposal, commonly known as a "Say on Pay" proposal,
+gives stockholders the opportunity to approve or reject our executive pay program through the following resolution: 
+"RESOLVED,
+that the stockholders approve, on an advisory basis, the compensation of our named executive officers, as disclosed in the Compensation Discussion and Analysis, the compensation tables and
+any other related disclosure in this proxy statement." 
+As
+discussed in the "Compensation Discussion and Analysis," the primary objective of our executive compensation program is to create long-term value for our stockholders by
+attracting and retaining talented executives, rewarding superior operating and financial performance and aligning the long-term interests of our executives with those of our stockholders.
+We believe our executive compensation strikes the appropriate balance between utilizing responsible, measured pay practices and effectively incentivizing our named executive officers to dedicate
+themselves fully to value creation for our stockholders. Please see "Compensation Discussion and Analysis" section above for an explanation of our executive compensation. 
+This
+"Say on Pay" proposal allows our stockholders to express their view regarding the decisions of the Compensation Committee on the 2010 compensation of our named executive officers.
+Your advisory vote will serve as a tool to guide the Board and the Compensation Committee in continuing to improve the alignment of our executive compensation programs with the objective of creating
+long-term value for our stockholders. 
+THE BOARD RECOMMENDS A VOTE "FOR" THE COMPENSATION OF OUR NAMED EXECUTIVES. 
+PROPOSAL 5—ADVISORY VOTE ON THE FREQUENCY OF STOCKHOLDER VOTES ON THE 
+COMPENSATION OF OUR NAMED EXECUTIVE OFFICERS 
+Stockholders have an opportunity to cast an advisory vote on how frequently we should seek an advisory vote on the compensation of our
+named executive officers. Stockholders may indicate whether they would prefer an advisory vote on executive compensation once every one, two or three years or they may abstain from voting. 
+Our
+executive compensation program is designed to create long-term value for our stockholders, and a triennial vote will allow stockholders to better judge our executive
+compensation program in relation to our long-term performance. As described in the "Compensation Discussion and Analysis" section above, equity awards are a significant component of our
+executive compensation program. We grant equity awards with multi-year performance and service periods to encourage our executive officers to focus on long-term performance. A
+triennial vote would allow our executive compensation programs to be evaluated over a similar time frame and in relation to our long-term performance. 
+We
+also believe that a vote every three years is an appropriate frequency to provide sufficient time to thoughtfully consider stockholders' input and to implement any appropriate changes
+to our executive compensation program, in light of the timing that would be required to implement any decisions related to such changes. In addition, many large stockholders rely on proxy advisory
+firms for vote recommendations. We believe holding a triennial vote will help proxy advisory firms provide more detailed and thorough analyses and recommendations. 
+35 
+Table of Contents 
+The
+voting frequency option that receives the highest number of votes cast by stockholders will be deemed the frequency for the advisory vote on executive compensation that has been
+selected by stockholders. Although the vote is non-binding, the Board will commit to the outcome of the vote when making future decisions about the frequency of
+votes on the compensation of our named executive officers. 
+THE BOARD RECOMMENDS A VOTE "FOR" A FREQUENCY PERIOD OF EVERY THREE YEARS FOR FUTURE ADVISORY VOTES ON NAMED
+EXECUTIVE OFFICER COMPENSATION. 
+OTHER MATTERS 
+We do not intend to bring before the Annual Meeting any matters other than the proposals specifically described above, and we know of
+no matters other than those to come before the Annual Meeting. If any other matters properly come before the Annual Meeting, it is the intention of the persons named in the accompanying proxy to vote
+such proxy in accordance with the recommendation of our management on such matters, including any matters dealing with the conduct of the Annual Meeting. 
+STOCKHOLDER PROPOSALS AND NOMINATIONS FOR 2012 ANNUAL MEETING 
+Any proposal of a stockholder intended to be included in our proxy statement for the 2012 annual meeting of stockholders pursuant to
+SEC Rule 14a-8, must
+be received by us no later than December 31, 2011, unless the date of our 2012 Annual Meeting is more than 30 days before or after June 28, 2012, in which case the proposal must
+be received a reasonable time before we begin to print and mail our proxy materials. All proposals should be addressed to the Corporate Secretary, Crocs, Inc., 6328 Monarch Park Place, Niwot,
+Colorado 80503. 
+In
+order for a stockholder to nominate a candidate for director for election or to bring other business before the 2012 annual meeting, we must receive timely notice of the nomination or
+business in writing by the close of business not later than March 30, 2012 nor earlier than February 29, 2012. However, in the event that the 2012 annual meeting is called for a date
+that is not within 30 days before or 60 days after June 28, 2012, notice by the stockholder to be timely must be delivered not earlier than the close of business on the
+120th day prior to such annual meeting and not later than the close of business on the later of the 90th day prior to such annual meeting or the 10th day following the date on
+which public announcement of the date of the 2012 annual meeting is made. 
+36 
+Table of Contents 
+APPENDIX A 
+CROCS, INC. 
+2007 EQUITY INCENTIVE PLAN 
+(As
+Amended and Restated) 
+1. Purpose. The purpose of the Crocs, Inc. 2007 Equity Incentive Plan (the "Plan") is to promote the
+interests of the Company and its stockholders by aligning the interests of employees and others who are selected to be Participants with those of the Company's stockholders, providing Participants
+with a strong incentive to put forth maximum effort for the continued success and growth of the Company
+and its Affiliates, and assisting the Company in attracting, motivating and retaining the best available individuals for service to the Company. 
+2. Definitions. The capitalized terms used in the Plan have the meanings set forth below. 
+(a) "Acquired
+Entity" means any entity acquired by the Company or an Affiliate or with which the Company or an Affiliate merges or combines. 
+(b) "Affiliate"
+means any entity that is directly or indirectly controlled by, in control of or under common control with the Company. Notwithstanding the foregoing, for
+purposes of determining whether any individual may be a Participant for purposes of any grant of Incentive Stock Options, the term "Affiliate" shall mean any corporation that is a "subsidiary
+corporation" of the Company, as that term is defined in Code Sections 424(e) and (f), or any successor provisions. 
+(c) "Agreement"
+means any written or electronic agreement, instrument or document evidencing the grant of an Award in such form as has been approved by the Committee,
+including all amendments thereto. 
+(d) "Award"
+means a grant made under the Plan in the form of Restricted Stock, Restricted Stock Units, Options, Stock Appreciation Rights, Performance Units, Stock or any
+other stock-based award. 
+(e) "Board"
+means the Board of Directors of the Company. 
+(f) "Cause"
+means (i) the Participant's material breach of any confidentiality, non-disclosure, non-solicitation, non-competition,
+invention assignment or similar agreement with the Company or any Affiliate; (ii) an act or acts of dishonesty undertaken by the Participant resulting in gain or personal enrichment of the
+Participant at the expense of the Company; (iii) persistent failure by the Participant to perform the duties of the Participant's employment, which failure is demonstrably deliberate on the
+part of the Participant and constitutes gross neglect of duties by the Participant; (iv) any failure by the Participant to materially conform to the Company's Code of Business Conduct and
+Ethics; or (v) the indictment or conviction of the Participant for a felony if the act or acts constituting the felony are substantially detrimental to the Company or its reputation. 
+(g) "Change
+of Control" means one of the following: 
+(1) a
+majority of the directors of the Company shall be persons other than persons 
+(i) for
+whose election proxies shall have been solicited by the Board, or 
+(ii) who
+are then serving as directors appointed by the Board to fill vacancies on the Board caused by death or resignation (but not by removal) or to fill newly created
+directorships; 
+(2) 35%
+or more of (1) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors
+("Outstanding 
+37 
+Table of Contents 
+Company
+Voting Securities") or (2) the then outstanding Shares of Stock ("Outstanding Company Common Stock") is acquired or beneficially owned (as defined in Rule 13d-3 under
+the Exchange Act, or any successor rule thereto) by any individual, entity or group (within the meaning of Section 13d(3) or 14(d)(2) of the Exchange Act), provided, however, that the following
+acquisitions and beneficial ownership shall not constitute Changes of Control pursuant to this Section 2(f)(2): 
+(i) any
+acquisition or beneficial ownership by the Company or a subsidiary of the Company, or 
+(ii) any
+acquisition or beneficial ownership by any employee benefit plan (or related trust) sponsored or maintained by the Company or one or more of its subsidiaries, or 
+(iii) any
+acquisition or beneficial ownership by a parent entity of the Company (after giving effect to the merger) or its wholly-owned subsidiaries, as long as they shall
+remain wholly-owned subsidiaries, directly or indirectly of 100% of the Outstanding Company Voting Securities as a result of a merger or that complies with Section 2(f)(3)(i)(A), (B) and
+(C) or the exception in Section 2(f)(3)(ii) in all respects; 
+(3) the
+Company consummates 
+(i) a
+merger of the Company with or into another entity, other than a merger in which: 
+(A) the
+persons who were the beneficial owners, respectively, of the Outstanding Company Voting Securities and Outstanding Company Common Stock immediately prior to such
+merger beneficially
+own, directly or indirectly, immediately after the merger, more than 50% of, respectively, the then outstanding common stock and the then outstanding voting power of the voting securities (or
+comparable equity interests) of the surviving entity in the merger or its direct or indirect parent entity in substantially the same proportions (except for those exercising statutory dissenters'
+rights) as their ownership of the Outstanding Company Voting Securities and Outstanding Company Common Stock immediately prior to the merger, 
+(B) if
+voting securities of the direct or indirect parent entity of the Company (after giving effect to the merger) are exchanged for Outstanding Company Voting Securities
+in the merger, all holders of any class or series of Outstanding Company Voting Securities immediately prior to the merger have the right to receive substantially the same per share consideration in
+exchange for their Outstanding Company Voting Securities as all other holders of such class or series (except for those exercising statutory dissenters' rights), and 
+(C) no
+individual, entity or group (other than a direct or indirect, parent entity that, after giving effect to the merger, directly or indirectly through one or more wholly
+owned subsidiaries, beneficially owns 100% of the outstanding voting securities of the entity resulting from the merger) beneficially owns, directly or indirectly, immediately after the merger, 35% or
+more of the voting power of the outstanding voting securities or the outstanding common stock of the entity (or comparable equity interests) resulting from the merger, or 
+(ii) a
+sale or other disposition of all or substantially all of the assets of the Company (in one transaction or a series of transactions); or 
+38 
+Table of Contents 
+(4) the
+stockholders of the Company approve a definitive agreement or plan to liquidate or dissolve the Company. 
+Notwithstanding
+anything herein stated, no Change of Control shall be deemed to occur unless it would be deemed to constitute a change in ownership or effective control, or a change in the ownership
+of a substantial portion of the assets, of a business under Section 409A. 
+(h) "Code"
+means the Internal Revenue Code of 1986, as amended and in effect from time to time or any successor statute, and the regulations promulgated thereunder. 
+(i) "Committee"
+means two or more Non-Employee Directors designated by the Board to administer the Plan under Section 3.1, each member of which shall be
+(i) an independent director within the meaning of Rule 4200(15) of the Nasdaq Marketplace Rules, (ii) considered a non-employee director within the meaning of Exchange
+Act Rule 16b-3, and (iii) an outside director for purposes of Code Section 162(m). 
+(j) "Company"
+means Crocs, Inc., a Delaware corporation, or any successor to all or substantially all of its businesses by merger, consolidation, purchase of assets
+or otherwise. 
+(k) "Disability"
+means the disability of a Participant such that the Participant is considered disabled under any retirement plan of the Company which is qualified under
+Section 401 of the Code, or as otherwise determined by the Committee. 
+(l) "Employee"
+means an employee (including an officer or director who is also an employee) of the Company or an Affiliate. 
+(m) "Exchange
+Act" means the Securities Exchange Act of 1934, as amended and in effect from time to time or any successor statute. 
+(n) "Fair
+Market Value" as of any date means, unless otherwise expressly provided in the Plan, the closing sale price of a Share on the Nasdaq Global Select Market (or such
+other national securities exchange as may at the time be the principal market for the Shares) on that date or, if no sale of the Company's Shares occurred on that date, on the next preceding day on
+which a sale of Shares occurred. If the Shares are not then listed and traded upon the Nasdaq Global Select Market or other national securities exchange, Fair Market Value shall be what the Committee
+determines in good faith to be 100% of the fair market value of a Share on that date, using such criteria as it shall determine, in its sole discretion, to be appropriate for valuation. 
+(o) "Fundamental
+Change" means a dissolution or liquidation of the Company, a sale of substantially all of the assets of the Company, or a merger or consolidation of the
+Company with or into any other corporation, regardless of whether the Company is the surviving corporation. 
+(p) "Grant
+Date" means the date on which the Committee approves the grant of an Award under the Plan, or such later date as may be specified by the Committee on the date the
+Committee approves the Award. 
+(q) "Incentive
+Stock Option" means any Option designated as such and granted in accordance with the requirements of Code Section 422. 
+(r) "Insider"
+as of a particular date means any person who, as of that date is an officer of the Company as defined under Exchange Act Rule 16a-1(f). 
+(s) "Non-Employee
+Director" means a member of the Board who is not an Employee. 
+(t) "Non-Statutory
+Stock Option" means an Option other than an Incentive Stock Option. 
+(u) "Option"
+means a right to purchase a number of Shares at a specified price. 
+39 
+Table of Contents 
+(v) "Participant"
+means a person to whom an Award is or has been made in accordance with the Plan. 
+(w) "Performance-Based
+Compensation" means an Award to a "covered employee" (as defined in Section 162(m)(3) of the Code) that is intended to constitute
+"performance-based compensation" within the meaning of Section 162(m)(4)(c) of the Code. 
+(x) "Performance
+Period" means the period of time as specified in an Agreement over which Performance Units or any other Award subject to Performance Measures are to be
+earned. 
+(y) "Performance
+Measures" means any measures of performance established by the Committee in connection with the grant of an Award. In the case of any such grant intended to
+constitute Performance-Based Compensation, the Performance Measures shall consist of one or a combination of two or more of the following performance criteria: net sales; net earnings; earnings before
+income taxes; earnings before interest and taxes; earnings before interest, taxes, depreciation and amortization; earnings per share (basic or diluted); profitability as measured by return ratios
+(including return on assets, return on equity, return on investment and return on net sales) or by the degree to which any of the foregoing earnings measures exceed a percentage of net sales; cash
+flow; market share; margins (including one or more of gross, operating and net earnings margins); stock price; total stockholder return; asset quality; non-performing assets; revenue
+growth; operating income; pre- or after-tax income; cash flow per share; operating assets; improvement in or attainment of expense levels or cost savings; economic value added;
+and improvement in or attainment of working capital levels. Any Performance Measure utilized may be expressed in absolute amounts, on a per share basis, as a growth rate or change from preceding
+periods, or as a comparison to the performance of specified companies or other external measures, and may relate to one or any combination of corporate, group, unit, division, Affiliate or individual
+performance. 
+(z) "Performance
+Unit" means the right to receive the Fair Market Value of one Share upon the achievement of specified levels of one or more Performance Measures in
+accordance with an Award granted under Section 11. 
+(aa) "Plan"
+means this Crocs, Inc. 2007 Equity Incentive Plan, as amended and in effect from time to time. 
+(bb) "Restricted
+Stock" means Shares issued in accordance with an Award granted under Section 7 so long as the retention and/or vesting of such Shares remains subject
+to conditions or restrictions. 
+(cc) "Restricted
+Stock Unit" means a derivative security provided in accordance with an Award granted under Section 8 which represents the right to receive, in cash
+and/or Stock as determined by the Committee, the Fair Market Value of one Share, and the retention, vesting and/or settlement of which is subject to conditions or restrictions. 
+(dd) "Retirement"
+means termination of an Employee's employment, other than for Cause, at or after age 65. 
+(ee) "Section 409A"
+means Section 409A of the Code, including any regulations and other guidance issued thereunder by the Department of the Treasury and/or the
+Internal Revenue Service. 
+(ff) "Share"
+means a share of Stock. 
+(gg) "Stock"
+means the common stock, no par value, of the Company. 
+(hh) "Stock
+Appreciation Right" means a right, the value of which is determined in relation to the appreciation in value of Shares in accordance with an Award granted under
+Section 10. 
+40 
+Table of Contents 
+(ii) "Subsidiary"
+means a "subsidiary corporation" as that term is defined in Code Section 424(f) or any successor provision. 
+(jj) "Substitute
+Award" means Awards granted or shares of Common Stock issued by the Company in assumption of, or in substitution or exchange for, awards previously granted
+by an Acquired Entity. 
+(kk) "Successor"
+means the legal representative of an incompetent Participant, or if the Participant is deceased means the estate of the Participant or the person or persons
+who may, by bequest or inheritance, or pursuant to the terms of an Award, acquire the right to exercise an Option or Stock Appreciation Right or to receive cash and/or Shares issuable in satisfaction
+of an Award in the event of the Participant's death. 
+(ll) "Transferee"
+means any "family member" (as defined by the general instructions to Form S-8 under the Securities Act of 1933) of the Participant. 
+3. Administration and Indemnification. 
+(a) Administration. 
+(1) The
+Committee shall administer the Plan. The Committee shall have exclusive power to (i) make Awards; (ii) determine when and to whom Awards will be
+granted, the form of each Award, the amount of each Award, and any other terms or conditions of each Award consistent with the Plan; (iii) prescribe and amend the terms of Agreements evidencing
+Awards; and (iv) determine whether, to what extent and under what circumstances, Awards may be settled, paid or exercised in cash, Shares or other Awards, or other property or canceled,
+forfeited or suspended. A majority of the members of the Committee shall constitute a quorum for any meeting of the Committee, and acts of a majority of the members present at any meeting at which a
+quorum is present or the acts unanimously approved in writing by all members of the Committee shall be the acts of the Committee. Notwithstanding the foregoing, the Board shall perform the duties and
+have the responsibilities of the Committee with respect to Awards made to Non-Employee Directors. 
+(2) Notwithstanding
+the foregoing, the Board or the Compensation Committee may delegate concurrent responsibility for administering the Plan, including with respect to
+designated classes of Participants, to different committees consisting of one or more members of the Board, subject to such limitations as the Board deems appropriate, except with respect to Awards to
+Participants who are subject to Section 16 of the Exchange Act or Awards intended to constitute Performance-Based Compensation. Members of any committee shall serve for such term as the Board
+may determine, subject to removal by the Board at any time. To the extent consistent with applicable law, the Board or the Compensation Committee may authorize one or more officers of the Company to
+grant Awards to designated classes of Participants, within limits specifically prescribed by the Board or the Compensation Committee;
+provided, however, that no such officer shall have or obtain authority to grant Awards to himself or herself or to any person subject to Section 16 of the Exchange Act. . 
+(3) To
+the extent within its discretion and subject to Sections 16 and 17, the Committee may amend the terms and conditions of any outstanding Award. 
+(4) It
+is the intent that the Plan and all Awards granted pursuant to it shall be administered by the Committee so as to permit the Plan and Awards to comply with Exchange
+Act Rule 16b-3 for persons subject to Section 16, except in such instances as the Committee, in its discretion, may so provide. 
+(5) The
+Committee's interpretation of the Plan and of any Award or Agreement made under the Plan and all related decisions or resolutions of the Board or Committee shall be 
+41 
+Table of Contents 
+final
+and binding on all parties with an interest therein. Consistent with its terms, the Committee shall have the power to establish, amend or waive regulations to administer the Plan. In carrying
+out any of its responsibilities, the Committee shall have discretionary authority to construe the terms of the Plan and any Award or Agreement made under the Plan. 
+(6) In
+order to facilitate compliance with the applicable provisions of the laws in other countries in which the Company or its Affiliates operate or have Employees or
+non-employee consultants and advisors, and notwithstanding any other provision of this Plan, the Committee shall have the power and authority to (i) determine which (if any)
+individuals rendering services or employed outside the United States are eligible to participate in the Plan or to receive any type of Award hereunder; (ii) determine which
+non-U.S.-based Affiliates or operations may participate in the Plan; (iii) modify the terms and conditions of any Awards made to such individuals or with respect to such
+non-U.S.-based Affiliates or operations; and (iv) establish sub-plans, modify methods of exercise, modify payment restrictions on sale or transfer of Shares and other
+terms and procedures to the extent deemed necessary or desirable by the Committee to comply with applicable laws of the non-U.S. jurisdiction. 
+(b) Indemnification. Each person who is or shall have been a member of the Committee, or of the Board, and any
+other person to whom the Committee delegates authority under the Plan, shall be indemnified and held harmless by the Company, to the extent permitted by law, against and from any loss, cost, liability
+or expense that may be imposed upon or reasonably incurred by such person in connection with or resulting from any claim, action, suit or proceeding to which such person may be a party or in which
+such person may be involved by reason of any action taken or failure to act, made in good faith, under the Plan and against and from any and all amounts paid by such person in settlement thereof, with
+the Company's approval, or paid by such person in satisfaction of any judgment in any such action, suit or proceeding against such person, provided such person shall give the Company an
+opportunity, at the Company's expense, to handle and defend the same before such person undertakes to handle and defend it on such person's own behalf. The foregoing right of indemnification shall not
+be exclusive of any other rights of indemnification to which such person or persons may be entitled under the Company's Certificate of Incorporation or Bylaws, as a matter of law, or otherwise, or any
+power that the Company may have to indemnify them or hold them harmless. 
+4. Shares Available Under the Plan. 
+(a) Subject
+to adjustment pursuant to Section 17, the number of Shares that may be granted under the Plan shall not exceed 15,300,000. The aggregate number of Shares
+available for issuance under the Plan will be reduced (i) by 1.5 Shares for each Share delivered in settlement of any Award of Restricted Stock, Restricted Stock Units, Performance Units, Stock
+or any other stock-based Award other than Options or Stock Appreciate Rights and (ii) by one Share for each Share delivered upon the exercise and settlement of Options or Stock Appreciation
+Rights. The Shares issued under the Plan may come from authorized and unissued shares or treasury shares. 
+(b) Any
+Shares subject to that portion of an Award which, for any reason, is forfeited or expires or terminates unexercised or unearned may again be used for future Awards. 
+(c) Any
+Shares subject to an Award settled in cash or other property in lieu of Shares may again be used for future Awards. 
+(d) For
+the purposes of computing the total number of Shares granted under the Plan, the following rules shall apply to Awards payable in Shares where appropriate: 
+(1) Each
+Award shall initially be deemed to involve the grant of the maximum number of Shares in which the particular Award is denominated. 
+42 
+Table of Contents 
+(2) If
+a Stock Appreciation Right has been exercised and settled in Shares, the gross number of Shares with respect to which such exercise occurred shall be deemed granted
+and may not again be the subject of Awards under the Plan. 
+(3) To
+the extent an Award is paid or settled in some other security, it shall be deemed to have involved the grant of the number of Shares in which that portion of the
+Award was denominated. 
+(4) Where
+the number of Shares available under the Award is variable on the Grant Date, the number of Shares granted shall be deemed, prior to the settlement of the Award,
+to be the maximum number of Shares that could be received under that particular Award. 
+(5) Where
+two or more types of Awards (all of which are payable in Shares) are granted to a Participant in tandem with each other, such that the exercise of one type of
+Award with respect to a number of Shares cancels at least an equal number of Shares of the other, such joint Awards shall be deemed to involve the grant of the maximum number of Shares available under
+the largest single Award. 
+(6) Shares
+tendered or withheld in payment of an Option exercise price or to satisfy any tax withholding obligation shall not be added to the total number of Shares
+available for grant under the Plan. 
+(7) Shares
+that are repurchased by the Company with Option proceeds shall not be added to the total number of Shares available for grant under the Plan. 
+(e) No
+fractional Shares may be issued under the Plan; however, cash shall be paid in lieu of any fractional Share in settlement of an Award. 
+(f) The
+maximum number of Shares that may be issued pursuant to Incentive Stock Options shall be 15,300,000, which limit will be subject to adjustment under
+Section 17 to the extent such adjustment is consistent with adjustments permitted of a plan authorizing the grant of incentive stock options under Code Section 422. The aggregate number
+of Shares subject to Options and/or Stock Appreciation Rights granted during any calendar year to any one Participant shall not exceed 1,000,000. The aggregate number of Shares subject to Restricted
+Stock and/or Restricted Stock Unit Awards granted during any calendar year to any one Participant shall not exceed 1,000,000. The foregoing limits shall be subject to adjustment under
+Section 17, but only to the extent that such adjustment will not affect the status of any Award intended to qualify as performance-based compensation under Code Section 162(m). 
+5. Eligibility. Participation in the Plan shall be limited to (i) Employees, (ii) individuals who
+are not Employees but who provide services to the Company or an Affiliate, including services provided in the capacity of a consultant, advisor or director, such as a Non-Employee
+Director, and (iii) any individual the Company desires to induce to become an Employee or Non-Employee Director, provided that any such grant shall not be effective until such
+individual becomes an Employee or Non-Employee Director, as the case may be. The granting of Awards is solely at the discretion of the Committee, except that Incentive Stock Options
+may only be granted to Employees. References herein to "employed," "employment" or similar terms (except "Employee") shall include the providing of services in any capacity, including as a director.
+Neither the transfer of employment of a Participant between any of the Company or its Affiliates, nor a leave of absence granted to such Participant and approved by the Committee, nor any change in
+status from an Employee to a consultant of the Company shall be deemed a termination of employment for purposes of the Plan. 
+6. General Terms of Awards. 
+(a) Amount of Award. Each Award shall be evidenced by an Agreement setting forth the number of Shares subject to
+the Award together with such other terms and conditions applicable 
+43 
+Table of Contents 
+to
+the Award (and not inconsistent with the Plan) as determined by the Committee, which may include conditions on vesting, exercisability, lapsing of restrictions or payment that are tied to
+Performance Measures. 
+(b) Vesting and Term. Each Agreement, other than those relating solely to Awards of Shares without restrictions,
+shall set forth the period until the applicable Award is scheduled to expire, which shall not be more than ten years from the Grant Date, and any applicable Performance Period. The Committee may
+provide for such vesting conditions as it may determine, subject to the following limitations: 
+(1) an
+Award that is not subject to the satisfaction of Performance Measures may not fully vest or become fully exercisable earlier than three years from the Grant Date; and 
+(2) the
+Performance Period of a Performance Unit or other Award subject to Performance Measures may not be shorter than one year. 
+The
+limitations in clauses (1) and (2) above will not, however, apply in the following situations: (i) an Award made to attract a key executive to join the Company;
+(ii) upon a Change of Control; (iii) termination of employment due to death, Disability or Retirement; (iv) Restricted Stock or Restricted Stock Units issued in exchange for other
+compensation; (v) a substitute Award granted pursuant to Section 20; and (vi) Awards issued to Non-Employee Directors. 
+(c) Transferability. Except as provided in this Section, (i) during the lifetime of a Participant, only
+that Participant (or that Participant's Successor) may exercise an Option or Stock Appreciation Right, or receive payment with respect to any other Award, and (ii) no Award may be sold,
+assigned, transferred,
+exchanged or otherwise encumbered other than to a Successor in the event of a Participant's death or pursuant to a qualified domestic relations order as defined in the Code or Title 1 of the Employee
+Retirement Income Security Act of 1974, as amended ("ERISA"), or the rules thereunder. Any attempted transfer in violation of this Section 6(c) shall be of no effect. The Committee may,
+however, provide in an Agreement or otherwise that an Award (other than an Incentive Stock Option) may be transferable, to the extent permitted by law, to a Transferee if the Participant does not
+receive any consideration for the transfer. Any Award held by a Transferee shall continue to be subject to the same terms and conditions that were applicable to that Award immediately before the
+transfer thereof to the Transferee. For purposes of any provision of the Plan relating to notice to a Participant or to acceleration or termination of an Award upon the death or termination of
+employment of a Participant, the references to "Participant" shall mean the original grantee of an Award and not any Transferee. 
+(d) Termination of Employment. Except as otherwise determined by the Committee or provided by the Committee in
+an Agreement, in case of a Participant's termination of employment with the Company and all of its Affiliates, the following provisions shall apply: 
+(1) Options and Stock Appreciation Rights. 
+(i) Death or Disability. If a Participant's employment terminates because of death or Disability before an
+Award of an Option or Stock Appreciation Right has expired, the portion of such Award that was exercisable immediately prior to such termination shall remain exercisable for one year after the date of
+such termination of employment (but not after the scheduled expiration date of such Award). The unexercisable portion of such Award shall terminate at the date of termination of employment. 
+(ii) Retirement. If the employment of a Participant who is an Employee terminates because of Retirement before
+an Award of an Option or Stock Appreciation Right has expired, the portion of such Award that was exercisable immediately prior to such termination shall remain exercisable for one year after the date
+of such termination of 
+44 
+Table of Contents 
+employment
+(but not after the scheduled expiration date of such Award). The unexercisable portion of such Award shall terminate at the date of termination of employment. 
+(iii) Cause. If a Participant's employment is terminated for Cause, all Awards to the Participant will terminate
+immediately upon such termination. 
+(iv) Termination for Other Reasons. If a Participant's employment terminates for any reason other than death,
+Disability, Retirement or Cause, then the unexercisable portion of any Award of an Option or Stock Appreciation Right held by such Participant shall terminate at the date of termination of
+employment, and any portion of such Award that was exercisable immediately prior to such termination shall remain exercisable for three months after termination of the Participant's employment (but
+not after the scheduled expiration date of such Award) if the Participant is not a Non-Employee Director, and shall remain exercisable until the scheduled expiration of the Award if the
+Participant is a Non-Employee Director. 
+(2) Performance Units. If a Participant's employment with the Company and all of its Affiliates terminates
+during a Performance Period because of death, Disability or Retirement, the Participant shall be entitled to a payment of Performance Units at the end of the Performance Period based upon the extent
+to which achievement of Performance Measures was satisfied at the end of such period and prorated for the portion of the Performance Period during which the Participant was employed by the Company or
+any Affiliate. Except as provided in this Section 6(d)(2) or in the applicable Agreement, if a Participant's employment terminates with the Company and all of its Affiliates during a
+Performance Period, then such Participant shall not be entitled to any payment with respect to that Performance Period. 
+(3) Restricted Stock and Restricted Stock Unit Awards. If a Participant's employment with the Company and all of
+its Affiliates terminates because of death, Disability or Retirement, a pro rata portion of any outstanding Award of Restricted Stock or Restricted Stock Units shall immediately vest. The portion of
+the Award that will vest will involve that number of Shares or Units which, when combined with the number of Shares or Units subject to the Award that have previously vested, will represent the same
+ratio to the total number of Shares or Units subject to the original Award as the portion of the scheduled vesting period of the Award during which the Participant was employed by the Company and its
+Affiliates bears to the scheduled vesting period. The portion of any Award of Restricted Stock or Restricted Stock Units that does not vest as provided in the preceding sentence will terminate at the
+date of the Participant's termination of employment, and any Shares of Restricted Stock will be forfeited to the Company. 
+(e) Rights as Stockholder. Each Agreement shall provide that a Participant shall have no rights as a stockholder
+with respect to any securities covered by an Award unless and until the date the Participant becomes the holder of record of the Stock, if any, to which the Award relates. 
+(f) Performance-Based Awards. Any Award may be granted as a performance-based Award if the Committee establishes
+one or more Performance Measures upon which vesting, the lapse of restrictions or settlement in cash or Shares is contingent. With respect to any Award intended to be Performance-Based Compensation,
+the Committee shall establish and administer Performance Measures in the manner described in Section 162(m) of the Code and the then current regulations of the Secretary of the Treasury. 
+7. Restricted Stock Awards. 
+(a) An
+Award of Restricted Stock under the Plan shall consist of Shares subject to restrictions on transfer and conditions of forfeiture, which restrictions and conditions
+shall be 
+45 
+Table of Contents 
+included
+in the applicable Agreement. The Committee may provide for the vesting of such Shares and the corresponding lapse or waiver of any such restrictions or conditions based on such factors or
+criteria as the Committee, in its sole discretion, may determine. 
+(b) Except
+as otherwise provided in the applicable Agreement, the Shares subject to an Award of Restricted Stock shall be evidenced by a book-entry in the name
+of the Participant with the Company's transfer agent or by one or more Stock certificates issued in the name of the Participant. Any such Stock certificate shall either be deposited with the Company
+or its designee, together with an assignment separate from the certificate, in blank, signed by the Participant, or bear such legend with respect to the restricted nature of the Restricted Stock
+evidenced thereby as shall be provided for in the applicable Agreement. Any book-entry shall be accompanied by a similar legend. 
+(c) Upon
+the vesting of Restricted Stock and the corresponding lapse of the restrictions and conditions, unrestricted Shares shall be issued to the Participant or a
+Successor or Transferee. 
+(d) Unless
+otherwise provided in an Agreement, a Participant or a Transferee with a Restricted Stock Award shall have all the other rights of a stockholder including, but
+not limited to, the right to receive dividends and the right to vote the Shares of Restricted Stock. 
+8. Restricted Stock Unit Awards. An Award of Restricted Stock Units under the Plan shall be subject to
+restrictions on transfer and conditions of forfeiture, which restrictions and conditions shall be included in the applicable Agreement. The Committee may provide for the vesting of Restricted Stock
+Units and the corresponding lapse or waiver of any such restrictions or conditions based on such factors or criteria as the Committee, in its sole discretion, may determine. Following the vesting of a
+Restricted Stock Unit Award, payment to the Participant or a Successor or Transferee shall be made at such time or times as shall be provided in the Agreement in the form of cash, Shares or a
+combination of cash and Shares as determined by the Committee. 
+9. Stock Options. 
+(a) Terms of All Options. 
+(1) An
+Option shall be granted pursuant to an Agreement as either an Incentive Stock Option or a Non-Statutory Stock Option. The purchase price of each Share
+subject to an Option shall be determined by the Committee and set forth in the Agreement, but shall not be less than the Fair Market Value of a Share as of the Grant Date (except as provided in
+Section 20). 
+(2) The
+purchase price of the Shares with respect to which an Option is exercised shall be payable in full at the time of exercise, which may include, to the extent
+permitted by the Committee, payment under a broker-assisted sale and remittance program acceptable to the Committee. The purchase price may be paid in cash or, if the Committee so permits, by
+withholding Shares otherwise issuable to the Participant upon exercise of the Option or by delivery to the Company of Shares (by actual delivery or attestation) already owned by the Participant (in
+each case, such Shares having a Fair Market Value as of the date the Option is exercised equal to the purchase price of the Shares being purchased), or a combination thereof, unless otherwise provided
+in the Agreement. A Participant exercising an Option shall not be permitted to pay any portion of the purchase price with Shares if, in the opinion of the Committee, payment in such manner could have
+adverse financial accounting consequences for the Company. 
+46 
+Table of Contents 
+(3) Each
+Option shall be exercisable in whole or in part on the terms provided in the Agreement. In no event shall any Option be exercisable at any time after its scheduled
+expiration. When an Option is no longer exercisable, it shall be deemed to have terminated. 
+(4) Options
+will not be granted under the Plan in consideration for, and the grant of Options will not be conditioned on, the delivery of Shares to the Company in payment of
+the exercise price and/or tax withholding obligation under any other Option. 
+(b) Incentive Stock Options. In addition to the other terms and conditions applicable to
+all Options: 
+(1) The
+aggregate Fair Market Value (determined as of Option Grant Date) of the Shares with respect to which Incentive Stock Options held by an individual first become
+exercisable in any calendar year (under the Plan and all other incentive stock option plans of the Company and its Affiliates) shall not exceed $100,000 (or such other limit as may be required by the
+Code) if this limitation is necessary to qualify the Option as an Incentive Stock Option. To the extent an Option granted to a Participant exceeds this limit, the Option shall be treated as a
+Non-Statutory Stock Option. 
+(2) An
+Incentive Stock Option shall not be exercisable more than 10 years after its Grant Date (or such other limit as may be required by the Code) if this limitation
+is necessary to qualify the Option as an Incentive Stock Option. 
+(3) An
+Incentive Stock Option shall not be exercisable more than one year after termination of the Participant's employment with the Company and its Affiliates if such
+termination is due to the Participant's death or Disability, or more than three months after termination of the Participant's employment if such termination is due to any other reason. 
+(4) The
+Agreement covering an Incentive Stock Option shall contain such other terms and provisions that the Committee determines necessary to qualify the Option as an
+Incentive Stock Option. 
+(5) No
+Participant may receive an Incentive Stock Option under the Plan if, immediately after the grant of such Award, the Participant would own (after application of the
+rules contained in Code Section 424(d)) Shares possessing more than 10% of the total combined voting power of all classes of stock of the Company or its Subsidiaries, unless (i) the
+option price for that Incentive Stock Option is at least 110% of the Fair Market Value of the Shares subject to that Incentive Stock Option on the Grant Date and (ii) that Option is not
+exercisable after the date five years from its Grant Date. 
+10. Stock Appreciation Rights. An Award of a Stock Appreciation Right shall entitle the Participant (or a
+Successor or Transferee), subject to terms and conditions determined by the Committee, to receive upon exercise of the Stock Appreciation Right all or a portion of the excess of (i) the Fair
+Market Value of a specified number of Shares as of the date of exercise of the Stock Appreciation Right over (ii) a specified price that shall not be less than 100% of the Fair Market Value of
+such Shares as of the Grant Date of the Stock Appreciation Right. Each Stock Appreciation Right may be exercisable in whole or in part on the terms provided in the Agreement. No Stock Appreciation
+Right shall be exercisable at any time after its scheduled expiration. When a Stock Appreciation Right is no longer exercisable, it shall be deemed to have terminated. Upon exercise of a Stock
+Appreciation Right, payment to the Participant or a Successor or Transferee shall be made at such time or times as shall be provided in the Agreement in the form of cash, Shares or a combination of
+cash and Shares as determined by the Committee. The Agreement may provide for a limitation upon the amount or percentage of the total appreciation on which payment (whether in cash and/or Shares) may
+be made in the event of the exercise of a Stock Appreciation Right. 
+47 
+Table of Contents 
+11. Performance Units. 
+(a) Initial Award. 
+(1) An
+Award of Performance Units under the Plan shall entitle the Participant (or a Successor or Transferee) to future payments of cash, Shares or a combination thereof, as
+determined by the Committee, based upon the achievement of specified levels of one or more Performance Measures. The Agreement may provide that a portion of a Participant's Award will be paid for
+performance that exceeds the minimum target but falls below the maximum target applicable to the Award. The Agreement shall also provide for the timing of the payment. 
+(2) Following
+the conclusion or acceleration of each Performance Period, the Committee shall determine the extent to which (i) Performance Measures have been
+attained, (ii) any other terms and conditions with respect to an Award relating to the Performance Period have been satisfied and (iii) payment is due with respect to an Award of
+Performance Units. 
+(3) No
+Participant may receive Awards of Performance Units relating to more than 1,000,000 Shares in any year under this Plan. 
+(b) Acceleration and Adjustment. The Agreement may permit an acceleration of the Performance Period and an
+adjustment of Performance Measures and payments with respect to some or all of the Performance Units awarded to a Participant upon the occurrence of certain events, which may include a Change of
+Control, a Fundamental Change, a recapitalization, a change in the accounting practices of the Company, a change in the Participant's title or employment responsibilities, the Participant's death,
+Disability or Retirement or, with respect to payments in Shares, a reclassification, stock dividend, stock split or stock combination as provided in Section 17. The Agreement also may provide
+for a limitation on the value of an Award of Performance Units that a Participant may receive. 
+12. Other Awards. The Committee may from time to time grant Stock and other Awards under the Plan including,
+without limitation, those Awards pursuant to which Shares are or may in the future be acquired, Awards denominated in Stock units, securities convertible into Stock and phantom securities. The
+Committee, in its sole discretion, shall determine the terms and conditions of such Awards provided that such Awards shall not be inconsistent with the terms and purposes of the Plan. The Committee
+may, in its sole discretion, direct the Company to issue Shares subject to restrictive legends and/or stop transfer instructions that are consistent with the terms and conditions of the Award to which
+the Shares relate. 
+13. Effective Date and Duration of the Plan. 
+(a) Effective Date. The date the Plan is approved by the stockholders of the Company (the "Effective Date"). 
+(b) Duration of the Plan. The Plan shall remain in effect until all Shares subject to it shall be distributed,
+all Awards have expired or terminated, the Plan is terminated pursuant to Section 16, or the tenth anniversary of the Effective Date, whichever occurs first (the "Termination Date"). Awards
+made before the Termination Date may be exercised, vested or otherwise effectuated beyond the Termination Date unless limited in the Agreement or otherwise. 
+14. Plan Participation and Employment Status. 
+(a) Status
+as an eligible Employee shall not be construed as a commitment that any Award will be made under the Plan to that eligible Employee or to eligible Employees
+generally. 
+(b) Nothing
+in the Plan or in any Agreement or related documents shall confer upon any Employee or Participant any right to continue in the employment of the Company or any
+Affiliate 
+48 
+Table of Contents 
+or
+constitute any contract of employment or affect any right that the Company or any Affiliate may have to change such person's compensation, other benefits, job responsibilities, or title, or to
+terminate the employment of such person with or without cause. 
+15. Tax Withholding. The Company shall have the right to withhold from any cash payment under the Plan to a
+Participant or other person (including a Successor or a Transferee) an amount sufficient to cover any required withholding taxes. The Company shall have the right to require a Participant or other
+person receiving Shares under the Plan to pay the Company a cash amount sufficient to cover any required withholding taxes before actual receipt of those Shares. In lieu of all or any part of a cash
+payment from a person receiving Shares under the Plan, the Committee may permit the individual to cover all or any part of the required withholdings through a reduction in the number of Shares
+delivered or a delivery or tender to the Company of Shares held by the Participant or other person, in each case valued in the same manner as used in computing the withholding taxes under applicable
+laws. 
+16. Amendment and Termination of the Plan and Agreements. 
+(a) Except
+as limited in (b) below, (i) the Board may at any time and from time to time terminate, suspend or amend the Plan and (ii) the Committee may
+at any time alter or amend any or all Agreements under the Plan. The Company shall submit any amendment of the Plan to its stockholders for approval if the rules of the Nasdaq Global Select Market or
+other applicable laws or regulations require stockholder approval of such amendment. 
+(b) No
+termination, suspension, or amendment of the Plan will materially and adversely affect any right acquired by any Participant or Successor or Transferee under an Award
+granted before the date of termination, suspension, or amendment, unless otherwise agreed to by the Participant in the Agreement or otherwise, or required as a matter of law; but it will be
+conclusively presumed that any adjustment for changes in capitalization provided for in Sections 11(b) or 17 does not adversely affect these rights. In no event, however, shall the Board or the
+Committee have the right, without stockholder approval, to (i) lower the exercise or grant price of an Option or SAR after it is granted, except in connection with adjustments provided in
+Section 17, (ii) cancel an Option or SAR at a time when its exercise or grant price exceeds the fair market value of the underlying stock, in exchange for cash, another option or stock
+appreciation right, restricted stock or other equity award, unless the cancellation and exchange occurs in connection with a merger, acquisition, spin-off or other similar corporate
+transaction or (iii) take any other action that is treated as a repricing under generally accepted accounting principles. . 
+17. Adjustment for Changes in Capitalization. In the event of any equity restructuring (within the meaning of
+Accounting Standard Codification 718, Compensation—Stock Compensation, issued by the Financial Accounting Standards Board, referred to as "FASB ASC Topic 718") that causes the per Share
+value of Shares to change, such as a stock dividend or stock split, the Committee shall cause there to be made an equitable adjustment to the number and kind of Shares or other securities issued or
+reserved for issuance pursuant to the Plan and to outstanding Awards (including but not limited to the number and kind of Shares to which such Awards are subject, and the exercise or strike price of
+such Awards) to the extent such other Awards would not otherwise automatically adjust in the equity restructuring; provided, in each case, that with respect to Incentive Stock Options, no such
+adjustment shall be authorized to the extent that such adjustment would cause such Incentive Stock Options to violate Section 422(b) of the Code or any successor provision. Notwithstanding
+anything in this Plan to the contrary, (a) any adjustments made pursuant to this Section 17 to Awards that are considered "deferred compensation" within the meaning of
+Section 409A shall be made in compliance with the requirements of Section 409A and (b) any adjustments made pursuant to this Section 17 to Awards that are not considered
+"deferred compensation" subject to Section 409A shall be made in such a manner as to ensure that after such adjustment the Awards either (i) continue not to be subject to 
+49 
+Table of Contents 
+Section 409A
+or (ii) comply with the requirements of Section 409A. In the event of any other change in corporate capitalization, which may include a merger, consolidation, any
+reorganization (whether or not such reorganization comes within the definition of such term in Section 368 of the Code), or any partial or complete liquidation of the Company to the extent such
+events do not constitute equity restructurings or business combinations within the meaning of FASB ASC Topic 718, such equitable adjustments described in the foregoing sentence may be made as
+determined to be appropriate and equitable by the Committee to prevent dilution or enlargement of rights. In either case, any such adjustment shall be conclusive and binding for all purposes of the
+Plan. Unless otherwise determined by the Committee, the number of Shares subject to an Award shall always be a whole number. 
+18. Fundamental Change. In the event of a proposed Fundamental Change, the Committee may, but shall not be
+obligated to: 
+(a) if
+the Fundamental Change is a merger or consolidation, make appropriate provision for the protection of the outstanding Options and Stock Appreciation Rights by the
+substitution of options, stock appreciation rights and appropriate voting common stock of the corporation surviving any merger or consolidation or, if appropriate, the parent corporation of the
+Company or such surviving corporation; or 
+(b) at
+least ten days before the occurrence of the Fundamental Change, declare, and provide written notice to each holder of an Option or Stock Appreciation Right of the
+declaration, that each outstanding Option and Stock Appreciation Right, whether or not then exercisable, shall be canceled at the time of, or immediately before the occurrence of the Fundamental
+Change in exchange for payment to each holder of an Option or Stock Appreciation Right, within ten days after the Fundamental Change, of cash equal to (i) for each Share covered by the canceled
+Option, the amount, if any, by which the Fair Market Value (as defined in this Section) per Share exceeds the exercise price per Share covered by such Option or (ii) for each Stock Appreciation
+Right, the price determined pursuant to Section 10, except that Fair Market Value of the Shares as of the date of exercise of the Stock Appreciation Right, as used in clause (i) of
+Section 10, shall be deemed to mean Fair Market Value for each Share with respect to which the Stock Appreciation Right is calculated determined in the manner hereinafter referred to in this
+Section. At the time of the declaration provided for in the immediately preceding sentence, each Stock Appreciation Right and each Option shall immediately become exercisable in full and each person
+holding an Option or a Stock Appreciation Right shall have the right, during the period preceding the time of cancellation of the Option or Stock Appreciation Right, to exercise the Option as to all
+or any part of the Shares covered thereby or the Stock Appreciation Right in whole or in part, as the case may be. In the event of a declaration pursuant to Section 18(b), each outstanding
+Option and Stock Appreciation Right granted pursuant to the Plan that shall not have been exercised before the Fundamental Change shall be canceled at the time of, or immediately before, the
+Fundamental Change, as provided in the declaration. Notwithstanding the foregoing, no person holding an Option or a Stock Appreciation Right shall be entitled to the payment provided for in this
+Section 18(b) if such Option or Stock Appreciation Right shall have terminated, expired or been cancelled. For purposes of this Section only, "Fair Market Value" per Share means the cash plus
+the fair market value, as determined in good faith by the Committee, of the non-cash consideration to be received per Share by the stockholders of the Company upon the occurrence of the
+Fundamental Change. 
+19. Dividends and Dividend Equivalents. An Award may, if so determined by the Committee, provide the Participant
+with the right to receive dividend payments or dividend equivalent payments with respect to Shares subject to the Award (both before and after the Shares subject to the Award are earned, vested or
+acquired), which payments may be either made currently or credited to an account for the Participant, and may be settled in cash or Shares, as determined by the Committee. Any such settlements, and
+any such crediting of dividends or dividend equivalents or reinvestment in Shares, may 
+50 
+Table of Contents 
+be
+subject to such conditions, restrictions and contingencies as the Committee shall establish, including the reinvestment of such credited amounts in Share equivalents, and must comply with or
+qualify for an exemption under Section 409A. 
+20. Corporate Mergers, Acquisitions, Etc. Notwithstanding anything in the Plan to the contrary, the Committee
+may grant Substitute Awards under the Plan. Substitute Awards shall not reduce the number of shares authorized for issuance under the Plan. In the event that an Acquired Entity has shares available
+for awards or grants under one or more preexisting plans not adopted in contemplation of such acquisition or combination and previously approved by the Acquired Entity's stockholders, then, to the
+extent determined by the Committee, the shares available for grant pursuant to the terms of such preexisting plan (as adjusted, to the extent appropriate, using the exchange ratio or other adjustment
+or valuation ratio or formula used in such acquisition or combination to determine the consideration payable to holders of common stock of the entities that are parties to such acquisition or
+combination) may be used for Awards under the Plan and shall not reduce the number of shares of Common Stock authorized for issuance under the Plan; provided, however, that Awards using such available
+shares shall not be made after the date awards or grants could have been made under the terms of such preexisting plans, absent the acquisition or combination, and shall only be made to individuals
+who were not employees or directors of the Company or an Affiliate immediately prior to such acquisition or combination. In the event that a written agreement between the Company and an Acquired
+Entity pursuant to which a merger or consolidation is completed is approved by the Board and that agreement sets forth the terms and conditions of the substitution for or assumption of outstanding
+awards of the Acquired Entity, those terms and conditions shall be deemed to be the action of the Committee without any further action by the Committee, except as may be required for compliance with
+Rule 16b-3 under the Exchange Act, and the persons holding such awards shall be deemed to be Participants. 
+21. Unfunded Plan. The Plan shall be unfunded and the Company shall not be required to segregate any assets that
+may at any time be represented by Awards under the Plan. Neither the Company, its Affiliates, the Committee, nor the Board of Directors shall be deemed to be a trustee of any amounts to be paid under
+the Plan nor shall anything contained in the Plan or any action taken pursuant to its provisions create or be construed to create a fiduciary relationship between the Company and/or its Affiliates,
+and a Participant or Successor or Transferee. To the extent any person acquires a right to receive an Award under the Plan, this right shall be no greater than the right of an unsecured general
+creditor of the Company. 
+22. Limits of Liability. 
+(a) Any
+liability of the Company to any Participant with respect to an Award shall be based solely upon contractual obligations created by the Plan and the Award Agreement. 
+(b) Except
+as may be required by law, neither the Company nor any member of the Board of Directors or of the Committee, nor any other person participating (including
+participation pursuant to a delegation of authority under Section 3(a)(2) of the Plan) in any determination of any question under the Plan, or in the interpretation, administration or
+application of the Plan, shall have any liability to any party for any action taken, or not taken, in good faith under the Plan. 
+23. Compliance with Applicable Legal Requirements. No Shares distributable pursuant to the Plan shall be issued
+and delivered unless the issuance of the Shares complies with all applicable legal requirements including, without limitation, compliance with the provisions of applicable state securities laws, the
+Securities Act of 1933, as amended and in effect from time to time or any successor statute, the Exchange Act and the requirements of the exchanges on which the Company's Shares may, at the time, be
+listed. 
+51 
+Table of Contents 
+24. Deferrals and Settlements. The Committee may require or permit Participants to elect to defer the issuance
+of Shares or the settlement of Awards in cash under such rules and procedures as it may establish under the Plan. It may also provide that deferred settlements include the payment or crediting of
+interest on the deferral amounts. The terms of any deferrals under this Section 24 shall comply with all applicable law, rules and regulations, including, without limitation,
+Section 409A. 
+25. Other Benefit and Compensation Programs. Payments and other benefits received by a Participant under an
+Award made pursuant to the Plan shall not be deemed a part of a Participant's regular, recurring compensation for purposes of the termination, indemnity or severance pay laws of any country and shall
+not be included in, nor have any effect on, the determination of benefits under any other employee benefit plan, contract or similar arrangement provided by the Company or an Affiliate unless
+expressly so provided by such other plan, contract or arrangement, or unless the Committee expressly determines that an Award or portion of an Award should be included to accurately reflect
+competitive compensation practices or to recognize that an Award has been made in lieu of a portion of competitive cash compensation. 
+26. Beneficiary Upon Participant's Death. To the extent that the transfer of a Participant's Award at death is
+permitted by this Plan or under an Agreement, (i) a Participant's Award shall be transferable to the beneficiary, if any, designated on forms prescribed by and filed with the Committee and
+(ii) upon the death of the Participant, such beneficiary shall succeed to the rights of the Participant to the extent permitted by law and this Plan. If no such designation of a beneficiary has
+been made, the Participant's legal representative shall succeed to the Awards, which shall be transferable by will or pursuant to laws of descent and distribution to the extent permitted by this Plan
+or under an Agreement. 
+27. Requirements of Law. 
+(a) To
+the extent that federal laws do not otherwise control, the Plan and all determinations made and actions taken pursuant to the Plan shall be governed by the laws of
+the State of Delaware without regard to its conflicts-of-law principles and shall be construed accordingly. 
+(b) If
+any provision of the Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Plan, and the Plan
+shall be construed and enforced as if the illegal or invalid provision had not been included. 
+(c) The
+Plan and Awards granted under the Plan are intended to comply with or be exempt from the requirements of Section 409A to the maximum extent possible, whether
+pursuant to the short-term deferral exception described in Treasury Regulation Section 1.409A-1(b)(4), the exclusion applicable to stock options and stock appreciation
+rights under Treasury Regulation Section 1.409A-1(b)(5), or otherwise. To the extent Section 409A is applicable to the Plan or any Award granted under the Plan, it is
+intended that the Plan and any such Awards granted under the Plan comply with the deferral, payout and other limitations and restrictions imposed under Section 409A. Notwithstanding any other
+provision of the Plan or any Award granted under the Plan to the contrary, the Plan and any Award granted under the Plan shall be interpreted, operated and administered in a manner consistent with
+such intentions; provided, however, that the Committee makes no representations or warranties that Awards granted under the Plan shall be exempt from or comply with Section 409A and makes no
+undertaking to preclude Section 409A from applying to Awards granted under the Plan. No provision of the Plan or any Award shall be interpreted or construed to transfer any liability resulting
+from or arising out of any such consequences from a Participant or any other individual to the Company or any of its Subsidiaries. Without limiting the generality of the foregoing, and notwithstanding
+any other provision of the Plan or any Award granted under the Plan to the contrary, with respect to any payments and benefits under the Plan or any Award granted under the Plan to which
+Section 409A applies, all references in the Plan or any Award granted under the Plan to the termination of the Participant's 
+52 
+Table of Contents 
+employment
+or service are intended to mean the Participant's "separation from service," within the meaning of Section 409A(a)(2)(A)(i) to the extent necessary to avoid subjecting the
+Participant to the imposition of any additional tax under Section 409A. In addition, if the Participant is a "specified employee," within the meaning of Section 409A(2)(B)(i), then to
+the extent necessary to avoid subjecting the Participant to the imposition of any additional tax under Section 409A, amounts that would otherwise be payable under the Plan or any Award granted
+under the Plan during the six-month period immediately following the Participant's "separation from service," within the meaning of Section 409A(a)(2)(A)(i), shall not be paid to
+the Participant during such period, but shall instead be accumulated and paid to the Participant (or, in the event of the Participant's death, the Participant's estate) in a lump sum on the first
+business day after the earlier of (a) the date that is six months following the Participant's separation from service or (b) the Participant's death. Notwithstanding any other provision
+of the Plan to the contrary, the Committee, to the extent it deems necessary or advisable in its sole discretion, reserves the right, but shall not be required, to unilaterally amend or modify the
+Plan and any Award granted under the Plan so that the Award qualifies for exemption from or complies with Section 409A. 
+53 
+6328 MONARCH PARK PLACE 
+NIWOT, CO 80503 
+VOTE BY INTERNET— www.proxyvote.com 
+Use the Internet to transmit your voting instructions and for electronic delivery of information up until 11:59 P.M. Eastern Time the day before the cut-off date or meeting date. Have your proxy card in hand when you access the web site and follow the instructions to obtain your records and to create an electronic voting instruction form. 
+ELECTRONIC DELIVERY OF FUTURE STOCKHOLDER COMMUNICATIONS 
+If you would like to reduce the costs incurred by Crocs, Inc. in mailing proxy materials, you can consent to receiving all future proxy statements, proxy cards and annual reports electronically via e-mail or the Internet. To sign up for electronic delivery, please follow the instructions above to vote using the Internet and, when prompted, indicate that you agree to receive or access stockholder communications electronically in future years. 
+VOTE BY PHONE—1-800-690-6903 
+Use any touch-tone telephone to transmit your voting instructions up until 11:59 P.M. Eastern Time the day before the cut-off date or meeting date. Have your proxy card in hand when you call and then follow the instructions. 
+VOTE BY MAIL 
+Mark, sign and date your proxy card and return it in the postage- paid envelope we have provided or return it to Crocs, Inc., c/o Broadridge, 51 Mercedes Way, Edgewood, NY 11717. 
+TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS 
+FOLLOWS: 
+CROCS1 
+KEEP THIS PORTION FOR YOUR RECORDS 
+DETACH AND RETURN THIS PORTION ONLY 
+THIS PROXY CARD IS VALID ONLY WHEN SIGNED AND DATED. 
+CROCS, INC. 
+THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ALL NOMINEES LISTED AND "FOR" PROPOSALS 2, 3, 4, AND "EVERY 3 YEARS" FOR PROPOSAL 5. 
+For 
+All 
+Withhold 
+All 
+For All 
+Except 
+To withhold authority to vote for any individual nominee(s), mark “For All Except” and write the number(s) of the nominee(s) on the line below. 
+Vote on Directors 
+1 
+ELECTION OF DIRECTORS 
+o 
+o 
+o 
+Nominees: 
+01) Thomas J. Smach 
+02) John P. McCarvel 
+Vote on Proposal 
+For 
+Against 
+Abstain 
+2 
+Ratification of the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for fiscal year 2011. 
+o 
+o 
+o 
+3 
+Approval of the amendment and restatement of our 2007 Equity Incentive Plan. 
+o 
+o 
+o 
+4 
+Advisory vote on the compensation of our named executive officers . 
+o 
+o 
+o 
+3 YRS 
+2 YRS 
+1 YR 
+Abstain 
+5 
+Advisory vote on the frequency of future advisory votes on the compensation of our named executive officers . 
+o 
+o 
+o 
+o 
+6 
+Such other business as may properly come before the meeting or any postponement or adjournment thereof. 
+The shares represented by this proxy when properly executed will be voted in the manner directed herein by the undersigned Stockholder(s). If no direction is made, this proxy will be voted FOR all nominees listed and FOR Proposals 2, 3, and 4 and EVERY THREE YEARS for Proposal 5. 
+For address changes and/or comments, please check this box and write them on the back where indicated. 
+o 
+Please indicate if you plan to attend this meeting. 
+o 
+o 
+Yes 
+No 
+(NOTE: Please sign exactly as your name(s) appear(s) hereon. All holders must sign. When signing as attorney, executor, administrator, or other fiduciary, please give full title as such. Joint owners should each sign personally. If a corporation, please sign in full corporate name, by authorized officer. If a partnership, please sign in partnership name by authorized person.) 
+Signature [PLEASE SIGN WITHIN o BOX] 
+Date 
+Signature (Joint Owners) 
+Date 
+Important Notice Regarding Internet Availability of Proxy Materials for the Annual Meeting: The Notice and Proxy Statement and Annual Report are available at www.proxyvote.com. 
+CROCS, INC. 
+THIS PROXY IS SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS 
+ANNUAL MEETING OF STOCKHOLDERS 
+June 28, 2011 
+The undersigned hereby appoints John McCarvel and Daniel P. Hart and each of them, with power of substitution, as proxies of the undersigned, to attend the Annual Meeting of Stockholders of Crocs, Inc. (the “Company”), to be held at the St. Julien Hotel, 900 Walnut Street, Boulder, Colorado, on June 28, 2011 at 2 p.m., Mountain Time, and all adjournments thereof, and to vote, as indicated on the reverse side, the shares of Common Stock of the Company which the undersigned is entitled to vote with all the powers the undersigned would possess if present at the meeting. 
+THIS PROXY, WHEN PROPERLY EXECUTED, WILL BE VOTED AS DIRECTED HEREIN BY THE UNDERSIGNED STOCKHOLDER(S). IF NO SPECIFIC DIRECTIONS ARE GIVEN, THIS PROXY WILL BE VOTED FOR ALL NOMINEES LISTED AND "FOR" PROPOSALS 2, 3, 4, AND "EVERY 3 YEARS" FOR PROPOSAL 5. 
+PLEASE MARK, SIGN, DATE AND RETURN THIS PROXY CARD PROMPTLY USING THE ENCLOSED REPLY ENVELOPE. 
+Address Changes/Comments: 
+(If you noted any Address Changes/Comments above, please mark corresponding box on the reverse side.) 
+CONTINUED AND TO BE SIGNED ON REVERSE SIDE
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001047469-11-004301/proxy_rpt.txt b/raw/proxies/0001334036/0001047469-11-004301/proxy_rpt.txt
new file mode 100644
index 0000000000000000000000000000000000000000..90bdcce9a71e37411aadab87b82cd1a6f723f198
--- /dev/null
+++ b/raw/proxies/0001334036/0001047469-11-004301/proxy_rpt.txt
@@ -0,0 +1,19 @@
+CERTAIN RELATIONSHIPS AND RELATED PERSON TRANSACTIONS 
+Related Person Transactions 
+We had no transactions with related persons during 2010 which are required to be disclosed by the rules of the SEC. 
+Policy on Transactions with Related Persons 
+Our Business Code of Conduct and Ethics requires that any transaction involving us in which one of our directors, nominees for
+director, executive officers, or greater than five percent stockholders, or one of the aforementioned's immediate family members (each, a "related person"), have a material interest be approved or
+ratified by the Audit Committee if the amount involved, when aggregated with the amount of all other transactions between the related person and us, exceeds $100,000 in a fiscal year. The full Board
+reviews ordinary course of business transactions in which directors have an interest as part of the Board's annual director independence review, and our Business Code of Conduct and Ethics permits the
+full Board to waive any conflicts of interest between us and any director or officer. In determining whether to approve or ratify any such transaction, the Audit Committee must consider, in addition
+to other factors it deems appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify certain directors and executive officers in addition to the indemnification provided for
+in our certificate of incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain 
+12 
+Table of Contents 
+expenses
+(including attorneys' fees), judgments, fines and settlement amounts incurred by any such person in any action or proceeding, including any action by us or in our right, arising out of such
+person's services as a director or executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request. We believe that these
+provisions and agreements are necessary to attract and retain qualified persons as directors and executive officers.
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001047469-13-004482/proxy.txt b/raw/proxies/0001334036/0001047469-13-004482/proxy.txt
new file mode 100644
index 0000000000000000000000000000000000000000..2ab232b9ff0e4b98ddb4ed3a49873bce278c58dc
--- /dev/null
+++ b/raw/proxies/0001334036/0001047469-13-004482/proxy.txt
@@ -0,0 +1,1887 @@
+DEF 14A
+1
+a2214463zdef14a.htm
+DEF 14A
+Use these links to rapidly review the document 
+TABLE OF CONTENTS 
+Table of Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+SCHEDULE 14A 
+Proxy
+Statement Pursuant to Section 14(a) of 
+the Securities Exchange Act of 1934 (Amendment No. ) 
+Filed by the Registrant ý 
+Filed by a Party other than the Registrant o 
+Check the appropriate box: 
+o 
+Preliminary Proxy Statement 
+o 
+Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2)) 
+ý 
+Definitive Proxy Statement 
+o 
+Definitive Additional Materials 
+o 
+Soliciting Material under §240.14a-12 
+CROCS, INC. 
+(Name of Registrant as Specified In Its Charter) 
+(Name of Person(s) Filing Proxy Statement, if other than the Registrant) 
+Payment of Filing Fee (Check the appropriate box): 
+ý 
+No fee required. 
+o 
+Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11. 
+(1) 
+Title of each class of securities to which transaction applies: 
+(2) 
+Aggregate number of securities to which transaction applies: 
+(3) 
+Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined): 
+(4) 
+Proposed maximum aggregate value of transaction: 
+(5) 
+Total fee paid: 
+o 
+Fee paid previously with preliminary materials. 
+o 
+Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration
+statement number, or the Form or Schedule and the date of its filing. 
+(1) 
+Amount Previously Paid: 
+(2) 
+Form, Schedule or Registration Statement No.: 
+(3) 
+Filing Party: 
+(4) 
+Date Filed: 
+Table of Contents 
+Crocs, Inc. 
+7477 East Dry Creek Parkway 
+Niwot, Colorado 80503 
+NOTICE OF THE 2013 ANNUAL MEETING OF STOCKHOLDERS 
+TO BE HELD JUNE 12, 2013 
+To the Stockholders of Crocs, Inc.: 
+We
+will hold the 2013 Annual Meeting of Stockholders of Crocs, Inc. at the St. Julien Hotel, 900 Walnut Street, Boulder, Colorado, on June 12, 2013 at 2:00 p.m.
+Mountain Time. 
+The
+meeting's purpose is to: 
+1. elect
+three Class II directors;
+2. ratify
+the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for fiscal year 2013;
+3. hold
+an advisory vote to approve the compensation of our named executive officers; and
+4. consider
+any other matters that properly come before the meeting or any postponement or adjournment thereof. 
+Only
+stockholders of record of our common stock at the close of business on April 16, 2013 are entitled to receive notice of and to vote at the meeting. Each share of common stock is entitled
+to one vote. 
+A
+list of the stockholders entitled to vote at the meeting will be available for examination at the meeting by any stockholder for any purpose relevant to the meeting. The list will also be available
+on the same basis for ten days prior to the meeting at our principal executive office, 7477 East Dry Creek Parkway, Niwot, Colorado 80503. 
+All
+stockholders are cordially invited to attend the meeting in person. Whether or not you plan to attend the meeting in person, please vote your shares as instructed in the Notice of Internet
+Availability of Proxy Materials, over the Internet, or by telephone after your receipt of hard copies of the proxy materials, as promptly as possible. You may also request a paper proxy card, which
+will include a reply envelope, to submit your vote by mail, as described in the Notice of Internet Availability of Proxy Materials. Stockholders who are present at the Annual Meeting may withdraw
+their proxy and vote in person if they so desire. 
+BY ORDER OF THE BOARD OF DIRECTORS 
+John P. McCarvel 
+President and Chief Executive Officer 
+Niwot,
+Colorado 
+April 17, 2013 
+Table of Contents 
+TABLE OF CONTENTS 
+Page 
+Proxy Statement 
+1 
+General Information Regarding Annual Meeting
+1 
+Proposal 1—Election of Directors 
+3 
+Corporate Governance 
+6 
+Board of Directors and Committees of the Board
+8 
+Executive Officers 
+10 
+Beneficial Ownership of our Common Stock 
+11 
+Certain Relationships and Related Person Transactions
+13 
+Director Compensation 
+14 
+Executive Compensation 
+16 
+Compensation Committee Report 
+24 
+Report of the Audit Committee 
+30 
+Independent Registered Public Accounting Firm
+30 
+Proposal 2—Ratification of the Appointment of
+Independent Registered Public Accounting Firm 
+31 
+Proposal 3—Advisory Vote to Approve the Compensation of
+our Named Executive Officers 
+31 
+Other Matters 
+32 
+Table of Contents 
+Crocs, Inc. 
+7477 East Dry Creek Parkway 
+Niwot, Colorado 80503 
+2013 ANNUAL MEETING OF STOCKHOLDERS 
+PROXY STATEMENT 
+This
+proxy statement will first be made available to stockholders on or about April 17, 2013. It is furnished to stockholders of Crocs, Inc., a Delaware corporation ("we," "us," or
+"our"), in connection with the solicitation of proxies by our Board of Directors. The proxies being solicited will be voted at the 2013 Annual Meeting of Stockholders (the "Annual Meeting"), to be
+held on June 12, 2013 at the St. Julien Hotel, 900 Walnut Street, Boulder, Colorado at 2:00 p.m. Mountain Time, or at any postponement or adjournment thereof, for the purpose of
+voting on the proposals as set forth herein as well as other business matters which may properly come before the meeting. 
+Under
+the rules of the Securities and Exchange Commission (the "SEC"), we are furnishing proxy materials to our stockholders on the Internet, rather than mailing printed copies. If you received a
+Notice of Internet Availability of Proxy Materials by mail, you will not receive a printed copy of the proxy materials unless you request one as instructed in that notice. Instead, the Notice of
+Internet Availability of Proxy Materials will instruct you as to how you may access and review the proxy materials on the Internet. This proxy statement and our 2012 annual report to stockholders are
+available at www.proxyvote.com. 
+GENERAL INFORMATION REGARDING ANNUAL MEETING 
+Record Date. Stockholders of record at the close of business on April 16, 2013 are entitled to notice of, and to vote at, the Annual Meeting. On the record
+date, there were 88,116,235 shares of our common stock outstanding. Each such share is entitled to one vote on each matter submitted to a vote at the Annual Meeting. 
+Quorum Requirements. A quorum is required to conduct business at the Annual Meeting. The holders of a majority of the outstanding shares entitled to vote generally
+in the election of directors must be present in person or by proxy at the Annual Meeting in order for a quorum to exist. Abstentions and broker non-votes count as present for purposes of
+determining a quorum. A broker
+non-vote occurs when a broker returns a proxy card but does not vote on one or more matters because the broker does not have the authority to do so without instructions from the beneficial
+owner. Shares represented by proxies that are marked withhold with respect to the election of our Class II directors will be counted as present in determining whether there is a quorum. 
+1 
+Table of Contents 
+Vote Requirements. If a quorum is present at the Annual Meeting, the following vote is required for approval of each matter to be voted on. 
+Election of Directors. The three Class II director nominees receiving the highest number of "for" votes cast in person or by proxy
+at the Annual Meeting will be elected as directors. Proxies marked withhold and broker non-votes will have no effect on the outcome of this proposal. Cumulative voting is not permitted.
+See "Corporate Governance—Majority Vote Director Resignation Policy" (below) regarding director nominees who receive a greater number of votes "withheld" from their election than votes
+"for" such election. 
+Ratification of Appointment of Deloitte & Touche LLP. The affirmative vote of the holders of a majority of the shares of our
+common stock present in person or by proxy and entitled to vote on the proposal is required for the ratification of the appointment of Deloitte & Touche LLP as our independent registered
+public accounting firm for fiscal year 2013. Abstentions will have the effect of voting against this proposal. Broker non-votes will have no effect on the outcome of this proposal. 
+Advisory Vote to Approve Named Executive Officer Compensation. The affirmative vote of the holders of a majority of the shares of our
+common stock present in person or by proxy and entitled to vote on the proposal is required to approve the advisory resolution to approve the compensation of our named executive officers. Abstentions
+will have the effect of voting against this proposal. Broker non-votes will have no effect on the outcome of this proposal. 
+Approval of all Other Proposals: With respect to any other matters properly brought before the Annual Meeting, the affirmative vote of the
+holders of a majority of the shares of our common stock present in person or by proxy and entitled to vote on the proposals will be the act of the stockholders. Abstentions will have the effect of
+voting against these proposals. Broker non-votes will have no effect on the outcome of these proposals. 
+Board Recommendations. Our Board of Directors' recommendation is set forth together with the description of each proposal. In summary, our Board of Directors
+recommends a vote: 
+• FOR election of each of the Class II director nominees (see
+Proposal 1); 
+• FOR the ratification of the appointment of Deloitte &
+Touche LLP as our independent registered public accounting firm for our fiscal year ending December 31, 2013 (see Proposal 2); and 
+• FOR the advisory vote to approve the compensation of our named executive
+officers as disclosed in this proxy statement (see Proposal 3). 
+Your Proxy. Whether or not you are able to personally attend the Annual Meeting, you are encouraged to vote your shares as instructed in
+the Notice of Internet Availability of Proxy Materials. Shares represented by properly executed methods, and not revoked prior to the Annual Meeting, will be voted at the Annual Meeting as directed in
+the proxy. If no directions are specified, such proxies will be voted FOR each of the proposals described in this proxy statement and in the best judgment of the proxy holders
+as to other matters that may properly come before the Annual Meeting. 
+If
+your shares are held in the name of a bank or brokerage firm, your bank or broker will send you a separate package describing the procedures and options for voting your shares. You should follow
+the instructions provided by your bank or brokerage firm. On routine matters, such as the ratification of the appointment of our independent registered public accounting firm, your broker will vote
+your shares for you at his or her discretion if you do not instruct your broker how to vote. For non-routine matters, which include all other matters to be voted upon at the Annual
+Meeting, your broker may not vote your shares without specific voting instructions from you. 
+2 
+Table of Contents 
+Revocation. Any stockholder giving a proxy has the power to revoke the proxy, or change the proxy, at any time before the proxy is voted at the Annual Meeting by
+(i) re-voting online at www.proxyvote.com, (ii) sending another properly executed proxy bearing a later date or a written notice of revocation of the proxy to Corporate
+Secretary, Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503 or (iii) voting in person at the Annual Meeting. 
+Cost of Proxy Solicitation. Our Board of Directors is soliciting the proxies. We will bear the entire cost of this proxy solicitation. We have retained the
+services of Georgeson, Inc., a professional proxy solicitation firm, to aid in the solicitation of proxies. Georgeson, Inc. may solicit proxies by personal interview, mail, telephone,
+facsimile, email or otherwise. We will pay Georgeson, Inc. its customary fee, estimated to be approximately $20,000, plus reasonable out-of-pocket expenses incurred in
+the process of soliciting proxies. We may also reimburse brokers, custodians, nominees and other fiduciaries for normal handling charges incurred for forwarding proxy materials to beneficial owners.
+Solicitation of proxies may be made personally or by mail or telephone by our directors, officers and other employees, who will receive no additional compensation for such services. 
+PROPOSAL 1—ELECTION OF DIRECTORS 
+Our
+Board of Directors (the "Board") currently consists of eight members divided into three classes, with each director elected to a three-year term. Class I consists of Ronald L.
+Frasch and W. Stephen Cannon, whose terms will expire at the annual meeting to be held in 2015. Class II consists of Raymond D. Croghan, Peter A. Jacobi and Doreen A. Wright, whose terms will
+expire at the Annual Meeting. Class III consists of Thomas J. Smach, Jeffrey H. Margolis and John P. McCarvel, whose terms will expire at the annual meeting to be held in 2014. Under our
+amended and restated bylaws, each of our directors holds office until his or her successor has been elected and qualified or until such director's earlier resignation or removal. 
+At
+each annual meeting of stockholders, the successors to directors whose terms expire at such meeting will be elected, or such directors will be re-elected, and will serve from the time
+of election and qualification until the third annual meeting following their election or until their successors are duly elected and qualified. The current authorized number of directors is eight. The
+authorized number of directors may be changed by resolution of the Board. Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes
+so that, as nearly as possible, each class will consist of one-third of the directors. Vacancies on the Board can be filled by resolution of the Board. 
+Upon
+the recommendation of the Nominating and Governance Committee, the Board has nominated Raymond D. Croghan, Peter A. Jacobi and Doreen A. Wright for re-election as Class II
+directors to serve for a three-year term expiring at the 2016 annual meeting of stockholders. 
+A
+stockholder cannot vote for more than three nominees. Each of the director nominees has consented to serve for a three-year term. We do not contemplate that any of the nominees will be
+unable to stand for election, but should any nominee become unable to serve or will not serve for any reason, all proxies (except proxies marked to the contrary) will be voted for the election of a
+substitute nominee as the Board may recommend. 
+Class II Director Nominees 
+Raymond D. Croghan (Class II), age 63, has served as a member of the
+Board since August 2004. Since 1999, Mr. Croghan has been retired. From 1991 to 1999, Mr. Croghan managed Croghan & Associates, Inc., a healthcare information technology
+consulting firm, which merged with Margolis 
+3 
+Table of Contents 
+Health
+Enterprise to form The TriZetto Group. Mr. Croghan currently serves on the boards of directors of several privately-held companies. Mr. Croghan has successfully
+operated and grown private companies and has served on the boards of several companies in a variety of industries. His experience successfully operating companies in different industries provides us
+with a unique perspective as does his board experience. In addition, Mr. Croghan is our longest serving director and has extensive knowledge of our company and its operations. 
+Peter A. Jacobi (Class II), age 69, has served as a member of the Board since October 2008. Mr. Jacobi was
+employed by Levi Strauss & Company ("Levi Strauss"), a jeans and casual wear manufacturer, from 1970 until his retirement in 1999. During his 29 years of tenure at Levi Strauss,
+Mr. Jacobi held various senior level positions, including President of the Men's Jeans Division, President of Global Sourcing,
+President of Levi Strauss International, and from 1996 until his retirement, President and Chief Operating Officer. Mr. Jacobi has extensive executive experience in the apparel industry gained
+through his tenure at Levi Strauss. The apparel industry is similar and complementary to the footwear industry and Mr. Jacobi has provided us significant insights from this industry. In
+addition, Levi Strauss is an established international brand. Mr. Jacobi's experience with a global brand has helped us as we continue to build our brand internationally. 
+Doreen A. Wright (Class II), age 56, has served as a member of the Board since June 2011 prior to which she served as
+Senior Vice President and Chief Information Officer of Campbell Soup Company from 2001 to 2008. Ms. Wright also served as Interim Chief of Human Resources for Campbell Soup Company in 2002.
+From 1999 to 2001, Ms. Wright served as Executive Vice President and Chief Information Officer for Nabisco Inc. Prior to that, from 1995 to 1998 Ms. Wright held the position of
+Senior Vice President, Operations & Systems, Prudential Investments, for Prudential Insurance Company of America, and held various positions with American Express Company, Bankers Trust
+Corporation and Merrill Lynch & Co. Since 2009, Ms. Wright has served on the Board of Directors of Dean Foods Company, a leading food and beverage company. She also serves on the
+Board of the WhiteWave Foods Company, a U.S. and European organic and plant based food and beverage company. She also serves on the Board of New Hope Arts, Inc., a regional nonprofit arts
+center. In addition, Ms. Wright served on the Board of Directors of Citadel Broadcasting Corporation from 2010 to 2011, where she chaired the Compensation Committee; The Oriental Trading
+Company from 2008 to 2011, where she served on the Audit and Compensation Committees; Yankee Candle Company from 2003 to 2007, where she served on the Compensation and Audit Committees; and
+Conseco, Inc. from 2007 to 2010, where she served on the Audit and Enterprise Risk Committee. Ms. Wright brings more than 30 years of leadership experience in the financial
+services and consumer products industries, with emphasis in the area of information technology, operations, and human resources. Ms. Wright also has extensive experience as a public company
+director, including service on audit, compensation and corporate governance committees. 
+THE BOARD RECOMMENDS A VOTE "FOR" EACH OF THE ABOVE-NAMED NOMINEES FOR DIRECTOR. 
+Information About Continuing Directors 
+Ronald L. Frasch (Class I), age 64, has served as a member of the
+Board since October 2006 and as our Lead Director since November 2012. Since February 2007, Mr. Frasch has served as President and Chief Merchandising Officer of Saks Fifth Avenue, a division
+of Saks, Incorporated, a NYSE-listed luxury fashion retailer. From November 2004 until January 2007, he held the post of Vice Chairperson and Chief Merchant of Saks Fifth Avenue. From
+January 2004 to November 2004, he was employed by Saks in a non-executive capacity. From
+April 2000 to January 2004, Mr. Frasch served as Chairperson and Chief Executive Officer of Bergdorf Goodman (a subsidiary of Neiman Marcus Group, Inc.) and served as President of GFT
+North America (a subsidiary of Gruppo GFT, based in Turin, Italy, a global 
+4 
+Table of Contents 
+producer,
+marketer and distributor of fine men's and women's clothing, sportswear and furnishings) from 1996 to 2000. Mr. Frasch also served as President and Chief Executive Officer of Escada
+USA from 1994 to 1996. Mr. Frasch has extensive executive expertise in the fashion retail industry, most notably demonstrated by his current position at Saks Fifth Avenue. Mr. Frasch's
+experience and insight into this industry is invaluable to the Board and management in understanding the consumer retail and fashion industry, including current buying trends by our wholesale
+customers. 
+W. Stephen Cannon (Class I), age 61, has served as a member of the Board since February 2009. Since 2005, he has served
+as the Chairperson of Constantine Cannon LLP, a law firm, and the Managing Partner of Constantine Cannon's Washington D.C. office. From 1994 to 2005, Mr. Cannon was the Senior Vice
+President, General Counsel and Secretary of Circuit City Stores, Inc., a retailer of consumer electronics, which, at the time, was publicly traded on the New York Stock Exchange. Prior to
+joining Circuit City Stores, Inc., Mr. Cannon served as a partner at the law firm of Wunder, Diefenderfer, Ryan, Cannon and Thelen and spent ten years in government service, including
+positions at the U.S. Department of Justice and the U.S. Senate Committee on the Judiciary. Mr. Cannon has demonstrated significant legal and business expertise through his role as general
+counsel of Circuit City, a public company with significant retail operations. This experience assists the Board with its risk oversight and retail expansion plans. Mr. Cannon's legal expertise
+also allows him to effectively chair the Nominating and Governance Committee and understand corporate governance and SEC developments. 
+Thomas J. Smach (Class III), age 52, has served as the Chairperson of the Board since June 2011, prior to which he was a
+member of the Board since April 2005. Mr. Smach is currently a co-founding partner of Riverwood Capital Management, a private equity firm. From January 2005 to June 2008,
+Mr. Smach served as the Chief Financial Officer of Flextronics International ("Flextronics"), a NASDAQ-listed electronics manufacturing services (EMS) provider. From April 2000 to December
+2004, Mr. Smach served as Senior Vice President—Finance of Flextronics. From 1997 to April 2000, he served as the Senior Vice President, Chief Financial Officer and Treasurer of The
+Dii Group, Inc., an EMS provider and publicly-traded company that merged with Flextronics in early 2000 ("The Dii Group"). Mr. Smach is a certified public accountant and also serves on
+the Board of Directors of Lighting Science Group Corporation. Mr. Smach has extensive accounting and financial management experience having served as the chief financial officer of global
+public companies. In addition, Mr. Smach has significant experience with international manufacturing and business from his leadership positions at Flextronics. This experience is useful as we
+continue to expand our international operations. Mr. Smach is also well versed in SEC compliance and risk oversight, which makes him particularly well suited to serve as the chairperson of the
+Audit Committee and as the Board's Chairperson. 
+Jeffrey H. Margolis (Class III), age 49, has served as a member of the Board since June 2012. Mr. Margolis
+currently serves as Chairman of the Board and Chief Executive Officer of WellTok, Inc., a healthcare consumer engagement and social media company, and on several private company boards. From
+October 1999 to July 2010, he served as Chairman of the Board and Chief Executive Officer of The TriZetto Group, Inc., a healthcare information technology company, and from August 2010 to
+October 2011, he continued to serve as Chairman of the Board of The TriZetto Group, Inc. Mr. Margolis has extensive leadership and management experience as a founder, executive and
+director of several high growth companies. Mr. Margolis's significant expertise leading technology companies coupled with his entrepreneurial success provides the Board with insight on the role
+of technology in growing the business. Mr. Margolis's finance expertise gained through his board and management roles also makes Mr. Margolis well suited to serve on the Audit Committee. 
+John P. McCarvel (Class III), age 56, has served as our President and Chief Executive Officer and as a director since
+March 2010. Previously, Mr. McCarvel served as our Chief Operating Officer and Executive Vice President from February 2007 to March 2010, as our Senior Vice President—Global 
+5 
+Table of Contents 
+Operations
+from October 2005 to February 2007 and as our Vice President—Asian & Australian Operations from January 2005 to September 2005, after providing consulting services to us
+during 2004. From October 2001 to January 2005, Mr. McCarvel served as Vice President for the Design, Test and Semiconductor division of Flextronics, where he was responsible for building
+Flextronics' engineering infrastructure in Asia and growing Flextronics' business in the region. From 1999 to October 2001, he served as President of U.S. Operations and Senior Vice President of
+Worldwide Sales and Marketing for Singapore Technology Assembly Test Services Ltd., a semiconductor services company. He previously worked in executive level positions with Micron Custom
+Manufacturing Services, Inc., a manufacturer of electronic products for computing and digital applications, and The Dii Group. Mr. McCarvel has served us as an executive since 2005. He
+has been our Chief Operating Officer and has extensive knowledge of our day-to-day operations along with a strategic vision as our Chief Executive Officer.
+Mr. McCarvel's leadership, extensive knowledge of our business and previous manufacturing expertise provide significant value and insights to the Board. 
+CORPORATE GOVERNANCE 
+We
+are committed to maintaining sound corporate governance practices. The Board has formalized several policies, procedures and standards of corporate governance, including our Corporate Governance
+Guidelines, some of which are described below. We continue to monitor best practices and legal and regulatory developments with a view to further revising our governance policies and procedures, as
+appropriate. 
+Corporate Governance Guidelines. Since 2005, the Board has had in place a set of governance guidelines, the Crocs, Inc. Corporate Governance Guidelines,
+which are designed to assure the continued vitality of the Board and excellence in the execution of its duties. Our Corporate Governance Guidelines establish the practices and procedures of the Board
+with respect to board composition and member selection, board independence, board meetings and involvement of senior management, management succession planning, board committees and the evaluation of
+senior management and the Board. The Board periodically reviews our Corporate Governance Guidelines and updates them as necessary to reflect improved corporate governance practices and changes in
+regulatory requirements. A copy of our Corporate Governance Guidelines is available on our website at www.crocs.com. 
+Majority Vote Director Resignation Policy. In addition, our Corporate Governance Guidelines contain a Director Resignation Policy. Under this policy, any nominee
+for director who receives a greater number of votes "withheld" from his or her election than votes "for" such election is required to offer his or her resignation to the Board following certification
+of the stockholder vote. Within 90 days following the certification of the vote, the independent directors on the Board would consider the offer of resignation and determine whether to accept
+or reject the tendered resignation. This policy does not apply in contested elections. 
+Director Independence. NASDAQ listing standards require that the Board consist of a majority of independent directors. The Board has determined that all of the
+current non-management members of the Board (Messrs. Cannon, Croghan, Frasch, Jacobi, Margolis and Smach and Ms. Wright) are independent directors as defined by NASDAQ
+listing standards. The Board makes a determination regarding the independence of each director annually
+based on relevant facts and circumstances. Applying the standards and independence criteria defined by the NASDAQ listing standards, the Board has made a subjective determination as to each
+independent director that no relationships exist which, in the opinion of the Board, would interfere with the exercise of his or her independent judgment in carrying out the responsibilities of a
+director. The independent directors of the Board regularly hold executive sessions without members of management present. 
+6 
+Table of Contents 
+Communicating with Directors. Stockholders who wish to communicate with the Board or with specified individual directors may do so by mailing such written
+communication to: Corporate Secretary, Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503. The Corporate Secretary will review all correspondence and will forward to the Board or
+an individual director a summary of the correspondence received and copies of correspondence that the Corporate Secretary determines requires the attention of the Board or such individual director.
+The Board and any individual director may at any time request copies and review all correspondence received by the Corporate Secretary that is intended for the Board or such individual director. 
+Board Leadership. The Board does not have a policy regarding separation of the roles of Chief Executive Officer and Chairperson of the Board. The Board believes it
+is in our best interests to make that determination based on current circumstances. The Board has determined that an independent director serving as Chairperson is in the best interests of our
+stockholders at this time. This structure ensures a greater role of independent directors in the active oversight of our business, including risk management oversight, and in setting agendas and
+establishing Board priorities and procedures. This structure also allows the Chief Executive Officer to focus to a greater extent on the management of our day-to-day
+operations. 
+In
+addition, in November 2012, the Board named Ron Frasch as its Lead Director. The Lead Director will preside at all meetings of the Board at which the Chairman is not present and will perform other
+duties assigned to him by the Chairman from time to time. 
+Risk Oversight. The Board oversees our risk management activities. The Board implements its risk oversight function both as a whole and through delegation to its
+committees. These committees meet regularly and report back to the full Board. The Audit Committee has primary oversight responsibility with respect to financial risks as well as oversight
+responsibility for our overall risk assessment and risk management policies and systems. The Audit Committee oversees our procedures for the receipt, retention and treatment of complaints relating to
+accounting and auditing matters and oversees our management of legal and regulatory compliance systems. The Compensation Committee oversees risks relating to our compensation plans and programs. The
+Compensation Committee has reviewed and considered our compensation policies and programs in light of the Board's risk assessment and management responsibilities and will do so in the future on an
+annual basis. The Compensation Committee believes that we have no compensation policies and programs that give rise to risks reasonably likely to have a material adverse effect on us. 
+The
+Chief Legal and Administrative Officer serves as our chief compliance officer and chairs an inter-disciplinary Compliance Council which is charged with assessing and managing our legal and other
+compliance obligations on a global basis. The Chief Legal and Administrative Officer regularly reports to the Audit Committee regarding our legal and compliance obligations. 
+The
+Director of Internal Audit coordinates the day-to-day risk management process and reports directly to the Chief Financial Officer and to the Audit Committee. The Director
+of Internal Audit performs a risk assessment annually, and updates the Audit Committee at least quarterly regarding our risk analyses, assessments, risk mitigation strategies and activities. The
+Treasury Director updates the Audit Committee at least annually, or more frequently as needed, regarding our directors and officers insurance coverage and on matters regarding certain financial risks. 
+Code of Business Conduct and Ethics and Committee Charters. We have adopted a Code of Business Conduct and Ethics that applies to all directors and employees,
+including our principal executive, financial and accounting officers. The Amended and Restated Code of Business Conduct and Ethics is posted on our website at www.crocs.com. We intend to satisfy the
+requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of our Code of Business Conduct and Ethics that apply to our
+directors and principal executive, financial and accounting officers 
+7 
+Table of Contents 
+by
+posting such information on our website. The Audit Committee Charter, Compensation Committee Charter, Nominating and Governance Committee Charter and Information Technology Steering Committee
+Charter are also available on our website at www.crocs.com. Any person may request a copy of the Code of Business Conduct and Ethics or committee charters free of charge by submitting a written
+request to: Corporate Secretary, Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503. 
+BOARD OF DIRECTORS AND COMMITTEES OF THE BOARD 
+During
+2012, the Board met six times. All directors attended 75% or more of the Board's meetings and the meetings of the Board committees on which they served, except for Mr. Croghan who
+attended 74%. We encourage, but do not require, our directors to attend the annual meeting of stockholders. Messrs. Cannon, Frasch, Jacobi, Margolis, McCarvel and Smach and Ms. Wright
+attended our 2012 Annual Meeting of Stockholders. 
+Board Committees. The Board has the authority to appoint committees to perform certain management and administrative functions and has established the following
+committees. 
+Audit Committee. Messrs. Smach (Chairperson), Frasch, Cannon and Margolis are the current members of the Audit Committee. The Audit Committee met eight
+times in 2012. The functions of the Audit Committee include oversight of the integrity of our financial statements, our compliance with legal and regulatory requirements, the performance,
+qualifications and independence of our independent auditors and the performance of our internal audit function. The Audit Committee is directly responsible for the appointment, retention,
+compensation, evaluation, termination and oversight of the work of any independent auditor engaged for the purpose of preparing or issuing an audit report or related work.
+The purpose and responsibilities of the Audit Committee are set forth in the Audit Committee Charter. The Audit Committee Charter can be found on our website at www.crocs.com. 
+All
+of the members of the Audit Committee are independent, as determined in accordance with NASDAQ listing standards and relevant federal securities laws and regulations. The Board has determined that
+Mr. Smach qualifies as an "audit committee financial expert" as defined by the applicable regulations of the SEC. 
+Compensation Committee. Ms. Wright (Chairperson), Mr. Croghan and Mr. Jacobi are the current members of the Compensation Committee. The
+Compensation Committee, which met seven times in 2012, has overall responsibility for defining, articulating, evaluating and approving our executive officer compensation, benefits, severance,
+equity-based or other compensation plans, policies and programs. The Compensation Committee is also responsible for approving our Compensation Discussion and Analysis for inclusion in this proxy
+statement. The purpose and responsibilities of our Compensation Committee are set forth in the Compensation Committee Charter, which can be found on our website at www.crocs.com. All of the current
+members of the Compensation Committee are independent, as determined in accordance with NASDAQ listing standards and relevant federal securities laws and regulations. 
+Pursuant
+to its charter, the Compensation Committee has the authority to, among other things: (i) establish, monitor and approve our overall compensation and benefits strategy and philosophy;
+(ii) review and approve annually corporate goals and objectives relevant to the compensation of our Chief Executive Officer, and to approve the Chief Executive Officer's compensation;
+(iii) oversee management's decisions concerning the performance and compensation of other executive officers; (iv) oversee the compensation and benefits structure for our employees
+generally; (v) review and make recommendations to the Board with respect to the establishment of any new incentive compensation 
+8 
+Table of Contents 
+and
+equity-based plans; (vi) supervise the administration of our equity-based incentive plans, including the authorization of equity grants under such plans; (vii) review and recommend
+to the Board the terms of written employment agreements, post-employment consulting agreements and severance arrangements for executive officers; (viii) assist the Board in
+developing and evaluating potential candidates for executive officer positions and oversee the development of succession plans for executive officers; (ix) review and recommend to the Board
+compensation to be paid to our outside directors and (x) review and evaluate the relationship between our incentive compensation arrangements and our corporate strategy and risk management
+policies and practices. 
+The
+Compensation Committee sets the Chief Executive Officer's compensation. The Compensation Committee also reviews the recommendations of the Chief Executive Officer with respect to compensation of
+the other named executive officers and, after reviewing such recommendations, sets the compensation of the other named executive officers. The Compensation Committee relies on its judgment when making
+compensation decisions after reviewing our performance and evaluating each executive's performance against established goals, leadership ability and responsibilities, and current compensation
+arrangements. When evaluating total compensation for each of our executive officers, the Compensation Committee reviews the executive officer's current compensation, including equity and
+non-equity-based compensation. The Compensation Committee also evaluates surveys and other available data regarding the executive compensation programs of comparative companies. The
+compensation program for executive officers and the Compensation Committee assessment process are designed to be flexible so as to better respond to the evolving business environment and individual
+circumstances. See "Risk Oversight" (above) for the Compensation Committee's evaluation of our compensation program risk. 
+In
+2012, the Compensation Committee engaged an outside independent compensation consultant, Towers Watson, to provide an evaluation of the 2012 executive bonus plan, long-term incentives
+and other executive compensation matters. Please see "Compensation Discussion and Analysis" for further description of the role of the Compensation Committee. Towers Watson does not provide any
+services to management and had no prior relationship with management prior to the engagement. The Compensation Committee has reviewed our relationships with Towers Watson and has not identified any
+conflicts of interest. 
+Nominating and Governance Committee. Our Nominating and Governance Committee currently consists of Messrs. Cannon (Chairperson), Frasch and Smach. The
+Nominating and Governance Committee met three times in 2012. The Nominating and Governance Committee assists the Board in promoting our best interests and that of our stockholders through the
+implementation of sound corporate governance principles and practices. In furtherance of this purpose, the Nominating and Governance Committee identifies individuals qualified to become board members
+and recommends to the Board the director nominees for election at each annual meeting of stockholders. It also reviews the qualifications and independence of the members of the Board and its various
+committees and makes any recommendations the Nominating and Governance Committee members may deem appropriate concerning any changes in the composition of the Board and its committees. The Nominating
+and Governance Committee also recommends to the Board the corporate governance guidelines and standards regarding the independence of outside directors applicable to us and reviews the provisions of
+the Nominating and Governance Committee Charter on a regular basis to confirm that such guidelines, standards and charter remain consistent with sound corporate governance practices and with any
+applicable legal or regulatory requirements and the NASDAQ listing standards. The Nominating and Governance Committee also monitors and leads the Board in its annual review of the Board's performance. 
+The
+purpose and responsibilities of our Nominating and Governance Committee are set forth in the Nominating and Governance Committee Charter. The Nominating and Governance Committee Charter 
+9 
+Table of Contents 
+can
+be found on our website at www.crocs.com. All of the members of the Nominating and Governance Committee are independent, as determined in accordance with the NASDAQ listing standards. 
+Information Technology Steering Committee. Our Information Technology Steering Committee (the "IT Steering Committee") currently consists of
+Messrs. McCarvel (Chairperson), Croghan, Margolis and Jacobi and Ms. Wright and met six times in 2012. The IT Steering Committee oversees major information technology ("IT") related
+strategies, projects and technology architecture decisions. The IT Steering Committee also monitors whether our IT programs effectively support our business objectives and strategies and reports to
+the Board on IT related matters. The IT Steering Committee is also tasked with evaluating our significant IT strategies. The purpose and responsibilities of the IT Steering Committee are set forth in
+the IT Steering Committee Charter. The IT Steering Committee Charter can be found on our website at www.crocs.com. 
+Director Nomination Process and Director Qualifications. In identifying potential director candidates, the Nominating and Governance Committee relies on
+recommendations from a number of sources, including current directors and officers. The Nominating and Governance Committee may also hire outside consultants, search firms or other advisors to assist
+in identifying director candidates. The Nominating and Governance Committee will consider director candidates recommended by stockholders on the same basis as it considers other candidates. Any
+stockholder wishing to recommend a candidate for consideration by the Nominating and Governance Committee may do so by submitting a written recommendation to the Nominating and Governance Committee in
+accordance with the procedures set forth under "Stockholder Proposals and Nominations for 2014 Annual Meeting." 
+In
+evaluating a candidate for director, our Nominating and Governance Committee considers, among other things, the candidate's judgment, knowledge, integrity, diversity, expertise and business and
+industry experience, and expertise, which are likely to enhance the Board's ability to govern our affairs and business. We do not have a separate policy regarding consideration of diversity in
+identifying director nominees but the Nominating and Governance Committee strives to nominate directors with a variety of complementary skills and backgrounds so that, as a group, the Board will
+possess a broad perspective and the appropriate talent, skills and expertise to oversee our business. The Nominating and Governance Committee also takes into account independence requirements imposed
+by law or regulations (including the NASDAQ listing standards). In the case of director candidates recommended by stockholders, the Nominating and Governance Committee may also consider the number of
+shares held by the recommending stockholder, the length of time that such shares have been held and the relationship, if any, between the recommending stockholder and the recommended director nominee. 
+EXECUTIVE OFFICERS 
+In
+addition to John McCarvel, our President and Chief Executive Officer, whose biographical information is disclosed above under "Election of Directors," our executive officers as of March 31,
+2013 include the following individuals: 
+Name 
+Age 
+Position(s) 
+Daniel P. Hart 
+54 
+Executive Vice President, Chief Legal and Administrative Officer 
+Jeffrey J. Lasher 
+49 
+Senior Vice President—Finance, Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) 
+Scott E. Crutchfield 
+52 
+Chief Operating Officer 
+Daniel P. Hart has served as our Executive Vice President, Chief Legal and Administrative Officer since January 2010. From June 2009 through December
+2009, he served as our Executive Vice President of Administration and Corporate Development. Prior to joining us, Mr. Hart was employed 
+10 
+Table of Contents 
+by
+Océ North America, a digital printing and document management division of Océ, N.V., a manufacturing and engineering company publicly traded on the Euronext
+Amsterdam stock exchange, where he served as Senior Vice President and General Counsel from 2006 to 2009. From 2004 to 2006, Mr. Hart served as Senior Vice President—General Counsel
+and Human Resources for Invensys Controls, a global manufacturing and engineering operation within Invensys plc, a public U.K. conglomerate. From 2002 to 2004, Mr. Hart served as Chief
+Staff Officer for the Development Division of Invensys, a large portfolio of disposal companies within Invensys plc. Previously, Mr. Hart's experience included service in senior legal
+positions at Dictaphone Corporation and Brooke Group Ltd. and private legal practice in New York City. 
+Jeffrey J. Lasher has served as our Senior Vice President-Finance and Chief Financial Officer since April 2011. From January 2011 to March 2011,
+Mr. Lasher served as our principal accounting officer and interim principal financial officer. From June 2009 to January 2011, he served as our Corporate Controller and Chief Accounting
+Officer. Prior to joining us, Mr. Lasher was a Senior Consultant for Connelly Consulting, a privately-held financial services company, from October 2008 to June 2009. From December
+2005 to September 2008, he was the Vice President—Corporate Controller for Corporate Express Inc., a publicly-held business supplies and equipment company.
+Mr. Lasher was also the Vice
+President—Finance of AutoNation, Inc., a publicly-held automotive retail company, from December 2000 to December 2005. 
+Scott E. Crutchfield has served as our Chief Operating Officer since September 2012 and was our Senior Vice President of World Wide Operations since May
+2010. From February 2006 to May 2010, he served as our Vice President for Worldwide Operations. Prior to joining us, he served as Senior Director, U.S. and South America Operations for Jabil Circuit,
+a publicly-held design and manufacturing company from May 2004 to January 2006. Mr. Crutchfield was also Vice President, General Manager Central/Eastern U.S. and South America for
+Flextronics from March 2000 to April 2004. Previously, Mr. Crutchfield also held senior leadership positions at Dovatron International, a subsidiary of the Dii Group, and at Square D, a
+subsidiary of Schneider Electric. Mr. Crutchfield serves as the Chairman of the Board of Directors of Biostem U.S. Corporation, a hair transplant and regrowth technology company. 
+BENEFICAL OWNERSHIP OF OUR COMMON STOCK 
+Ownership by Our Directors, Executive Officers and Greater than 5% Stockholders 
+The following table sets forth information with respect to the beneficial ownership of our common stock as of March 31, 2013
+by: 
+• each person (or group of affiliated persons) who is known by us to own beneficially more than 5% of our common stock; 
+• each current director or nominee; 
+• each of the named executive officers listed in the Summary Compensation Table below; and 
+• all directors and executive officers as a group. 
+Beneficial
+ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, shares of common stock subject to options or restricted stock units held by that
+person that are currently exercisable, or exercisable (or, in the case of restricted stock units, scheduled to vest and settle) within 60 days after March 31, 2013, are deemed to be
+outstanding and beneficially owned 
+11 
+Table of Contents 
+by
+that person. None of these shares, however, are deemed outstanding for the purpose of computing the percentage ownership of any other person. 
+Except
+as indicated and pursuant to applicable community property laws, each stockholder named in the table has sole voting and investment power with respect to the shares set forth opposite such
+stockholder's name. Percentage ownership is based on 88,102,196 shares of our common stock outstanding on March 31, 2013. Unless otherwise indicated below, the address for each director and
+named executive officer listed below is in care of Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503. 
+Beneficial Ownership 
+Name of Beneficial Owner
+Shares 
+Percent 
+5% Stockholders: 
+Blackrock, Inc. (1) 
+7,171,518 
+8.1% 
+The Vanguard Group, Inc (2) 
+5,378,888 
+6.1% 
+Directors: 
+Peter A. Jacobi (3) 
+47,631 
+* 
+Thomas J. Smach (4) 
+158,414 
+* 
+Raymond D. Croghan (5) 
+53,668 
+* 
+W. Stephen Cannon (6) 
+64,509 
+* 
+Jeffrey H. Margolis (7) 
+11,068 
+* 
+Ronald L. Frasch 
+29,821 
+* 
+Doreen A. Wright 
+9,967 
+* 
+Officers: 
+John P. McCarvel (8) 
+333,219 
+* 
+Daniel P. Hart (9) 
+137,000 
+* 
+Jeffrey J. Lasher (10) 
+84,660 
+* 
+Scott E. Crutchfield (11) 
+117,925 
+* 
+All current directors and executive officers as a group (11 persons) (12) 
+1,047,882 
+1.2% 
+* Less
+than 1%
+(1) Based
+solely on a Schedule 13G/A filed with the SEC on February 8, 2013. The address for Blackrock, Inc. is 40 East
+52 nd Street, New York, New York 10022.
+(2) Based
+solely on a Schedule 13G/A filed with the SEC on February 11, 2013. The address for The Vanguard Group, Inc. is 100
+Vanguard Blvd., Malvern, PA 19355.
+(3) Shares
+beneficially owned include 45,506 shares held in trust by Peter A Jacobi & Mary Louise Jacobi Living Trust.
+(4) Shares
+beneficially owned include 125,109 shares subject to options exercisable within 60 days of March 31, 2013 and 4,400
+shares held as custodian for Mr. Smach's two children under the New York Uniform Gifts to Minors Act. Mr. Smach exercises voting and investment power over the shares.
+(5) Shares
+beneficially owned include an aggregate of 4,960 shares of common stock beneficially owned by two trusts for the benefit of
+Mr. Croghan's two daughters. Mr. Croghan's spouse is the trustee of both trusts and she exercises sole voting and investment power over the shares. Mr. Croghan disclaims
+beneficial ownership of such shares 
+12 
+Table of Contents 
+(6) Shares
+beneficially owned include 64,053 shares held in trust by The W Stephen Cannon Revocable Trust.
+(7) Shares
+beneficially owned consists of 11,068 shares held in trust by the Margolis Family Trust.
+(8) Shares
+beneficially owned include 100,540 shares subject to options exercisable within 60 days of March 31, 2013 and 179,815
+shares held jointly with his spouse.
+(9) Shares
+beneficially owned include 72,915 shares subject to options exercisable within 60 days of March 31, 2013.
+(10) Shares
+beneficially owned include 42,792 shares subject to options exercisable within 60 days of March 31, 2013.
+(11) Shares
+beneficially owned include 76,548 shares subject to options exercisable within 60 days of March 31, 2013.
+(12) Shares
+beneficially owned include 125,109 shares of common stock subject to options issued to directors and 292,795 shares of common stock
+subject to options issued to named executive officers that are exercisable or issuable within 60 days of March 31, 2013. 
+Section 16 Beneficial Ownership and Compliance 
+Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors and executive officers and persons who own more than
+ten percent of our common stock to file with the SEC and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of
+our common stock. 
+To
+our knowledge, based solely on a review of the copies of such reports furnished to us and written representations from certain of our officers and directors that no other reports were required, we
+believe that all required reports of our officers, directors and greater than ten percent stockholders under Section 16(a) were timely filed during the year ended December 31, 2012. 
+CERTAIN RELATIONSHIPS AND RELATED PERSON TRANSACTIONS 
+Related Person Transactions 
+We had no transactions with related persons during 2012 which are required to be disclosed by the rules of the SEC. 
+Policy on Transactions with Related Persons 
+Our Code of Business Conduct and Ethics requires that any transaction involving us in which one of our directors, nominees for director, executive
+officers, or greater than five percent stockholders, or one of the aforementioned's immediate family members (each, a "related person"), have a material interest be approved or ratified by the Audit
+Committee if the amount involved, when aggregated with the amount of all other transactions between the related person and us, exceeds $100,000 in a fiscal year. The full Board reviews ordinary course
+of business transactions in which directors have an interest as part of the Board's annual director independence review, and our Code of Business Conduct and Ethics permits the full Board to waive any
+conflicts of interest between us and any director or officer. In determining whether to approve or ratify any such transaction, the Audit Committee must consider, in addition to other factors it deems
+appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. 
+13 
+Table of Contents 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify certain directors and executive officers in addition to the indemnification provided for in our
+certificate of incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain expenses (including attorneys' fees),
+judgments, fines and settlement amounts incurred by any such person in any action or proceeding, including any action by us or in our right, arising out of such person's services as a director or
+executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request. We believe that these provisions and agreements are necessary
+to attract and retain qualified persons as directors and executive officers. 
+DIRECTOR COMPENSATION 
+In
+June 2012, the Board adjusted the Board committee compensation for non-employee directors, following a review by our Nominating and Governance Committee. The Nominating and Governance
+Committee was assisted in this review by its outside compensation consultant, Towers Watson, which provided advice and perspective regarding peer group practices (using the same companies that were
+used for peer comparisons for executive compensation in 2012) and broader market trends. Directors are compensated with a combination of an annual retainer and fees for serving on committees, paid in
+cash or restricted stock at the director's election, and annual equity grants. Directors who are employees of the Company are not eligible to receive this compensation. Directors do not receive
+additional fees for attendance at meetings. The following describes amounts payable to our non-employee directors under our director compensation program. 
+Retainer Fees. Directors receive an annual retainer fee for Board service of $150,000 for the Chairman of the Board, $130,000 for the Lead Director and $100,000
+for each of our other non-employee directors. Directors who serve as chairpersons of the Audit Committee, the Compensation Committee and the Nominating and Governance Committee receive
+additional annual retainer fees of $50,000, $30,000 and $10,000, respectively. Directors also receive additional annual retainer fees for committee service, as follows: members of the Audit Committee
+receive an additional $20,000, members of the Compensation Committee receive an additional $20,000, members of the Nominating and Governance Committee receive an additional $5,000 and members of the
+IT Steering Committee receive an additional $20,000. These annual retainer fees are denominated in cash and payable in quarterly installments unless the director elects to be paid in shares of
+restricted stock or a combination of cash and restricted stock. The number of shares of restricted stock is determined based on the fair market value of our common stock on the date the retainer is
+payable. The restricted stock vests in four successive quarterly installments from the issuance date. Mr. Cannon elected to receive his annual retainer fees partly in cash and partly in
+restricted stock, and Messrs. Croghan and Jacobi elected to receive all their annual retainer fees in restricted stock. Ms. Wright and Messrs. Frasch, Margolis, and Smach elected
+to receive their annual retainer fees in cash. 
+Equity Awards. Directors receive annual equity awards for Board service consisting of a grant of $150,000 of our common stock for the Chairman of the Board and a
+grant of $100,000 of our common stock for each of our other non-employee directors. The number of shares of common stock was determined based on the fair market value of our common stock
+on the date of grant. The annual equity compensation for the Chairman of the Board also consists of an option to purchase 10,000 shares of our common stock at an exercise price equal to the fair
+market value of the shares on
+the date of grant. This option vests and becomes exercisable in four equal installments on the respective dates of each of the four annual meetings of stockholders following the year of grant. 
+14 
+Table of Contents 
+All
+directors are reimbursed for their reasonable out-of-pocket expenses incurred in attending meetings of the Board and its committees. 
+The
+table below summarizes the total compensation paid to each non-employee directors during the fiscal year ended December 31, 2012. 
+Name 
+Fees Earned or 
+Paid in Cash 
+Stock Awards (1) 
+Option Awards (1) 
+Total 
+W. Stephen Cannon 
+$ 
+100,000 
+$ 
+130,011 
+$ 
+— 
+$ 
+230,011 
+Raymond D. Croghan 
+— 
+240,015 
+— 
+240,015 
+Ronald L. Frasch 
+62,500 
+100,001 
+— 
+162,501 
+Peter A. Jacobi 
+— 
+240,015 
+— 
+240,015 
+Jeffrey H. Margolis (2) 
+70,000 
+100,001 
+— 
+170,001 
+Thomas J. Smach 
+170,000 
+150,001 
+66,471 
+386,472 
+Doreen A. Wright 
+$ 
+137,500 
+$ 
+100,001 
+$ 
+— 
+$ 
+237,501 
+(1) Amounts
+reflect the aggregate grant date fair value of grants computed in accordance with stock-based accounting rules (Financial Standards
+Accounting Board ("FASB") Accounting Standards Codification ("ASC") Topic 718—Stock Compensation), excluding the effect of estimated forfeitures. Assumptions used in to calculate these
+values are included in Note 9 to the Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2012.
+(2) Mr. Margolis
+joined the Board on June 5, 2012. 
+As
+of December 31, 2012, each non-employee director had the following number of stock options and unvested shares of restricted stock outstanding: 
+Options 
+Outstanding at 
+December 31, 2012 
+Unvested Restricted 
+Stock Awards 
+Outstanding at 
+December 31, 2012 
+W. Stephen Cannon 
+— 
+912 
+Raymond D. Croghan 
+— 
+4,250 
+Ronald L. Frasch 
+— 
+— 
+Peter A. Jacobi 
+— 
+4,250 
+Jeffrey H. Margolis 
+— 
+— 
+Thomas J. Smach 
+142,609 
+— 
+Doreen A. Wright 
+— 
+— 
+Director Ownership Guidelines 
+In 2012, we adopted stock ownership guidelines for our directors. The guidelines require that each of our directors own at least 5,000 shares of our
+common stock within the later of three years from (i) adoption of the policy or (ii) within three years of their election to the Board. Each of our directors currently meets these stock
+ownership guidelines. 
+15 
+Table of Contents 
+EXECUTIVE COMPENSATION 
+Compensation Discussion and Analysis 
+This Compensation Discussion and Analysis provides information about our executive compensation program as it relates to the following "named
+executive officers" whose compensation information is presented in the tables and accompanying narratives following this discussion: 
+• John P. McCarvel, Chief Executive Officer and President • Jeffrey J. Lasher, Senior Vice President—Finance and Chief Financial
+Officer • Daniel P. Hart, Executive Vice President, Chief Legal and Administrative Officer 
+• Scott E. Crutchfield, Chief Operating Officer 
+Executive Summary 
+2012 Business Performance. In 2012, we grew revenue by 12.2% to over $1.1 billion. Gross profit increased by 13.3% and diluted earnings per share increased
+by 16.1% in 2012 compared to 2011. The following table highlights the year-over-year comparison of some of our Company's key financial results. 
+($ in millions, except per share amounts) 
+2012 
+2011 
+Change 
+Annual revenues* 
+$ 
+1,123 
+$ 
+1,001 
+12.2% 
+Annual gross profit 
+$ 
+608 
+$ 
+536 
+13.3% 
+Annual selling, general and administrative costs as a % of revenue 
+41.0 
+% 
+40.4 
+% 
+60 bps 
+Diluted earnings per share* 
+$ 
+1.44 
+$ 
+1.24 
+16.1% 
+Annual gross margin 
+54.1 
+% 
+53.6 
+% 
+50 bps 
+Inventory as of December 31* 
+$ 
+165 
+$ 
+130 
+27.1% 
+Cash and cash equivalents as of December 31* 
+$ 
+294 
+$ 
+258 
+14.2% 
+* Indicated
+metrics were used as performance measures in our 2012 incentive plans. 
+During
+the year ended December 31, 2012, revenues increased $122.4 million, or 12.2%, compared to 2011. Revenue growth was driven by increased sales volume and focused improvements on
+average footwear selling prices with new product styles as we continue to transform Crocs brand awareness into an all-season footwear brand. Also during the year ended December 31,
+2012, diluted earnings per share improved to $1.44 compared to $1.24 during 2011. 
+CEO Performance and Compensation. Since being named our Chief Executive Officer in early 2010, John McCarvel has led the Company's turnaround strategy. Highlights
+of the Company's achievements under Mr. McCarvel's leadership include: 
+• Sustained profitable growth in 2012, 2011 and 2010 for the first time since 2007; 
+• Record revenue of $1.1 billion in 2012 exceeding $1 billion for the second year in a row; 
+• Expansion of product offerings, bringing the total number of Crocs shoe styles to more than 300 including sneakers and
+boots, which allows Crocs to become a viable four-season brand; 
+• Opening of 107 new Crocs retail stores net worldwide in 2012 (resulting in a net increase in Crocs stores of 25% over
+2011), as well as increasing online presence so consumers can shop the brand from anywhere; and 
+16 
+Table of Contents 
+• Reinvigoration of our corporate social responsibility platform, Crocs Cares, which focuses on helping to make a difference
+in the lives of children and families in need through initiatives that positively impact the environment, employees and local and global communities. 
+Mr. McCarvel
+has received numerous awards in the past two years in recognition of his leadership and achievements. Mr. McCarvel received the prestigious Stevie Award for turnaround
+executive of the year at the 2011 American Business Awards. In October 2012, Mr. McCarvel was recognized for his achievements as the winner of the retail and product manufacturing category in
+the Denver Business Journal's 2012 Power Book. In addition, he was a finalist for Colorado Biz Magazine's 2012 CEO of the Year award. Most recently, in
+January 2013, Mr. McCarvel received the award of Retail Innovator of the Year from the National Retail Federation in recognition of his work as a retail pioneer. 
+Mr. McCarvel's
+2012 compensation reflects these achievements and our pay for performance philosophy. Mr. McCarvel declined his potential 2012 annual cash incentive award payout.
+Mr. McCarvel received an annual award of 67,500 restricted stock units (at target subject to achievement of an earnings per share growth target and time-based vesting) to provide
+incentive for long-term performance. There was no change to Mr. McCarvel's salary or cash incentive award target in 2012. 
+Corporate Governance Highlights. In order to further align the long-term interests of management with those of our stockholders and align our
+compensation program with best practices, the Compensation Committee (the "Committee") has established the following policies and practices: 
+• Independent Compensation Committee. The Committee,
+comprised solely of independent directors, approves all compensation for our named executive officers. 
+• Independent compensation consultant. The Committee retains
+an independent compensation consultant that does not provide any services to management and that had no prior relationship with management prior to the engagement. The Committee has also determined
+that the independent compensation consultant has no conflicts of interest with our company. 
+• Assessment of compensation risk. The Committee assessed
+our compensation policies and programs and determined that we have no compensation policies and programs that give rise to risks reasonably likely to have a material adverse effect on the Company. 
+• Annual Say-on-Pay vote. We will
+hold annual say-on-pay, or advisory votes to approve executive compensation. 
+• Executive stock ownership guidelines. Our Board adopted
+stock ownership guidelines that our named executive officers are expected to meet within three years. 
+• Clawback policy. Our Board adopted a clawback policy for
+awards made pursuant to our annual cash incentive plan and in 2012 also implemented a clawback policy under which all annual and long-term incentive awards, including those granted in
+2012, are subject to any clawback or recoupment policy adopted by us pursuant to the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act. 
+• No excise tax gross-ups. We do not provide our
+management with "excise tax gross-ups" in the event of a change of control. 
+• No enhanced benefit programs. We do not provide our
+management with pensions, supplemental executive retirement plans or any other enhanced benefit programs beyond those that are typically available to all other employees other than a deferred
+compensation plan for senior executives, which is funded by deferred bonus payments to senior executives. 
+17 
+Table of Contents 
+• Limited perquisites. Our management receives minimal
+perquisites, consisting primarily of health insurance premiums. 
+• No hedging or pledging. We do not allow our management or
+directors to engage in hedging transactions in our stock or to pledge our stock to secure loans or other obligations. 
+Executive Compensation Objectives and Principles 
+The objectives of our executive compensation program are to: 
+• attract and retain exemplary executive talent who are able to succeed in our fast-paced, rapidly evolving
+Company; 
+• hold our executives accountable to stockholders; 
+• motivate our executives to achieve our financial and strategic business objectives; 
+• align our executives' compensation with our stockholders' interests; and 
+• assure that our total compensation program aligns with good corporate governance and best practices. 
+We
+achieve these objectives through implementing the following pay principles. 
+• Fair and
+Competitive: We believe that a fair and competitive pay package for our executives is essential to attract and retain talented
+executives in key positions. 
+• Short and Long-Term
+Incentives: Our compensation program rewards both short-term and long-term performance. Annual cash incentive
+awards are tied to achievement of short-term quantitative performance goals that we believe closely correlate to shareholder value. Long-term performance is rewarded through
+equity-based awards, which align our executives' interests with those of our stockholders. The value of equity awards depends on future share prices, and the realization of the awards is contingent on
+satisfaction of vesting schedules requiring continued service with us and the achievement of performance goals. 
+• Pay for
+Performance: Our executives have a high proportion of variable, performance-based compensation. We aim to tie more than 50% of our
+executive pay to performance metrics. Actual compensation will be above or below targeted levels depending on the level of performance achieved. 
+• Good
+Governance: We have designed our executive compensation program in light of the best practice governance policies and practices
+discussed above under "Corporate Governance Highlights." 
+At
+our annual meeting of stockholders in June 2012, we held our second advisory stockholder vote to approve the compensation of our named executive officers ("say-on-pay"). The
+compensation of our named executive officers reported in our 2012 proxy statement was approved by over 99% of the votes cast at the 2012 annual meeting, similar to the results at our 2011 annual
+meeting. The Committee believes this affirms our stockholders' support of our approach to executive compensation, and the Committee did not change its approach in 2012. The Committee has considered
+and will continue to consider the outcome of our say-on-pay votes when making future compensation decisions for the named executive officers. 
+18 
+Table of Contents 
+Governance of Pay Setting Process 
+Role of Compensation Committee, Chief Executive Officer and Compensation Consultant 
+The Committee has overall responsibility for evaluating and approving our executive officer compensation, benefits, severance, equity-based or other
+compensation plans, policies and programs. The Committee sets the Chief Executive Officer's compensation, and considers the recommendations of the Chief Executive Officer with respect to the
+compensation of the other named executive officers. The Committee works with Towers Watson, an independent executive compensation consultant engaged by the Committee, for advice and perspective
+regarding market trends and best practices. For a more detailed discussion about the Committee, its methodology and the role of consultants, see "Compensation Committee" on page 7. 
+Peer Group Companies 
+The Committee uses peer company and survey data to guide its review of the total compensation of our officers and executives and generally reviews
+the compensation data of our peer companies and industry to understand market competitive compensation. The Committee focuses on ensuring that the performance-based elements of our executive
+compensation program are consistent with peer and industry trends. However, the Committee does not benchmark compensation to a specific percentage of the compensation of peer companies. 
+In
+2012, the Committee approved a revised peer group based on analysis and preliminary recommendations by Towers Watson. The peer group was selected based on the key industry criteria noted below, and
+took into consideration the company's revenue, market capitalization and other key financial metrics. This peer group is comprised of 15 publicly traded companies. As of December 31, 2012, our
+market capitalization was at the 50th percentile of this group and our annual revenue was at the 21st percentile of the group. We believe these companies are broadly comparable to us,
+and represent our labor market for talent for key leadership positions. The Committee will regularly review our peer group to determine if adjustments are necessary to ensure that it continues to be
+relevant or if additional peer companies or groups are necessary to provide appropriate information on market practices and compensation levels. 
+The
+2012 peer companies and the criteria for their inclusion are listed below: 
+Columbia Sportswear Co. 
+G III Apparel Group, Ltd. 
+Skechers USA, Inc 
+Deckers Outdoor Corp. 
+lululemon athletica inc. 
+Steven Madden, LTD 
+DSW Inc. 
+Oxford Industries, Inc. 
+Under Armour, Inc. 
+Fossil, Inc. 
+Perry Ellis International, Inc. 
+Warnaco Group 
+Genesco Inc. 
+Quiksilver, Inc. 
+Wolverine Worldwide, Inc. 
+The
+peer group used in 2012 differs from the peer group used in the 2011 executive compensation review process in the following respects: (i) lululemon athletica inc. and Warnaco Group
+were added and (ii) Shoe Carnival Inc. was deleted. These changes served to make the overall composition of the peer group better reflect our size, complexity, growth prospects, global
+operations, product focus and labor market for executive talent. The Committee intends to continue to monitor how changes in the peer group will impact the peer group information it reviews in making
+its executive compensation decisions. 
+19 
+Table of Contents 
+Elements of Compensation 
+Our executive compensation objectives and principles are implemented through the use of the following principal elements of compensation, each of
+which is discussed more fully below: 
+• Base salary, which provides a fixed level of cash compensation; 
+• Annual cash incentive awards, which motivate and reward annual company performance; 
+• Long-term incentives (in the form of equity awards), which motivate and retain executives by rewarding
+long-term financial performance and tying incentives to the performance of our common stock over the long-term; and 
+• Limited executive benefits and perquisites. 
+The
+Committee does not utilize an exact calculation in determining the break-down or weighting of named executive officer compensation among base salary, annual cash incentive awards and
+long-term equity awards. Rather, the Committee considers all forms of compensation in light of the market competition for executive talent, the risk to an executive inherent in employment
+with our fast-paced, rapidly evolving Company and our financial goals. Accordingly, we believe that over 50% of each named executive officer's compensation should be in the form of annual
+cash performance-based awards and equity awards that vest upon performance. We believe that the total compensation opportunities offered to our executives are sufficient to reduce the need for
+anything other than limited executive perquisites or enhanced benefit programs beyond those that are typically available to all other employees. 
+Base Salary. The Committee establishes base salary for our named executive officers by considering the size of our operations, the responsibilities of the named
+executive officers and the competitive marketplace for executive talent in similar positions. The Committee sets the base salary of the Chief Executive Officer. Base salary for other named executive
+officers is set by the Committee after considering the recommendation of the Chief Executive Officer. 
+Base
+salary is reviewed on an annual basis and at the time of hire or promotion. Annual adjustments are influenced by growth of our operations, revenues and profitability, individual performance,
+changes in responsibility, peer company comparisons and other factors. There was no change to base salary for Messrs. McCarvel and Hart. Messrs. Lasher and Crutchfield received increases
+of 3%. 
+The
+current base salaries of our named executive officers are below: 
+Named Executive Officer 
+2012 Base Salary 
+Increase Over 
+2011 Base Salary 
+John P. McCarvel 
+$ 
+840,000 
+0% 
+Daniel P. Hart 
+$ 
+498,750 
+0% 
+Jeffrey J. Lasher 
+$ 
+334,750 
+3% 
+Scott E. Crutchfield 
+$ 
+334,750 
+3% 
+Annual Incentive Awards. The Committee believes that an annual cash incentive plan that offers significant awards to our named executive officers for meeting or
+exceeding company performance goals provides our officers additional incentive to outperform our peer companies and ensures that we attract and retain talented named executive officers. 
+Each
+year, the Committee establishes a target annual incentive award for each named executive officer expressed as a percentage of the executive's base salary, based on the estimated contribution and 
+20 
+Table of Contents 
+responsibility
+of the individual named executive officer and considering market practices. For 2012, the targets were: 
+Named Executive Officer 
+Annual Incentive Plan Target 
+(as a percentage of Base Salary) 
+John P. McCarvel 
+100 
+% 
+Daniel P. Hart 
+60 
+% 
+Jeffrey J. Lasher 
+60 
+% 
+Scott E. Crutchfield 
+60 
+% 
+The
+total annual incentive award actually paid to each named executive officer is determined based on the extent to which specified weighted objective performance goals are achieved. Each of these
+performance targets has a threshold payout of 75% of the named executive officer's annual incentive award target and a maximum payout of 175% of the target. For 2012, these goals and their applicable
+weightings were: 
+2012 Performance Goal Targets 
+Weighting 
+2012 Actual 
+Performance as 
+a Percentage of 
+Target 
+Annual Revenues: $1,182.9 million 
+20% 
+16.6% 
+Earnings Per Share: $1.48 
+50% 
+0% 
+Inventory Turnover: 3.66 
+15% 
+0% 
+Net unrestricted cash (net of short- and long-term debt): $373.6 million 
+15% 
+0% 
+Based
+on 2012 actual results and applying the weighting described above, our named executive officers were eligible to be paid annual cash incentive awards at up to 16.6% of their respective target
+annual incentive award amounts because our 2012 performance results, in the aggregate, equated to 16.6% of the weighted performance targets. The Committee has discretion to depart from the formula in
+approving the annual incentive awards by decreasing, but not increasing, incentive awards after general results are known. 
+However,
+in keeping with our pay for performance philosophy, our named executive officers informed the Committee that they intended to decline any annual cash incentive award because of the Company's
+overall performance versus plan in 2012. Therefore, the Committee did not award our named executive officers a bonus under the annual incentive plan in 2012. 
+Long-Term Equity Awards. The Committee grants long-term equity awards annually to the named executive officers in order to provide
+long-term performance-based compensation, to encourage the named executive officers to continue their employment throughout the vesting periods of the awards, and to align management and
+stockholder interests. We believe that a significant portion of each named executive officer's compensation should be in the form of equity awards. Each year the Committee considers the number of
+shares to grant and the appropriate type and combination of equity-based awards in making named executive officer grant decisions. 
+2012 Long-Term Performance Incentive Program. In 2012, all of our named executive officers received grants of restricted stock units ("RSUs"), half of
+which vest based on satisfaction of performance goals 
+21 
+Table of Contents 
+and
+half of which vest based on continued service. The material terms of the 2012 restricted stock awards are as follows: 
+Performance Vested RSUs (50% of Award) 
+Time Vested RSUs 
+(50% of Award) 
+Performance Goal 
+Potential Award 
+Further Time Vesting 
+Vest in 3 annual installments beginning one year after the date of grant 
+Achievement of at least 70% of a two-year cumulative earnings per share performance goal 
+Executive may earn from 50% to 200% of the target number of RSUs based on the level of achievement of the performance goal 
+Earned RSUs vest 50% upon satisfaction of performance goal and 50% one year later 
+For
+2012, the amount of restricted stock unit awards granted to the named executive officers was based on a review of the equity compensation of our peer companies, input from the independent
+compensation consultant and the Committee's assessment of each named executive officer's expected future contributions. 
+The
+Committee grants performance-based awards to further demonstrate our pay for performance philosophy and better align the interests of our named executive officers with those of our stockholders.
+The Committee grants restricted stock units because it generally believes that full value awards such as restricted stock units offer a stronger retention incentive than do stock options. In addition,
+restricted stock units are less dilutive to our current stockholders and to the Company's 2007 Amended and Restated Equity Incentive Plan than are stock options, as fewer restricted stock units are
+necessary to provide the same equity benefit compared to stock options. The Committee selected cumulative earnings per share as the performance metric because it views cumulative earnings per share as
+a primary driver of enhanced stockholder value. 
+Other Benefits. We provide other benefits to our named executive officers in order to achieve a competitive pay package. The Committee believes that those
+benefits, which are detailed in the Summary Compensation Table under the heading "All Other Compensation," are reasonable, competitive and consistent with our overall executive compensation program.
+Those benefits consist principally of employer-paid premiums on health insurance. 
+Post-Employment Compensation 
+Senior Executive Deferred Compensation Plan. Certain senior executives are eligible to participate in the 2007 Senior Executive Deferred Compensation Plan (the
+"Deferred Compensation Plan"), which permits executives to defer all or a part of their cash compensation and save for future financial needs. No named executive officers have contributed to the
+Deferred Compensation Plan since 2008. For a more detailed discussion of the Deferred Compensation Plan, see the Nonqualified Deferred Compensation table and accompanying narrative on page 23. 
+Severance and Change in Control Benefits. We entered into an employment agreement with Mr. Hart concurrent with his appointment as an officer in 2009. The
+agreement provides for guaranteed payments and accelerated vesting of certain equity awards upon his involuntary termination of employment with us (other than for cause) or his resignation for good
+reason. For a more detailed discussion of the agreement, see Potential Payments on Termination or Change in Control beginning on page 23. 
+22 
+Table of Contents 
+Additional Considerations 
+Executive Stock Ownership. In March 2012, the Committee adopted stock ownership guidelines to ensure that our senior executive officers have a meaningful stake in
+the equity of the Company and to further align the interests of our executives with the long-term interests of our stockholders.
+Under these guidelines, our Chief Executive Officer is required to hold 10,000 shares of our common stock and the other named executive officers are required to hold 5,000 shares. The ownership
+guidelines assume that, in normal circumstances, an executive can reach the requisite stock ownership within the later of three years from (i) the adoption of the guidelines or (ii) the
+date the executive's employment commences. These ownership guidelines are based on analysis of peer and market practices, as prepared by the Committee's independent compensation consultant. Each of
+our named executive officers currently meets these stock ownership guidelines. 
+Equity Granting Practices. The Committee has determined to make our annual equity award grants at the regular meeting of the Committee held in the first quarter of
+each year. The Committee meeting date, or the next business day if the meeting falls on a day where the Nasdaq is closed for trading, is the effective grant date for the grants. For stock options, the
+exercise price is the fair market value of our common stock on that date. 
+We
+also may grant equity awards (e.g., options, restricted stock) to recognize increased responsibilities or special contributions, attract new hires, retain executives or recognize certain
+other special circumstances that occur throughout the year. The effective date of these grants is determined based on the timing of the recognition or recruitment event and approved on or in advance
+of the effective date of the grant. The exercise/grant price is the fair market value of our common stock on the effective date. The Committee approves all equity grants to executive officers. We do
+not permit repricing of stock options without stockholder approval. 
+Clawbacks. In 2010, our Compensation Committee adopted a clawback policy for awards made under our annual incentive plan. Under this policy, at the discretion of
+the Committee, executives may be required to repay awards to us if within two years of the award: (i) we are required to restate our financial statements due to fraud or willful misconduct
+involving the executive; or (ii) the executive took part in any fraud, negligence or breach of fiduciary duty. 
+In
+2012, our Board also adopted a policy whereby any incentive compensation awards granted to management, including annual and long-term incentive awards granted in 2012, will be subject
+to any clawback or recoupment policy adopted by the Company pursuant to the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act. 
+Deductibility of Executive Compensation. Section 162(m) of the Code imposes a $1.0 million annual limit on the amount that a public company may
+deduct for compensation paid to the company's chief executive officer during a tax year or to any of the company's four other most highly compensated executive officers who are still employed at the
+end of the tax year. The limit does not apply to compensation that meets the requirements of the Code for "qualified performance-based"
+compensation (i.e., compensation paid only if the executive meets pre-established, objective goals based on performance criteria approved by the company's stockholders). 
+The
+Committee reviews and considers the deductibility of executive compensation under Section 162(m) of the Code. In certain situations, the Committee may approve compensation that does not
+meet the requirements of the Code in order to ensure competitive levels of total compensation for our executive officers. The annual incentive awards paid in 2012 under our 2008 Cash Incentive Plan
+and the performance-vested restricted stock units granted in 2012 are designed to meet the requirements for consideration as "qualified performance-based compensation" under Section 162(m). 
+23 
+Table of Contents 
+COMPENSATION COMMITTEE REPORT 
+The
+Compensation Committee has reviewed and discussed the foregoing Compensation Discussion and Analysis with our management. Based on such review and discussion, the Compensation Committee
+recommended to the Board that the foregoing Compensation Discussion and Analysis be included in this proxy statement. 
+THE
+COMPENSATION COMMITTEE 
+Doreen A. Wright (Chairperson) 
+Raymond D. Croghan 
+Peter A. Jacobi 
+Summary Compensation Table 
+The following table sets forth information regarding compensation earned for services rendered during fiscal years 2012 and 2011, and, where
+applicable 2010 for our Chief Executive Officer, our Chief Financial Officer, and the two other most highly compensated executive officers who were serving as executive officers at the end of 2012. 
+Name and Principal Position 
+Year 
+Salary 
+($) 
+Stock 
+Awards (1) 
+($) 
+Option 
+Awards (1) 
+($) 
+Non-Equity 
+Incentive Plan 
+Compensation (2) 
+($) 
+All Other 
+Compensation (3) 
+($) 
+Total 
+($) 
+John P. McCarvel 
+2012 
+$ 
+840,000 
+$ 
+1,313,550 
+$ 
+— 
+$ 
+— 
+$ 
+32,203 
+$ 
+2,185,753 
+President and Chief Executive Officer 
+2011 
+828,333 
+2,349,981 
+— 
+1,285,200 
+15,015 
+4,478,529 
+2010 
+766,667 
+831,723 
+— 
+800,000 
+233,451 
+2,631,841 
+Daniel P. Hart 
+2012 
+498,750 
+462,175 
+— 
+— 
+29,883 
+990,808 
+Executive Vice President, Chief Legal 
+2011 
+491,823 
+475,019 
+— 
+450,000 
+14,606 
+1,431,448 
+and Administrative Officer 
+2010 
+475,000 
+296,298 
+— 
+339,150 
+41,403 
+1,151,851 
+Jeffrey J. Lasher (4) 
+2012 
+332,313 
+462,175 
+— 
+— 
+32,260 
+826,748 
+Senior Vice President—Finance 
+2011 
+300,000 
+1,078,320 
+266,802 
+300,000 
+14,606 
+1,959,728 
+and Chief Financial Officer 
+Scott E. Crutchfield (5) 
+2012 
+332,313 
+462,175 
+— 
+— 
+32,957 
+827,445 
+Chief Operating Officer 
+2011 
+$ 
+325,000 
+$ 
+350,009 
+$ 
+— 
+$ 
+240,000 
+$ 
+15,106 
+$ 
+930,115 
+(1) Amounts
+reflect the aggregate grant date fair value of grants made in each respective fiscal year computed in accordance with stock-based
+accounting rules (FASB ASC Topic 718-Stock Compensation), excluding the effect of estimated forfeitures. Assumptions used in the calculations of these amounts are included in Note 9
+to our Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2012. The grant date fair value of stock awards, which are
+comprised of time-vested and performance-vested restricted stock units, includes the grant date fair value for the performance-vested restricted stock units calculated based on the target
+amount for the award period commencing in the year indicated. For 2012, the total aggregate grant date fair value of stock awards, including the time-vested restricted stock units and the
+performance-vested restricted stock units assuming the highest level of payout for performance against assigned targets would be as follows: $1.97 million for Mr. McCarvel and
+$0.7 million for Messrs. Hart, Lasher, and Crutchfield.
+(2) In
+2012, our named executive officers did not receive a cash bonus under our annual incentive plan.
+(3) All
+other compensation for 2012 represents the following: (i) Company matches to employee 401(k) contributions in the amounts of
+$10,000 for Mr. Hart, $13,200 for Mr. Lasher and $13,015 for Mr. Crutchfield, (ii) a $12,800 car allowance for Mr. McCarvel, (iii) $14,145 in incremental
+healthcare premiums paid by us on behalf of each named executive officer that is not offered to other non-executive employees, (iv) group term life insurance premiums
+paid-in full by the Company for each named executive officer and (v) certain recognition gifts made to the named executive officers.
+(4) Mr. Lasher
+was appointed as our Senior Vice President-Finance and Chief Financial Officer effective April 28, 2011. During
+2010, he served as our Corporate Controller and Chief Accounting Officer.
+(5) Mr. Crutchfield
+was appointed as our Chief Operating Officer in September 2012 and previously served as our Senior Vice President for
+Worldwide Operations. 
+24 
+Table of Contents 
+Grants of Plan-Based Awards Table 
+The following table provides information for each of our named executive officers regarding annual and long-term incentive award
+opportunities, including the range of potential payouts under our non-equity annual incentive plan and our performance-vested restricted stock units granted during fiscal year 2012. 
+Estimated Future 
+Payouts Under 
+Non-Equity Incentive 
+Plan Awards 
+Estimated Future 
+Payouts Under 
+Equity Incentive 
+Plan Awards 
+All Other 
+Stock Awards: 
+Number of 
+Shares of 
+Stock or 
+Units (#) 
+Grant Date 
+Fair Value 
+of Stock 
+and Option 
+Awards (1) 
+Name 
+Type of Award 
+Grant 
+Date 
+Target 
+($) 
+Maximum 
+($) 
+Threshold 
+(#) 
+Target 
+(#) 
+Maximum 
+(#) 
+John P. McCarvel 
+Annual Incentive Award 
+$ 
+840,000 
+$ 
+1,147,000 
+— 
+— 
+— 
+— 
+$ 
+— 
+Restricted Stock Unit 
+3/14/12 
+— 
+— 
+16,875 
+33,750 
+67,500 
+33,750 
+1,313,550 
+Daniel P. Hart 
+Annual Incentive Award 
+299,250 
+523,688 
+— 
+— 
+— 
+— 
+— 
+Restricted Stock Unit 
+3/14/12 
+— 
+— 
+5,938 
+11,875 
+23,750 
+11,875 
+462,175 
+Jeffrey J. Lasher 
+Annual Incentive Award 
+200,850 
+351,488 
+— 
+— 
+— 
+— 
+— 
+Restricted Stock Unit 
+3/14/12 
+— 
+— 
+5,938 
+11,875 
+23,750 
+11,875 
+462,175 
+Scott E. Crutchfield 
+Annual Incentive Plan 
+200,850 
+351,488 
+— 
+— 
+— 
+— 
+— 
+Restricted Stock Units 
+3/14/12 
+$ 
+— 
+$ 
+— 
+5,938 
+11,875 
+23,750 
+11,875 
+$ 
+462,175 
+(1) The
+aggregate grant date fair value for the restricted stock units was calculated based on the target number of restricted stock units. 
+Annual Incentive Awards. The amounts shown for annual incentive awards represent the target and maximum amounts of annual cash incentive compensation that,
+depending on performance results, might have been paid to each executive for 2012 performance based on achievement of specified target levels of sales growth, earnings per share, inventory turnover
+and net unrestricted cash. The target payments were based on achieving the target level of performance with ranges from zero to 175% of the executive's annual incentive target. No amounts were paid
+based on 2012 performance as reflected in the "Non-Equity Incentive Plan Compensation" column of the "Summary Compensation Table" set forth above. These awards are described in further
+detail under "Compensation Discussion and Analysis" above. 
+Restricted Stock Units ("RSUs"). The amounts shown for RSUs represent the number of RSUs awarded to the executives in 2012 and the grant date fair value of the
+RSUs determined in accordance with
+FASB ASC 718, as follows. The amounts shown for RSUs granted on March 14, 2012 represent awards of restricted stock units to certain of our named executive officers as part of a performance
+incentive plan. One-half of these RSUs vest in three equal annual installments beginning one year after the date of grant based on continued employment. The other half may be earned from
+50% to 200% of the target number of RSUs based on the level of achievement of a two-year cumulative earnings per share performance goal, and vest in two equal annual installments, 50% on
+certification of the achievement of performance goal by the Compensation Committee and 50% one year later subject to continued employment. These RSU awards are described in further detail under
+"Compensation Discussion and Analysis" above. 
+Employment Agreement with Mr. Hart. In May 2009, we entered into an employment agreement with Mr. Hart. The agreement provides that Mr. Hart
+will receive an annual base salary of $475,000, subject to annual adjustments. His salary may be reduced only if such reduction is a uniformly applied reduction affecting all senior executives and is
+no greater than 10% of Mr. Hart's base pay in any case, may not be reduced by greater than $47,500 in total during his employment with us. Mr. Hart is also eligible for a bonus pursuant
+to our annual incentive plan. Mr. Hart's target under the annual incentive plan was 60% of his base pay in 2012. He is also entitled to participate in all employee benefit plans and programs
+generally available to our executives, including our Senior Executive Plan. The agreement also contains provisions relating to benefits Mr. Hart may receive in connection with a change in
+control or a termination of his employment, as described in further detail under "Potential Payments 
+25 
+Table of Contents 
+on
+Terminations or Change in Control." Mr. Hart's Agreement requires him to maintain confidential information regarding us and to assign certain inventions and intellectual property to us.
+During his employment with us and for twelve months after the termination of his employment with us, Mr. Hart will be restricted from participating in certain competitive businesses and from
+soliciting our employees and customers. 
+Salary and Bonus in Proportion to Total Compensation. As noted in "Compensation Discussion and Analysis" above, we believe that a substantial portion of each named
+executive officer's compensation should be in the form of performance-based annual incentive awards and equity awards. Base salary of the named executive officers is set at levels that the
+Compensation Committee believes are competitive with our peer companies, with the expectation that shortfalls in base pay, if any, will be recouped through performance bonuses. The Compensation
+Committee believes that our current program substantially aligns the compensation of our named executive officers with the compensation of executive officers of our peer companies, while also
+permitting the Compensation Committee to provide incentives to the named executive officers to pursue performance that increases stockholder value. Please see "Compensation Discussion and Analysis"
+for a description of the objectives of our compensation program and overall compensation philosophy. 
+Outstanding Equity Awards at Fiscal Year-End 
+The following table sets forth information regarding outstanding options and unvested restricted stock and restricted stock unit awards held by our
+named executive officers as of December 31, 2012. Market values for outstanding stock awards are presented as of the end of 2012 based on the closing price of our common stock on the NASDAQ
+Global Select Market on December 31, 2012 of $14.39. 
+Option Awards 
+Stock Awards 
+Name 
+Number of 
+Securities 
+Underlying 
+Unexercised 
+Options (#) 
+Exercisable 
+Number of 
+Securities 
+Underlying 
+Unexercised 
+Options (#) 
+Unexercisable 
+Option 
+Exercise 
+Price 
+($) 
+Option 
+Expiration 
+Date 
+Number of 
+Shares or 
+Units of 
+Stock That 
+Have Not 
+Vested (#) 
+Market Value 
+of Shares or 
+Units of 
+Stock That 
+Have Not 
+Vested ($) 
+Equity Incentive 
+Plan Awards: 
+Number of 
+Unearned 
+Shares, Units or 
+Other Rights 
+That Have Not 
+Vested (#) (1) 
+Equity 
+Incentive Plan 
+Awards: 
+Market or 
+Payout Value of 
+Unearned 
+Shares, Units 
+or Other 
+Rights That 
+Have Not 
+Vested (#) 
+John P. McCarvel 
+80,454 
+— 
+$ 
+1.14 
+11/17/2018 
+94,775 
+(2) 
+$ 
+1,363,812 
+95,104 
+(2) 
+$ 
+1,368,547 
+35,086 
+— 
+10.50 
+02/07/2016 
+— 
+— 
+— 
+— 
+Daniel P. Hart 
+58,333 
+25,000 
+(3) 
+3.99 
+06/15/2019 
+24,281 
+(4) 
+349,404 
+33,618 
+(4) 
+483,763 
+Jeffrey J. Lasher 
+12,500 
+17,500 
+(5) 
+20.11 
+04/29/2021 
+40,003 
+(6) 
+575,643 
+25,063 
+(6) 
+360,657 
+23,000 
+5,000 
+(7) 
+3.99 
+06/15/2019 
+— 
+— 
+— 
+— 
+Scott E. Crutchfield 
+33,000 
+— 
+1.14 
+11/17/2018 
+20,890 
+(8) 
+300,607 
+27,645 
+(8) 
+397,812 
+43,548 
+— 
+$ 
+10.50 
+02/07/2016 
+— 
+$ 
+— 
+— 
+$ 
+— 
+(1) The
+aggregate number of restricted stock units was calculated based on the achievement of target performance.
+(2) Represents
+the unvested portion of four restricted stock grants for: (i) 70,485 shares awarded on June 15, 2010 of which 35,243
+shares vest ratably on each of the first four anniversaries of the grant date based on continued employment and the remaining 35,242 shares vest on a cliff basis on the fourth anniversary of the grant
+date based on continued employment and provided certain corporate performance metrics are achieved; (ii) 52,224 restricted stock units awarded on June 28, 2011 of which
+one-half of the restricted stock units vest in three equal annual installments on June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and up
+to one half of the restricted stock units based on target performance vest in two equal annual installments on the date in 2013 that the achievement of certain performance metrics is established and
+one year from that date, respectively, based on continued employment; (iii) 38,986 restricted stock units awarded on June 29, 2011 which will vest in equal installments on the next three
+grant date anniversaries, based on continued employment; and (iv) 67,500 restricted stock units awarded on March 14, 2012 of which one-half of the restricted stock units vest
+in three equal annual installments on March 14, 2013, March 14, 2014 and March 14, 2015 based on continued employment and up to one-half of the restricted stock units
+based on target performance vest in two equal annual installments on the date in 2014 that the achievement of certain performance metrics is established and one year from that date, respectively,
+based on continued employment. 
+26 
+Table of Contents 
+(3) Represents
+the unvested portion of a stock option to purchase 200,000 shares of common stock, which was granted on June 15, 2009. This
+stock option vests over four years with 25% vesting on the first anniversary of the grant date and the remaining options vesting in 36 equal monthly installments thereafter, based on continued
+employment.
+(4) Represents
+the unvested portion of three restricted stock grants for: (i) 25,110 shares awarded on June 15, 2010 of which half
+vest ratably on each of the first four anniversaries of the grant date based on continued employment and the remaining half vest on a cliff basis on the fourth anniversary of the grant date based on
+continued employment and provided certain corporate performance metrics are achieved; (ii) 18,376 restricted stock units awarded on June 28, 2011 of which one-half of the
+restricted stock units vest in three equal installments on June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and up to one-half of the
+restricted stock units based on target performance vest in two equal annual installments on the date in 2013 that the achievement of certain performance metrics is established and one year from that
+date, respectively, based on continued employment; and (iii) 23,750 restricted stock units awarded on March 14, 2012 of which one-half of the restricted stock units vest in
+three equal annual installments on March 14, 2013, March 14, 2014 and March 14, 2015 based on continued employment and up to one-half of the restricted stock units
+based on target performance vest in two equal annual installments on the date in 2014 that the achievement of certain performance metrics is established and one year from that date, respectively,
+based on continued employment.
+(5) Represents
+the unvested portion of stock options to purchase 30,000 shares of common stock, which were granted on April 29, 2011. This
+stock option award has a four year vesting period with 25% vesting on the first anniversary of the grant date and the remaining options vesting in 36 equal monthly installments thereafter, based on
+continued employment.
+(6) Represents
+the unvested portion of four restricted stock grants for: (i) 8,000 shares awarded on August 2, 2010 of which half
+vest ratably on June 15, 2011, June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and the remaining half vest on a cliff basis on June 15,
+2014, based on continued employment and provided certain corporate performance metrics are achieved; (ii) 30,000 shares granted on April 29, 2011 which vest annually in equal
+installments on the next three grant date anniversaries, based on continued employment; (iii) 18,376 restricted stock units awarded on June 28, 2011 of which one-half of the
+restricted stock units vest in three equal installments on June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and up to one-half of the
+restricted stock units based on target performance vest in two equal annual installments on the date in 2013 that the achievement of certain performance metrics is established and one year from that
+date, respectively, based on continued employment; and (iv) 23,750 restricted stock units awarded on March 14, 2012 of which one-half of the restricted stock units vest in
+three equal annual installments on March 14, 2013, March 14, 2014 and March 14, 2015 based on continued employment and up to one-half of the restricted stock units
+based on target performance vest in two equal annual installments on the date in 2014 that the achievement of certain performance metrics is established and one year from that date, respectively,
+based on continued employment.
+(7) Represents
+the unvested portion of stock options to purchase 40,000 shares of common stock, which were granted on June 15, 2009. This
+stock option award has a four year vesting period with 25% vesting on the first anniversary of the grant date and the remaining options vesting in 36 equal monthly installments thereafter, based on
+continued employment.
+(8) Represents
+the unvested portion of three restricted stock grants for: (i) 18,000 shares awarded on August 2, 2010 of which half
+vest ratably on June 15, 2011, June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and the remaining half vest on a cliff basis on June 15,
+2014, based on continued employment and provided certain corporate performance metrics are achieved; (ii) 13,540 restricted stock units awarded on June 28, 2011 of which
+one-half of the restricted stock units vest in three equal installments on June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and up to
+one-half of the restricted stock units based on target performance vest in two equal annual installments on the date in 2013 that the achievement of certain performance metrics is
+established and one year from that date, respectively, based on continued employment; and (iii) 23,750 restricted stock units awarded on March 14, 2012 of which one-half of
+the restricted stock units vest in three equal annual installments on March 14, 2013, March 14, 2014 and March 14, 2015 based on continued employment and up to
+one-half of the restricted stock units based on target performance vest in two equal annual installments on the date in 2014 that the achievement of certain performance metrics is
+established and one year from that date, respectively, based on continued employment. 
+Options Exercises and Stock Vested 
+The following table sets forth information for each of our named executive officers regarding stock options exercised and stock awards vested during
+2012. 
+Option Awards 
+Stock Awards 
+Name 
+Number of 
+Shares Acquired 
+on Exercise 
+(#) 
+Value 
+Realized on 
+Exercise 
+($) (1) 
+Number of 
+Shares Acquired 
+on Vesting 
+(#) 
+Value 
+Realized on 
+Vesting 
+($) (1) 
+John P. McCarvel 
+45,000 
+$ 
+308,250 
+30,506 
+$ 
+494,248 
+Daniel P. Hart 
+— 
+— 
+56,199 
+912,672 
+Jeffrey J. Lasher 
+2,000 
+17,145 
+27,394 
+481,779 
+Scott E. Crutchfield 
+— 
+$ 
+— 
+4,505 
+$ 
+73,161 
+(1) For
+option awards, the value realized is the difference between the fair market value of our common stock at the time of exercise and the
+exercise price. For stock awards, the value realized is based on the closing price of our common stock on the vesting date. 
+27 
+Table of Contents 
+Nonqualified Deferred Compensation 
+Under our Deferred Compensation Plan, participants have the option to defer all or a part of their cash compensation in accordance with the terms and
+conditions established by the Compensation Committee. The deferred amount will vest ratably on a quarterly basis over a three-year period, with a pro rata amount vesting on each calendar
+quarter. Any unvested balance will vest immediately upon the death or disability of the participant or upon a Change in Control, as defined in the plan. None of the named executive officers have
+deferred any compensation since 2008. The table below summarizes the 2012 accrued earnings and balances at December 31, 2012 under our Deferred Compensation Plan for each of the named executive
+officers. 
+Name 
+Executive 
+Contributions 
+in Last Fiscal 
+Year 
+$ 
+Registrant 
+Contributions 
+in Last Fiscal 
+Year 
+$ 
+Aggregate 
+Earnings in 
+Last Fiscal 
+Year (1) 
+$ 
+Aggregate 
+Withdrawals/ 
+Distributions 
+$ 
+Aggregate 
+Balance at 
+Last Fiscal 
+Year End 
+$ 
+John P. McCarvel 
+$ 
+— 
+$ 
+— 
+$ 
+76,510 
+$ 
+— 
+$ 
+810,705 
+Daniel P. Hart 
+— 
+— 
+— 
+— 
+— 
+Jeffrey J. Lasher 
+— 
+— 
+— 
+— 
+— 
+Scott E. Crutchfield 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+(1) Each
+participant in the Deferred Compensation Plan may choose, at his or her discretion, a portfolio of investments in which their
+contributions may be hypothetically invested. We are not obligated to invest the participant's contributions into these accounts; however, upon the participant's withdrawal, we are obligated to pay
+the amount, inclusive of earnings, interest, and capital gains, that the participant's contributions would have earned had we actually invested the money as the participant directed. The aggregate
+earnings on each individual's contribution varies widely depending on the portfolio of investments the participant chooses. We received investment direction from Mr. McCarvel and the aggregate
+earnings from those hypothetical investments are reflected in the table above. 
+Potential Payments on Terminations or Change in Control 
+Mr. Hart's employment agreement provides certain benefits in the event of a change of control or certain terminations of employment. No other
+named executive officer currently has an employment agreement. Mr. Hart's employment agreement provides that in the event of a change in control, all unvested stock options and
+time-based unvested stock awards then held by Mr. Hart that are scheduled to vest over the 24 months following the change in control will immediately vest upon the effective
+date of the change in control. The potential incremental value of such acceleration, assuming the change in control was effective as of December 31, 2012 and that the price of our common stock
+was the closing price of $14.39 on that date, would have been $0.7 million. The agreement also provides that if Mr. Hart is terminated by us involuntarily without cause, or if he resigns
+for good reason, he will receive: (i) a lump sum payment equal to one year of his base pay as of the termination date; (ii) a lump sum payment equal to 80% of his base pay in effect as
+of the termination date, pro-rated to equal the proportion of the year that he was employed by us; (iii) a lump sum payment equal to 80% of his base pay as of the termination date;
+and (iv) immediate vesting of any unvested stock options or time-based unvested stock awards then held by him that would have been vested had he remained employed for
+24 months after the termination date. The potential aggregate amount of such payments, assuming such termination occurred on December 31, 2012 and including the potential incremental
+value of the equity acceleration as described above, would have been $2.0 million. These amounts are estimates of the incremental amounts that would be payable as of December 31, 2012
+under Mr. Hart's agreement in the foregoing circumstances. The actual amounts that would be payable in similar circumstances in the future can only be determined at the time of a change in
+control or his 
+28 
+Table of Contents 
+termination
+of employment under certain circumstances. The agreement also provides that any stock options granted to Mr. Hart during his employment will remain exercisable for ten years after
+the date of grant, including if Mr. Hart ceases to be employed by us for any reason other than termination for cause. 
+Under
+Mr. Hart's employment agreement, "cause," "change of control" and "good reason" are defined as follows: 
+"Cause"
+is defined by the agreement to mean: (i) the executive's conviction, or guilty or no contest plea, to any felony; (ii) any act of fraud by the executive related to or connected
+with the executive's employment by the Company; (iii) the executive's material breach of his fiduciary duty to the Company; (iv) the executive's gross negligence or gross misconduct in
+the performance of duties reasonably assigned to the executive which causes material harm to the Company; (v) any willful and material violation by the executive of the Company's codes of
+conduct or other rules or policies of the
+Company; (vi) any entry of any court order or other ruling that prevents the executive from performing his material duties and responsibilities hereunder; or (vii) any willful and
+material breach of the agreement by the executive. 
+"Change
+of control" is generally defined by the agreement to mean any one of the following: (i) incumbent directors (including those nominees subsequently nominated or elected by incumbent
+directors) cease to constitute a majority of the members of the Board; (ii) any person becomes the beneficial owner of 35% or more of our common stock or voting securities, with certain
+exceptions; (iii) consummation of a merger unless (a) after the merger the beneficial owners of our common stock and voting securities immediately prior to the trans action retain more
+than 50% of such common stock and voting securities of the entity resulting from the merger, (b) holders of any class or series of voting securities immediately prior to the merger have the
+right to receive substantially the same per share consideration in exchange for their voting securities, and (c) no person immediately after the merger beneficially owns 35% or more of the
+voting power of the entity resulting from the merger; (iii) a sale or other disposition of all or substantially all of the assets of the Company (in one transaction or a series of
+transactions); or (iv) stockholder approval of the liquidation or dissolution the Company, except that a change of control will not be deemed to occur unless it would be deemed to constitute a
+change in ownership or effective control, or a change in the ownership of a substantial portion of the assets, of a business under Section 409A of the Code. 
+"Good
+reason" is defined by the agreement to mean any of the following conditions arising during the executive's term of employment without the consent of the executive: (i) a material
+diminution in the executive's responsibilities, authority, position, or duties; (ii) a reduction in the executive's base salary (except as provided for in the agreement); (iii) a
+reduction in the executive's incentive or equity compensation opportunity such that it is materially less favorable than those provided generally to other senior executive officers; (iv) the
+Company's material failure to honor its incentive compensation plans, as then in effect; (v) assignment of duties or responsibilities materially inconsistent with those described in the
+agreement; (vi) removal from the position of Executive Vice President of Administration and Corporate Development of the Company or its successor; (vii) any change in the executive's
+reporting responsibility being solely to the Chief Executive Officer; (viii) relocation of the executive's office or the Company 50 miles or more from the place of relocation agreed between the
+executive and Chief Executive Officer; or (ix) any other action or inaction that constitutes a material breach by the Company of the agreement. 
+29 
+Table of Contents 
+REPORT OF THE AUDIT COMMITTEE 
+The
+Audit Committee has reviewed and discussed the audited financial statements for the fiscal year ended December 31, 2012 with our management and Deloitte & Touche LLP, our
+independent registered public accounting firm. Management is responsible for the preparation, presentation and integrity of the financial statements, accounting and financial reporting principles and
+internal control over financial reporting. Deloitte & Touche LLP is responsible for performing an independent audit of the financial statements in accordance with generally accepted
+auditing standards and for expressing opinions on the conformity of the financial statements with accounting principles generally accepted in the United States. 
+The
+Audit Committee has discussed with Deloitte & Touche LLP the matters required to be discussed by Statement on Auditing Standards No. 61, as amended, Communication With Audit Committees , and the Public Company Accounting Oversight Board ("PCAOB") AU Section 380, Communications with Audit Committees , and has received the written disclosures and the letter from
+Deloitte & Touche LLP required by
+applicable requirements of the PCAOB regarding the independent auditor's communications with the Audit Committee concerning independence. The Audit Committee has also discussed with Deloitte &
+Touche LLP their independence. 
+Based
+on its reviews and discussions referred to above, the Audit Committee recommended to the Board that the audited financial statements be included in our Annual Report on
+Form 10-K for the year ended December 31, 2012 for filing with the SEC. 
+The
+Audit Committee: 
+Thomas
+J. Smach (Chairperson) 
+Ronald L. Frasch 
+W. Stephen Cannon 
+Jeffrey H. Margolis 
+INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+The
+following table sets forth the aggregate fees for professional services provided during 2012 and 2011 by Deloitte & Touche LLP, our independent registered public accounting firm, and
+its affiliates. The Audit Committee is required to pre-approve all audit and non-audit services provided by Deloitte & Touche LLP. All of the fees paid to
+Deloitte & Touche LLP and disclosed in the following table were pre-approved by the Audit Committee. 
+2012 
+2011 
+Audit fees (1) 
+$ 
+1,911,663 
+$ 
+1,882,800 
+Audit-related fees 
+— 
+— 
+Tax fees (2) 
+349,314 
+644,463 
+All other fees 
+— 
+— 
+Total fees 
+$ 
+2,260,977 
+$ 
+2,527,263 
+(1) Audit
+fees relate to professional services rendered in connection with the audit of our annual financial statements and internal control over
+financial reporting, both of which are included in our Annual Report on Form 10-K and services attendant to, or required by, statute or regulation, such as: (i) consents and
+other audit services related to SEC and other regulatory filings; (ii) accounting consultation related to the audit; and (iii) statutory audit requirements in foreign countries.
+(2) Tax
+fees include professional services rendered in connection with tax compliance, tax advice, tax consulting and tax planning. 
+30 
+Table of Contents 
+PROPOSAL 2—RATIFICATION OF THE APPOINTMENT OF INDEPENDENT REGISTERED 
+PUBLIC ACCOUNTING FIRM 
+The
+Audit Committee has appointed Deloitte & Touche LLP as the independent registered public accounting firm for the fiscal year ending December 31, 2013. Deloitte &
+Touche LLP has served as our independent public accounting firm since 2005. We are not required to submit this appointment to the stockholders for approval, but the Board believes it is
+desirable as a matter of policy. We expect that a representative of Deloitte & Touche LLP will attend the Annual Meeting and will have the opportunity to make any statements if he or she
+so desires and to respond to appropriate stockholder questions. 
+If
+the stockholders do not ratify this appointment, the Audit Committee will investigate the reasons for the rejection and consider other independent registered public accounting firms. Even if the
+appointment is ratified, the Audit Committee may, in its discretion, appoint a different independent registered public accounting firm. 
+THE BOARD RECOMMENDS A VOTE "FOR" THE RATIFICATION OF DELOITTE & TOUCHE LLP AS THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR FISCAL YEAR
+2013. 
+PROPOSAL 3—ADVISORY VOTE TO APPROVE THE COMPENSATION OF OUR 
+NAMED EXECUTIVE OFFICERS 
+Pursuant
+to Section 14A of the Securities Exchange Act of 1934, our stockholders have an opportunity to cast a non-binding advisory vote to approve the compensation of our named
+executive officers as disclosed in this proxy statement. This proposal, commonly known as a "Say on Pay" proposal, gives stockholders the opportunity to approve or reject our executive pay program.
+Accordingly, we ask our stockholders to vote "FOR" the following resolution at the Annual Meeting: 
+"RESOLVED,
+that the stockholders approve, on an advisory basis, the compensation of our named executive officers, as disclosed pursuant to Item 402 of Regulation S-K,
+including the Compensation Discussion and Analysis, the compensation tables and any other related disclosure in this proxy statement." 
+As
+discussed in the "Compensation Discussion and Analysis," the primary objective of our executive compensation program is to create long-term value for our stockholders by attracting and
+retaining talented executives, holding our executives accountable to stockholders, motivating our executives to achieve superior financial and business objectives and aligning the interests of our
+executives with those of our stockholders. We believe our executive compensation strikes the appropriate balance between utilizing responsible, measured pay practices and effectively incentivizing our
+named executive officers to dedicate themselves fully to value creation for our stockholders. Please see "Compensation Discussion and Analysis" section above for an explanation of our executive
+compensation. 
+This
+"Say on Pay" proposal allows our stockholders to express their view regarding the decisions of the Compensation Committee on the 2012 compensation of our named executive officers. Your advisory
+vote will serve as a tool to guide the Board and the Compensation Committee in continuing to improve the alignment of our executive compensation programs with the objective of creating
+long-term value for our stockholders. 
+Our
+current policy is to provide stockholders with an opportunity to approve the compensation of our named executive officers each year at the annual meeting of stockholders until the next required 
+31 
+Table of Contents 
+stockholder
+vote on the frequency of such votes. It is expected that the next such frequency vote will occur at the 2017 annual meeting of stockholders. 
+THE BOARD RECOMMENDS A VOTE "FOR" THE ADVISORY VOTE TO APPROVE THE COMPENSATION OF OUR NAMED EXECUTIVE OFFICERS. 
+OTHER MATTERS 
+We
+do not intend to bring before the Annual Meeting any matters other than the proposals specifically described above, and we know of no matters other than those to come before the Annual Meeting. If
+any other matters properly come before the Annual Meeting, it is the intention of the persons named in the accompanying proxy to vote such proxy in accordance with the recommendation of our management
+on such matters, including any matters dealing with the conduct of the Annual Meeting. 
+STOCKHOLDER PROPOSALS AND NOMINATIONS FOR 2014 ANNUAL MEETING 
+Any proposal of a stockholder intended to be included in our proxy statement for the 2014 annual meeting of stockholders pursuant to SEC
+Rule 14a-8, must be received by us no later than December 18, 2013, unless the date of our 2014 annual meeting is more than 30 days before or after June 12,
+2014, in which case the proposal must be received a reasonable time before we begin to print and mail our proxy materials. All proposals should be addressed to the Corporate Secretary,
+Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503. 
+In
+order for a stockholder to nominate a candidate for director for election or to bring other business before the 2014 annual meeting, we must receive timely notice of the nomination or business in
+writing by the close of business not later than March 18, 2014 and not earlier than February 16, 2014. However, in the event that the 2014 annual meeting is called for a date that is not
+within 30 days before or 60 days after June 12, 2014, notice by the stockholder to be timely must be delivered not earlier than the close of business on the 120th day prior
+to such annual meeting and not later than the close of business on the later of the 90th day prior to such annual meeting or the 10th day following the date on which public announcement
+of the date of the 2014 annual meeting is made. 
+32 
+1 1 12345678
+12345678 12345678 12345678 12345678 12345678 12345678 12345678 000000000000
+NAME THE COMPANY NAME INC. - COMMON 123,456,789,012.12345 THE COMPANY NAME
+INC. - CLASS A 123,456,789,012.12345 THE COMPANY NAME INC. - CLASS B
+123,456,789,012.12345 THE COMPANY NAME INC. - CLASS C 123,456,789,012.12345
+THE COMPANY NAME INC. - CLASS D 123,456,789,012.12345 THE COMPANY NAME INC. -
+CLASS E 123,456,789,012.12345 THE COMPANY NAME INC. - CLASS F
+123,456,789,012.12345 THE COMPANY NAME INC. - 401 K 123,456,789,012.12345 . x
+02 0000000000 JOB # 1 OF 2 1 OF 2 PAGE SHARES CUSIP # SEQUENCE # THIS PROXY
+CARD IS VALID ONLY WHEN SIGNED AND DATED. KEEP THIS PORTION FOR YOUR RECORDS
+DETACH AND RETURN THIS PORTION ONLY TO VOTE, MARK BLOCKS BELOW IN BLUE OR
+BLACK INK AS FOLLOWS: Signature (Joint Owners) Signature [PLEASE SIGN WITHIN
+BOX] Date Date CONTROL # SHARES To withhold authority to vote for any
+individual nominee(s), mark “For All Except” and write the number(s) of the
+nominee(s) on the line below. 0 0 0 0 0 0 0 0 0 0000172678_1 R1.0.0.51160 For
+Withhold For All All All Except The Board of Directors recommends you vote
+FOR the following: 1. Election of Directors Nominees 01 Raymond D. Croghan 02
+Peter A. Jacobi 03 Doreen A. Wright CROCS, INC. ATTN: CORPORATE SECRETARY
+7477 EAST DRY CREEK PARKWAY NIWOT, CO 80503 Investor Address Line 1 Investor
+Address Line 2 Investor Address Line 3 Investor Address Line 4 Investor
+Address Line 5 John Sample 1234 ANYWHERE STREET ANY CITY, ON A1A 1A1 VOTE BY
+INTERNET - www.proxyvote.com Use the Internet to transmit your voting
+instructions and for electronic delivery of information up until 11:59 P.M.
+Eastern Time the day before the cut-off date or meeting date. Have your proxy
+card in hand when you access the web site and follow the instructions to
+obtain your records and to create an electronic voting instruction form.
+ELECTRONIC DELIVERY OF FUTURE PROXY MATERIALS If you would like to reduce the
+costs incurred by our company in mailing proxy materials, you can consent to
+receiving all future proxy statements, proxy cards and annual reports
+electronically via e-mail or the Internet. To sign up for electronic
+delivery, please follow the instructions above to vote using the Internet
+and, when prompted, indicate that you agree to receive or access proxy
+materials electronically in future years. VOTE BY PHONE - 1-800-690-6903 Use
+any touch-tone telephone to transmit your voting instructions up until 11:59
+P.M. Eastern Time the day before the cut-off date or meeting date. Have your
+proxy card in hand when you call and then follow the instructions. VOTE BY
+MAIL Mark, sign and date your proxy card and return it in the postage-paid
+envelope we have provided or return it to Vote Processing, c/o Broadridge, 51
+Mercedes Way, Edgewood, NY 11717. The Board of Directors recommends you vote
+FOR proposals 2 and 3. For Against Abstain 2 Ratification of the appointment
+of Deloitte & Touche LLP as our independent registered public accounting
+firm for fiscal year 2013. 3 An advisory vote to approve the compensation of
+our named executive officers. NOTE: Such other business as may properly come
+before the meeting or any adjournment thereof. Please sign exactly as your
+name(s) appear(s) hereon. When signing as attorney, executor, administrator,
+or other fiduciary, please give full title as such. Joint owners should each
+sign personally. All holders must sign. If a corporation or partnership,
+please sign in full corporate or partnership name, by authorized officer. 
+0000172678_2
+R1.0.0.51160 Important Notice Regarding the Availability of Proxy Materials
+for the Annual Meeting: The Notice & Proxy Statement, 2012 Annual Report
+is/are available at www.proxyvote.com . CROCS, INC. Annual Meeting of
+Stockholders June 12, 2013 2:00 PM This proxy is solicited by the Board of
+Directors The undersigned hereby appoints John McCarvel and Daniel P. Hart
+and each of them, with power of substitution, as proxies of the undersigned,
+to attend the Annual Meeting of Stockholders of Crocs, Inc. (the
+"Company"), to be held at the St. Julien Hotel, 900 Walnut Street,
+Boulder, Colorado, on June 12, 2013 at 2 p.m. Mountain Time, and all
+adjournments thereof, and to vote, as indicated on the reverse side, the
+shares of Common Stock of the Company which the undersigned is entitled to vote
+with all the powers the undersigned would possess if present at the meeting.
+THIS PROXY, WHEN PROPERLY EXECUTED, WILL BE VOTED AS DIRECTED HEREIN BY THE
+UNDERSIGNED STOCKHOLDER(S). IF NO SPECIFIC DIRECTIONS ARE GIVEN, THIS PROXY
+WILL VOTED FOR ALL NOMINEES LISTED AND "FOR" PROPOSALS 2 AND 3.
+PLEASE MARK, SIGN, DATE AND RETURN THIS PROXY CARD PROMPTLY USING THE
+ENCLOSED REPLY ENVELOPE. Continued and to be signed on reverse side
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001047469-13-004482/proxy_rpt.txt b/raw/proxies/0001334036/0001047469-13-004482/proxy_rpt.txt
new file mode 100644
index 0000000000000000000000000000000000000000..cb097520fec7b843c392791b18c70937d4d3b539
--- /dev/null
+++ b/raw/proxies/0001334036/0001047469-13-004482/proxy_rpt.txt
@@ -0,0 +1,18 @@
+CERTAIN RELATIONSHIPS AND RELATED PERSON TRANSACTIONS 
+Related Person Transactions 
+We had no transactions with related persons during 2012 which are required to be disclosed by the rules of the SEC. 
+Policy on Transactions with Related Persons 
+Our Code of Business Conduct and Ethics requires that any transaction involving us in which one of our directors, nominees for director, executive
+officers, or greater than five percent stockholders, or one of the aforementioned's immediate family members (each, a "related person"), have a material interest be approved or ratified by the Audit
+Committee if the amount involved, when aggregated with the amount of all other transactions between the related person and us, exceeds $100,000 in a fiscal year. The full Board reviews ordinary course
+of business transactions in which directors have an interest as part of the Board's annual director independence review, and our Code of Business Conduct and Ethics permits the full Board to waive any
+conflicts of interest between us and any director or officer. In determining whether to approve or ratify any such transaction, the Audit Committee must consider, in addition to other factors it deems
+appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. 
+13 
+Table of Contents 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify certain directors and executive officers in addition to the indemnification provided for in our
+certificate of incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain expenses (including attorneys' fees),
+judgments, fines and settlement amounts incurred by any such person in any action or proceeding, including any action by us or in our right, arising out of such person's services as a director or
+executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request. We believe that these provisions and agreements are necessary
+to attract and retain qualified persons as directors and executive officers.
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001047469-14-004292/proxy.txt b/raw/proxies/0001334036/0001047469-14-004292/proxy.txt
new file mode 100644
index 0000000000000000000000000000000000000000..024b6869bb06e0de2bd196051f7a2201152f1a1d
--- /dev/null
+++ b/raw/proxies/0001334036/0001047469-14-004292/proxy.txt
@@ -0,0 +1,2192 @@
+DEF 14A
+1
+a2219903zdef14a.htm
+DEF 14A
+Use these links to rapidly review the document 
+TABLE OF CONTENTS 
+Table of Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+SCHEDULE 14A 
+Proxy
+Statement Pursuant to Section 14(a) of 
+the Securities Exchange Act of 1934 (Amendment No. ) 
+Filed by the Registrant ý 
+Filed by a Party other than the Registrant o 
+Check the appropriate box: 
+o 
+Preliminary Proxy Statement 
+o 
+Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2)) 
+ý 
+Definitive Proxy Statement 
+o 
+Definitive Additional Materials 
+o 
+Soliciting Material under §240.14a-12 
+CROCS, INC. 
+(Name of Registrant as Specified In Its Charter) 
+(Name of Person(s) Filing Proxy Statement, if other than the Registrant) 
+Payment of Filing Fee (Check the appropriate box): 
+ý 
+No fee required. 
+o 
+Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11. 
+(1) 
+Title of each class of securities to which transaction applies: 
+(2) 
+Aggregate number of securities to which transaction applies: 
+(3) 
+Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined): 
+(4) 
+Proposed maximum aggregate value of transaction: 
+(5) 
+Total fee paid: 
+o 
+Fee paid previously with preliminary materials. 
+o 
+Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration
+statement number, or the Form or Schedule and the date of its filing. 
+(1) 
+Amount Previously Paid: 
+(2) 
+Form, Schedule or Registration Statement No.: 
+(3) 
+Filing Party: 
+(4) 
+Date Filed: 
+Table of Contents 
+CROCS, INC. 
+7477 East Dry Creek Parkway 
+Niwot, Colorado 80503 
+NOTICE OF THE 2014 ANNUAL MEETING OF STOCKHOLDERS 
+TO BE HELD JUNE 10, 2014 
+To the Stockholders of Crocs, Inc.: 
+We
+will hold the 2014 Annual Meeting of Stockholders of Crocs, Inc. at the St. Julien Hotel, 900 Walnut Street, Boulder, Colorado, on June 10, 2014 at 11:00 a.m. Mountain
+Time. 
+The
+meeting's purpose is to: 
+1. elect
+two Class III directors;
+2. ratify
+the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for fiscal year 2014;
+3. hold
+an advisory vote to approve the compensation of our named executive officers; and
+4. consider
+any other matters that properly come before the meeting or any postponement or adjournment thereof. 
+Only
+stockholders of record of our common stock and Series A convertible preferred stock at the close of business on April 15, 2014 are entitled to receive notice of and to vote at the
+meeting. 
+A
+list of the stockholders entitled to vote at the meeting will be available for examination at the meeting by any stockholder for any purpose relevant to the meeting. The list will also be available
+on
+the same basis for ten days prior to the meeting at our principal executive office, 7477 East Dry Creek Parkway, Niwot, Colorado 80503. 
+All
+stockholders are cordially invited to attend the meeting in person. Whether or not you plan to attend the meeting in person, please vote your shares as instructed in the Notice of Internet
+Availability of Proxy Materials, over the Internet, or by telephone after your receipt of hard copies of the proxy materials, as promptly as possible. You may also request a paper proxy card, which
+will include a reply envelope, to submit your vote by mail, as described in the Notice of Internet Availability of Proxy Materials. Stockholders of record who are present at the Annual Meeting may
+withdraw their proxy and vote in person if they so desire. 
+BY ORDER OF THE BOARD OF DIRECTORS 
+Daniel P. Hart 
+Executive Vice President, Chief Legal and Administrative Officer 
+Niwot,
+Colorado 
+April 29, 2014 
+Table of Contents 
+TABLE OF CONTENTS 
+Page 
+Proxy Statement 
+1 
+General Information Regarding Annual
+Meeting 
+1 
+Proposal 1—Election of Directors 
+3 
+Corporate Governance 
+7 
+Board of Directors and Committees of the
+Board 
+9 
+Executive Officers 
+12 
+Beneficial Ownership of our
+Securities 
+13 
+Certain Relationships and Related Person
+Transactions 
+16 
+Director Compensation 
+18 
+Executive Compensation 
+20 
+Compensation Committee Report 
+29 
+Report of the Audit Committee 
+36 
+Independent Registered Public Accounting
+Firm 
+37 
+Proposal 2—Ratification of the Appointment of
+Independent Registered Public Accounting Firm 
+37 
+Proposal 3—Advisory Vote to Approve the
+Compensation of our Named Executive Officers 
+38 
+Other Matters 
+39 
+Table of Contents 
+CROCS, INC. 
+7477 East Dry Creek Parkway 
+Niwot, Colorado 80503 
+2014 ANNUAL MEETING OF STOCKHOLDERS 
+PROXY STATEMENT 
+This
+proxy statement will first be made available to stockholders on or about April 29, 2014. It is furnished to stockholders of Crocs, Inc., a Delaware corporation ("we," "us," or
+"our"), in connection with the solicitation of proxies by our Board of Directors. The proxies being solicited will be voted at the 2014 Annual Meeting of Stockholders (the "Annual Meeting"), to be
+held on June 10, 2014 at the St. Julien Hotel, 900 Walnut Street, Boulder, Colorado at 11:00 a.m. Mountain Time, or at any postponement or adjournment thereof, for the purpose of
+voting on the proposals as set forth herein as well as other business matters which may properly come before the meeting. 
+Under
+the rules of the Securities and Exchange Commission (the "SEC"), we are furnishing proxy materials to our stockholders on the Internet, rather than mailing printed copies. If you received a
+Notice of Internet Availability of Proxy Materials by mail, you will not receive a printed copy of the proxy materials unless you request one as instructed in that notice. Instead, the Notice of
+Internet Availability of Proxy Materials will instruct you as to how you may access and review the proxy materials on the Internet. This proxy statement and our 2013 annual report to stockholders are
+available at www.proxyvote.com. 
+GENERAL INFORMATION REGARDING ANNUAL MEETING 
+Record Date and Voting. Stockholders of record of our common stock and our Series A convertible preferred stock (our "convertible preferred stock") at the
+close of business on April 15, 2014 are entitled to notice of, and to vote at, the Annual Meeting. On the record date, there were 87,594,981 shares of our common stock outstanding, for
+aggregate votes of 87,594,981 (or one vote per share), and there were 200,000 shares of our convertible preferred stock outstanding, for aggregate votes of 13,793,100 (or 68.9655 votes per share,
+which number is equal to the number of shares of common stock into which each such share of convertible preferred stock is convertible on the record date). Our common stock and convertible preferred
+stock will vote together as a single class, for aggregate votes of 101,388,081 on all matters at the Annual Meeting. 
+Quorum Requirements. A quorum is required to conduct business at the Annual Meeting. The holders of a majority of the voting power of the outstanding shares
+entitled to vote generally in the election of directors must be present in person or by proxy at the Annual Meeting in order for a quorum to exist. Abstentions and broker non-votes count as present
+for purposes of determining a quorum. A broker non-vote occurs when a broker returns a proxy card but does not vote on one or more matters because the broker does not have the authority to do so
+without instructions from the 
+1 
+Table of Contents 
+beneficial
+owner. Shares represented by proxies that are marked withhold with respect to the election of our Class III directors will be counted as present in determining whether there is a
+quorum. 
+Vote Requirements. If a quorum is present at the Annual Meeting, the following vote is required for approval of each matter to be voted on. 
+Election of Directors. The two Class III director nominees receiving the highest number of "for" votes cast in person or by proxy at
+the Annual Meeting will be elected as directors. Proxies marked withhold and broker non-votes will have no effect on the outcome of this proposal. Cumulative voting is not permitted. See "Corporate
+Governance—Majority Vote Director Resignation Policy" (below) regarding director nominees who receive a greater number of votes "withheld" from their election than votes "for" such
+election. 
+Ratification of Appointment of Deloitte & Touche LLP. The affirmative vote of a majority of the voting power of the shares
+present in person or by proxy and entitled to vote on the proposal is required for the ratification of the appointment of Deloitte & Touche LLP as our independent registered public
+accounting firm for fiscal year 2014. Abstentions will have the effect of voting against this proposal. Broker non-votes will have no effect on the outcome of this proposal. 
+Advisory Vote to Approve Named Executive Officer Compensation. The affirmative vote of a majority of the voting power of the shares present
+in person or by proxy and entitled to vote on the proposal is required to approve the advisory resolution to approve the compensation of our named executive officers. Abstentions will have the effect
+of voting against this proposal. Broker non-votes will have no effect on the outcome of this proposal. 
+Approval of all Other Proposals. With respect to any other matters properly brought before the Annual Meeting, the affirmative vote of a
+majority of the voting power of the shares present in person or by proxy and entitled to vote on such proposals will be the act of the stockholders. Abstentions will have the effect of voting against
+these proposals. Broker non-votes will have no effect on the outcome of these proposals. 
+Board Recommendations. Our Board of Directors' recommendation is set forth together with the description of each proposal. In summary, our Board of Directors
+recommends a vote: 
+• FOR election of each of the Class III director nominees (see
+Proposal 1); 
+• FOR the ratification of the appointment of Deloitte &
+Touche LLP as our independent registered public accounting firm for our fiscal year ending December 31, 2014 (see Proposal 2); and 
+• FOR the advisory vote to approve the compensation of our named executive
+officers as disclosed in this proxy statement (see Proposal 3). 
+Your Proxy. Whether or not you are able to personally attend the Annual Meeting, you are encouraged to vote your shares as instructed in
+the Notice of Internet Availability of Proxy Materials. Shares represented by properly executed methods, and not revoked prior to the Annual Meeting, will be voted at the Annual Meeting as directed in
+the proxy. If no directions are specified, such proxies will be voted FOR each of the proposals described in this proxy statement and in the best judgment of the proxy holders
+as to other matters that may properly come before the Annual Meeting. 
+If
+your shares are held in the name of a bank or brokerage firm, your bank or broker will send you a separate package describing the procedures and options for voting your shares. You should follow
+the instructions provided by your bank or brokerage firm. On routine matters, such as the ratification of the appointment of our independent registered public accounting firm, your broker will vote
+your shares for you at his or her discretion if you do not instruct your broker how to vote. For non-routine 
+2 
+Table of Contents 
+matters,
+which include all other matters to be voted upon at the Annual Meeting, your broker may not vote your shares without specific voting instructions from you. 
+Revocation. Any stockholder giving a proxy has the power to revoke the proxy, or change the proxy, at any time before the proxy is voted at the Annual Meeting by
+(i) re-voting online at www.proxyvote.com, (ii) sending another properly executed proxy bearing a later date or a written notice of revocation of the proxy to Corporate Secretary,
+Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503 or (iii) voting in person at the Annual Meeting. 
+Cost of Proxy Solicitation. Our Board of Directors is soliciting the proxies. We will bear the entire cost of this proxy solicitation. We have retained the
+services of Georgeson, Inc., a professional proxy solicitation firm, to aid in the solicitation of proxies. Georgeson, Inc. may solicit proxies by personal interview, mail, telephone,
+facsimile, email or otherwise. We will pay Georgeson, Inc. its customary fee, estimated to be approximately $20,000, plus reasonable out-of-pocket expenses incurred in the process of soliciting
+proxies. We may also reimburse brokers, custodians, nominees and other fiduciaries for normal handling charges incurred for forwarding proxy materials to beneficial owners. Solicitation of proxies may
+be made personally or by mail or telephone by our directors, officers and other employees, who will receive no additional compensation for such services. 
+PROPOSAL 1—ELECTION OF DIRECTORS 
+Our
+Board of Directors (the "Board") currently consists of eight members divided into three classes, with each director elected to a three-year term. Class I consists of Ronald L. Frasch and
+Gregg S. Ribatt, whose terms will expire at the annual meeting to be held in 2015. Class II consists of Raymond D. Croghan, Peter A. Jacobi and Doreen A. Wright, whose terms will expire at the
+annual meeting to be held in 2016. Class III consists of Thomas J. Smach, Prakash A. Melwani and John P. McCarvel,
+whose terms will expire at the Annual Meeting, except for Mr. McCarvel, whose resignation from his position as our President, Chief Executive Officer and director will become effective on
+April 30, 2014. As such, Mr. McCarvel has not been nominated for re-election at the Annual Meeting. Under our amended and restated bylaws, each of our directors holds office until his or
+her successor has been elected and qualified or until such director's earlier resignation or removal. 
+On
+January 27, 2014, we issued to Blackstone Capital Partners VI L.P. ("Blackstone") and certain of its permitted transferees, an aggregate of 200,000 shares of our convertible preferred
+stock for an aggregate purchase price of $198 million, or $990 per share, pursuant to an Investment Agreement between us and Blackstone, dated December 28, 2013 (as amended, the
+"Investment Agreement"). The Investment Agreement grants Blackstone certain rights to designate directors to serve on the Board. For so long as Blackstone and its permitted transferees
+(i) beneficially own at least 95% of the convertible preferred stock or the as-converted common stock purchased pursuant to the Investment Agreement or (ii) maintain beneficial ownership
+of at least 12.5% of our outstanding common stock (the "Two-Director Threshold"), Blackstone will have the right to designate for nomination two directors to the Board. For so long as Blackstone and
+its permitted transferees beneficially own shares of convertible preferred stock or the as-converted common stock purchased pursuant to the Investment Agreement that represent less than the
+Two-Director Threshold but more than 25% of the number of shares of the as-converted common stock purchased pursuant to the Investment Agreement, Blackstone will have the right to designate for
+nomination one director to the Board. 
+Effective
+January 27, 2014, two prior members of the Board, W. Stephen Cannon and Jeffrey H. Margolis, resigned from the Board, and the Board appointed Messrs. Melwani and Ribatt to
+serve as a Class III director and a Class I director, respectively, to fill the vacancies on the Board resulting from the resignations of Messrs. Cannon and Margolis.
+Messrs. Melwani and Ribatt were designated by 
+3 
+Table of Contents 
+Blackstone
+for election to the Board in accordance with the terms of the Investment Agreement. Blackstone has designated Mr. Melwani for nomination for re-election as a Class III
+director at the Annual Meeting. 
+At
+each annual meeting of stockholders, the successors to directors whose terms expire at such meeting will be elected, or such directors will be re-elected, and will serve from the time of election
+and qualification until the third annual meeting following their election or until their successors are duly elected and qualified. The current authorized number of directors is eight. The authorized
+number of directors may be changed by resolution of the Board, subject to the terms of the Investment Agreement and the certificate of designations of the convertible preferred stock. Any additional
+directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of the directors.
+Vacancies on the Board can be filled by resolution of the Board. 
+Upon
+the recommendation of the Nominating and Governance Committee, the Board has nominated Messrs. Smach and Melwani for re-election as Class III directors to serve for a three-year
+term expiring at the 2017 annual meeting of stockholders. 
+A
+stockholder cannot vote for more than two nominees. Each of the director nominees has consented to serve for a three-year term. We do not contemplate that any of the nominees will be unable to stand
+for election, but should any nominee become unable to serve or will not serve for any reason, all proxies (except proxies marked to the contrary) will be voted for the election of a substitute nominee
+as the Board may recommend. 
+Class III Director Nominees 
+Thomas J. Smach (Class III) , age 53, has served as the Chairperson of
+the Board since June 2011, prior to which he was a member of the Board since April 2005. Mr. Smach is currently a co-founding partner of Riverwood Capital Management, a private equity firm.
+From January 2005 to June 2008, Mr. Smach served as the Chief Financial Officer of Flextronics International ("Flextronics"), a NASDAQ-listed electronics manufacturing services (EMS) provider.
+From April 2000 to December 2004, Mr. Smach served as Senior Vice President—Finance of Flextronics. From 1997 to April 2000, he served as the Senior Vice President, Chief Financial
+Officer and Treasurer of The Dii Group, Inc., an EMS provider and publicly-traded company that merged with Flextronics in early 2000 ("The Dii Group"). Mr. Smach also served on the Board
+of Directors of Lighting Science Group Corporation from 2012 until February 2014. Mr. Smach is a certified public accountant. Mr. Smach has extensive accounting and financial management
+experience having served as the chief financial officer of global public companies. In addition, Mr. Smach has significant experience with international manufacturing and business from his
+leadership positions at Flextronics. This experience is useful as we continue to expand our international operations. Mr. Smach is also well versed in SEC compliance and risk oversight, which
+makes him particularly well suited to serve as the chairperson of the Audit Committee and as the Board's Chairperson. 
+Prakash A. Melwani (Class III) , age 55, is a Blackstone director designee and has served as a member of the Board since
+January 2014. Mr. Melwani is a Senior Managing Director at Blackstone Group, L.P. and is based in New York. He is the Chief Investment Officer of the Private Equity Group and chairs each
+of its Investment Committees. Since joining Blackstone in 2003, Mr. Melwani has led Blackstone's investments in Kosmos Energy, Foundation Coal, Texas Genco, Ariel Re, Pinnacle Foods, RGIS
+Inventory Specialists and Performance Food Group. Before joining Blackstone, Mr. Melwani was a founding partner of Vestar Capital Partners and served as its Chief Investment Officer. Prior to
+that, he was with the management buyout group at The First Boston Corporation and with N.M. Rothschild & Sons in Hong Kong and London. Mr. Melwani received a First Class Honors degree in
+Economics from Cambridge University, England, and an MBA with High Distinction from the Harvard Business 
+4 
+Table of Contents 
+School,
+where he graduated as a Baker Scholar and a Loeb Rhodes Fellow. Mr. Melwani serves as a Director of Acushnet Company, Kosmos Energy, Performance Food Group, Pinnacle Foods, RGIS
+Inventory Specialists and Blackstone strategic partner, Patria. Mr. Melwani's significant knowledge and expertise in finance, business, and strategic investments provide a valuable perspective
+to the Board. In addition, Mr. Melwani brings to the Board extensive leadership experience through his service on the boards of various companies, including other public companies in the
+consumer goods industry. 
+THE BOARD RECOMMENDS A VOTE "FOR" EACH OF THE ABOVE-NAMED NOMINEES FOR DIRECTOR. 
+Information About Continuing Directors 
+Ronald L. Frasch (Class I) , age 65, has served as a member of the
+Board since October 2006 and as our Lead Director since November 2012. Since February 2014, Mr. Frasch has served as Operating Partner at Castanea Partners, a private equity firm.
+Mr. Frasch served as President and Chief Merchandising Officer of Saks Fifth Avenue, a division of Saks, Incorporated, a NYSE-listed luxury fashion retailer, from February 2007 until the merger
+of Saks, Incorporated with Hudson's Bay Company in November 2013. From November 2004 until January 2007, he held the post of Vice Chairperson and Chief Merchant of Saks Fifth Avenue. From January 2004
+to November 2004, he was employed by Saks in a non-executive capacity. From April 2000 to January 2004, Mr. Frasch served as Chairperson and Chief Executive Officer of Bergdorf Goodman (a
+subsidiary of Neiman Marcus Group, Inc.) and served as President of GFT North America (a subsidiary of Gruppo GFT, based in Turin, Italy, a global producer, marketer and distributor of fine
+men's and women's clothing, sportswear and furnishings) from 1996 to 2000. Mr. Frasch also served as President and Chief Executive Officer of Escada USA from 1994 to 1996. Mr. Frasch has
+extensive executive expertise in the fashion retail industry, demonstrated by his recent position at Saks Fifth Avenue. Mr. Frasch's experience and insight into this industry is invaluable to
+the Board and management in understanding the consumer retail and fashion industry, including current buying trends by our wholesale customers. 
+Gregg S. Ribatt (Class I) , age 46, is a Blackstone director designee and has served as a member of the Board since
+January 2014. Mr. Ribatt currently serves as the interim Chief Executive Officer of Spanx Inc., one of the leading global shapewear, apparel and accessory companies, and has served in
+such capacity since February 2014. From January 2008 to January 2013, Mr. Ribatt was the President and Chief Executive Officer of the Performance + Lifestyle Group (formerly, The
+Stride Rite
+Corporation) of Collective Brands, Inc., a branded lifestyle footwear company. The Performance + Lifestyle Group included the Sperry Top-Sider, Saucony, Keds and Stride Rite
+brands. The Performance & Lifestyle Group was acquired by Wolverine Worldwide in October 2012. Before joining Collective Brands, Mr. Ribatt served as President and Chief Executive
+Officer of Stuart Weitzman Holdings LLC. Mr. Ribatt's prior experience also includes thirteen years with Bennett Footwear Group, where he was Executive Vice President & Chief
+Operating Officer. Bennett was a leading women's fashion footwear company, which included the Franco Sarto, Via Spiga, and Etienne Aigner brands. Mr. Ribatt holds a Bachelor of Arts from
+Wesleyan University and a Masters of Business Administration from The University of Chicago. Mr. Ribatt's extensive experience in senior management roles at large branded footwear companies
+provides the Board and management with invaluable insights into the global footwear industry. In addition, Mr. Ribatt brings leadership experience and vast knowledge in international footwear
+brands and consumer retail operations. 
+Raymond D. Croghan ( Class II ), age 64, has served as a member of the Board since August 2004.
+Since 1999, Mr. Croghan has been retired. From 1991 to 1999, Mr. Croghan managed Croghan & Associates, Inc., a healthcare information technology consulting firm, which
+merged with Margolis Health Enterprise to form The TriZetto Group. Mr. Croghan currently serves on the boards of directors of several privately-held companies. Mr. Croghan has
+successfully operated and grown private 
+5 
+Table of Contents 
+companies
+and has served on the boards of several companies in a variety of industries. His experience successfully operating companies in different industries provides us with a unique perspective as
+does his board experience. In addition, Mr. Croghan is our longest serving director and has extensive knowledge of our company and its operations. 
+Peter A. Jacobi ( Class II ), age 70, has served as a member of the Board since October 2008.
+Mr. Jacobi was employed by Levi Strauss & Company ("Levi Strauss"), a jeans and casual wear manufacturer, from 1970 until his retirement in 1999. During his 29 years of tenure at
+Levi Strauss, Mr. Jacobi held various senior level positions, including President of the Men's Jeans Division, President of Global Sourcing, President of Levi Strauss International, and from
+1996 until his retirement, President and Chief Operating Officer. Mr. Jacobi has extensive executive experience in the apparel industry gained through his tenure at Levi Strauss. The apparel
+industry is similar and complementary to the footwear industry and Mr. Jacobi has provided us significant insights from this industry. In addition, Levi Strauss is an established international
+brand. Mr. Jacobi's experience with a global brand has helped us as we continue to build our brand internationally. 
+Doreen A. Wright ( Class II ), age 57, has served as a member of the Board since June 2011 prior to
+which she served as Senior Vice President and Chief Information Officer of Campbell Soup Company from 2001 to 2008. Ms. Wright also served as Interim Chief of Human Resources for Campbell Soup
+Company in 2002. From 1999 to 2001, Ms. Wright served as Executive Vice President and Chief Information Officer for Nabisco Inc. Prior to that, from 1995 to 1998 Ms. Wright held
+the position of
+Senior Vice President, Operations & Systems, Prudential Investments, for Prudential Insurance Company of America, and held various positions with American Express Company, Bankers Trust
+Corporation and Merrill Lynch & Co. Since 2009, Ms. Wright has served on the Board of Directors of Dean Foods Company, a leading food and beverage company. She also serves on the
+Board of the WhiteWave Foods Company, a U.S. and European organic and plant based food and beverage company. She also serves on the Board of New Hope Arts, Inc., a regional nonprofit arts
+center. In addition, Ms. Wright served on the Board of Directors of Citadel Broadcasting Corporation from 2010 to 2011, where she chaired the Compensation Committee; The Oriental Trading
+Company from 2008 to 2011, where she served on the Audit and Compensation Committees; Yankee Candle Company from 2003 to 2007, where she served on the Compensation and Audit Committees; and
+Conseco, Inc. from 2007 to 2010, where she served on the Audit and Enterprise Risk Committee. Ms. Wright brings more than 30 years of leadership experience in the financial
+services and consumer products industries, with emphasis in the area of information technology, operations, and human resources. Ms. Wright also has extensive experience as a public company
+director, including service on audit, compensation and corporate governance committees. 
+Information About Mr. McCarvel 
+John P. McCarvel (Class III) , age 57, has served as our President and
+Chief Executive Officer and as a director since March 2010. On December 27, 2013, Mr. McCarvel resigned as our President, Chief Executive Officer and a director, effective upon the
+earlier to occur of (i) April 30, 2014 or (ii) the Board's appointment of his successor as Chief Executive Officer. Prior to serving as our President and Chief Executive Officer,
+Mr. McCarvel served as our Chief Operating Officer and Executive Vice President from February 2007 to March 2010, as our Senior Vice President—Global Operations from October 2005 to
+February 2007 and as our Vice President—Asian & Australian Operations from January 2005 to September 2005, after providing consulting services to us during 2004. From October 2001
+to January 2005, Mr. McCarvel served as Vice President for the Design, Test and Semiconductor division of Flextronics, where he was responsible for building Flextronics' engineering
+infrastructure in Asia and growing Flextronics' business in the region. From 1999 to October 2001, he served as President of U.S. Operations and Senior Vice President of Worldwide Sales and Marketing
+for Singapore Technology Assembly Test Services Ltd., a semiconductor services company. He previously 
+6 
+Table of Contents 
+worked
+in executive level positions with Micron Custom Manufacturing Services, Inc., a manufacturer of electronic products for computing and digital applications, and The Dii Group.
+Mr. McCarvel has served us as an executive since 2005. He has been our Chief Operating Officer and has extensive knowledge of our day-to-day operations along with a strategic vision as our
+Chief Executive Officer. Mr. McCarvel's leadership, extensive knowledge of our business and previous manufacturing expertise has provided significant value and insights to the Board. 
+CORPORATE GOVERNANCE 
+We
+are committed to maintaining sound corporate governance practices. The Board has formalized several policies, procedures and standards of corporate governance, including our Corporate Governance
+Guidelines, some of which are described below. We continue to monitor best practices and legal and regulatory developments with a view to further revising our governance policies and procedures, as
+appropriate. 
+Corporate Governance Guidelines. Since 2005, the Board has had in place a set of governance guidelines, the Crocs, Inc. Corporate Governance Guidelines,
+which are designed to assure the continued vitality of the Board and excellence in the execution of its duties. Our Corporate Governance Guidelines establish the practices and procedures of the Board
+with respect to board composition and member selection, board independence, board meetings and involvement of senior management, management succession planning, board committees and the evaluation of
+senior management and the Board. The Board periodically reviews our Corporate Governance Guidelines and updates them as necessary to reflect improved corporate governance practices and changes in
+regulatory requirements. A copy of our Corporate Governance Guidelines is available on our website at www.crocs.com. 
+Majority Vote Director Resignation Policy. In addition, our Corporate Governance Guidelines contain a Director Resignation Policy. Under this policy, any nominee
+for director who receives a greater number of votes "withheld" from his or her election than votes "for" such election is required to offer his or her resignation to the Board following certification
+of the stockholder vote. Within 90 days following the certification of the vote, the independent directors on the Board would consider the offer of resignation and determine whether to accept
+or reject the tendered resignation. This policy does not apply in contested elections. 
+Director Independence. NASDAQ listing standards require that the Board consist of a majority of
+independent directors. The Board has determined that all of the current non-management members of the Board (Messrs. Croghan, Frasch, Jacobi, Melwani, Ribatt, and Smach and Ms. Wright)
+are independent directors as defined by NASDAQ listing standards. 
+The
+Board makes a determination regarding the independence of each director annually based on relevant facts and circumstances. Applying the standards and independence criteria defined by the NASDAQ
+listing standards, the Board has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the Board, would interfere with the exercise of
+his or her independent judgment in carrying out the responsibilities of a director. In making its determination of Mr. Melwani's independence, the Board considered Mr. Melwani's role as
+a Senior Managing Director of the Blackstone Group. In making its determination of Mr. Ribatt's independence, the Board considered the fact that, in connection with our issuance of convertible
+preferred stock to Blackstone in January 2014, Mr. Ribatt, as a permitted transferee of Blackstone, purchased from us 1,000 shares of such convertible preferred stock for an aggregate purchase
+price of $990,000. 
+The
+independent directors of the Board regularly hold executive sessions without members of management present. 
+7 
+Table of Contents 
+Communicating with Directors. Stockholders who wish to communicate with the Board or with specified individual directors may do so by mailing such written
+communication to: Corporate Secretary, Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503. The Corporate Secretary will review all correspondence and will forward to the Board or
+an individual director a summary of the correspondence received and copies of correspondence that the Corporate Secretary determines requires the attention of the Board or such individual director.
+The Board and any individual director may at any time request copies and review all correspondence received by the Corporate Secretary that is intended for the Board or such individual director. 
+Board Leadership. The Board does not have a policy regarding separation of the roles of Chief Executive Officer and Chairperson of the Board. The Board believes it
+is in our best interests to make that determination based on current circumstances. The Board has determined that an independent director serving as Chairperson is in the best interests of our
+stockholders at this time. This structure ensures a greater role of independent directors in the active oversight of our business, including risk management oversight, and in setting agendas and
+establishing Board priorities and procedures. This structure also allows the Chief Executive Officer to focus to a greater extent on the management of our day-to-day operations. 
+In
+addition, in November 2012, the Board named Mr. Frasch as its Lead Director. The Lead Director will preside at all meetings of the Board at which the Chairman is not present and will perform
+other duties assigned to him by the Chairman from time to time. 
+Risk Oversight. The full Board is actively involved in oversight of risks that could affect us. The Board implements its risk oversight function both as a whole
+and through delegation to its committees. These committees meet regularly and report back to the full Board. The Audit Committee has primary oversight responsibility with respect to financial risks as
+well as oversight responsibility for our overall risk assessment and risk management policies and systems. The Audit Committee oversees our procedures for the receipt, retention and treatment of
+complaints relating to accounting and auditing matters and oversees our management of legal and regulatory compliance systems. The Audit Committee regularly interacts with the Company's accounting and
+legal personnel, our Vice President of Internal Audit and our outside auditors in fulfillment of this oversight function. The Compensation Committee oversees risks relating to our compensation plans
+and programs. The Compensation Committee has reviewed and considered our compensation policies and programs in light of the Board's risk assessment and management responsibilities and will do so in
+the future on an annual basis. The Compensation Committee believes that we have no compensation policies and programs that give rise to risks reasonably likely to have a material adverse effect on us.
+The Compensation Committee also, on at least an annual basis, considers and evaluates the independence and potential conflicts of interest of its advisors, including our compensation consultant,
+Towers Watson. 
+The
+Chief Legal and Administrative Officer serves as our chief compliance officer and chairs an inter-disciplinary Compliance Council which is charged with assessing and managing our legal and other
+compliance obligations on a global basis. The Chief Legal and Administrative Officer regularly reports to the Audit Committee, and the full Board as appropriate, regarding our legal and compliance
+obligations. 
+The
+Vice President of Internal Audit coordinates the day-to-day risk management process and reports directly to the Audit Committee and to the Chief Financial Officer. The Vice President of Internal
+Audit performs a risk assessment annually, and updates the Audit Committee at least quarterly regarding our risk analyses, assessments, risk mitigation strategies and activities. The Vice President of
+Finance Administration updates the Audit Committee at least annually, or more frequently as needed, regarding our directors and officers insurance coverage and on matters regarding certain financial
+risks. 
+8 
+Table of Contents 
+Code of Business Conduct and Ethics and Committee Charters. We have adopted a Code of Business Conduct and Ethics that applies to all directors and employees,
+including our principal executive, financial and accounting officers. The Amended and Restated Code of Business Conduct and Ethics is posted on our website at www.crocs.com. We intend to satisfy the
+requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of our Code of Business Conduct and Ethics that apply to our directors and
+principal executive, financial and accounting officers by posting such information on our website. The Audit Committee Charter, Compensation Committee Charter, Nominating and Governance Committee
+Charter and Business Systems Steering Committee Charter are also available on our website at www.crocs.com. Any person may request a copy of the Code of Business Conduct and Ethics or committee
+charters free of charge by submitting a written request to: Corporate Secretary, Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503. 
+BOARD OF DIRECTORS AND COMMITTEES OF THE BOARD 
+During
+2013, the Board met eight times, and all directors who served during 2013 attended 75% or more of the Board's meetings and the meetings of the Board committees on which they served. We
+encourage, but do not require, our directors to attend the annual meeting of stockholders. Messrs. Cannon, Frasch, Jacobi, Margolis, McCarvel, and Smach and Ms. Wright attended our 2013
+Annual Meeting of Stockholders. 
+Board Committees. The Board has the authority to appoint committees to perform certain management and administrative functions and has established the following
+committees. 
+Audit Committee. Messrs. Smach (Chairperson), Frasch, Cannon and Margolis served as the members of the Audit Committee during 2013. The Audit Committee met
+eight times in 2013. Effective January 27, 2014, Messrs. Cannon and Margolis resigned from their service on the Audit Committee, and Mr. Jacobi was appointed as a new member of
+the Committee. The functions of the Audit Committee include oversight of the integrity of our financial statements, our compliance with legal and regulatory requirements, the performance,
+qualifications and independence of our independent auditors and the performance of our internal audit function. The Audit Committee is directly responsible for the appointment, retention,
+compensation, evaluation, termination and oversight of the work of any
+independent auditor engaged for the purpose of preparing or issuing an audit report or related work. The purpose and responsibilities of the Audit Committee are set forth in the Audit Committee
+Charter. The Audit Committee Charter can be found on our website at www.crocs.com. 
+All
+of the members of the Audit Committee are independent, as determined in accordance with NASDAQ listing standards applicable to Audit Committee members and relevant federal securities laws and
+regulations. The Board has determined that Mr. Smach qualifies as an "audit committee financial expert" as defined by the applicable regulations of the SEC. 
+Compensation Committee. Ms. Wright (Chairperson), Messrs. Croghan and Jacobi served as the members of the Compensation Committee during 2013. The
+Compensation Committee met six times in 2013. Effective January 27, 2014, Mr. Melwani became a member of the Compensation Committee, and Mr. Jacobi's membership on the Committee
+terminated. The Compensation Committee has overall responsibility for defining, articulating, evaluating and approving our executive officer compensation, benefits, severance, equity-based or other
+compensation plans, policies and programs. The Compensation Committee is also responsible for approving our Compensation Discussion and Analysis for inclusion in this proxy statement. The purpose and
+responsibilities of our Compensation Committee are set forth in the Compensation Committee Charter, which can be found on our website at www.crocs.com. All of the members of the Compensation Committee
+are independent, as determined 
+9 
+Table of Contents 
+in
+accordance with NASDAQ listing standards applicable to Compensation Committee members and relevant federal securities laws and regulations. 
+Pursuant
+to its charter, the Compensation Committee has the authority to, among other things: (i) establish, monitor and approve our overall compensation and benefits strategy and philosophy;
+(ii) review and approve annually corporate goals and objectives relevant to the compensation of our Chief Executive Officer, and to approve the Chief Executive Officer's compensation;
+(iii) oversee management's decisions concerning the performance and compensation of other executive officers; (iv) oversee the compensation and benefits structure for our employees
+generally; (v) review and make recommendations to the Board with respect to the establishment of any new incentive compensation and equity-based plans; (vi) supervise the administration
+of our equity-based incentive plans, including the authorization of equity grants under such plans; (vii) review and recommend to the Board the terms of written employment agreements,
+post-employment consulting agreements and severance arrangements for executive officers; (viii) assist the Board in developing and evaluating potential candidates for executive officer
+positions and oversee the development of succession plans for executive officers; (ix) review and recommend to the Board compensation to be paid to our outside directors; and (x) review
+and evaluate the relationship between our incentive compensation arrangements and our corporate strategy and risk management policies and practices. 
+The
+Compensation Committee sets the Chief Executive Officer's compensation. The Compensation Committee also reviews the recommendations of the Chief Executive Officer with respect to compensation of
+the other named executive officers and, after reviewing such recommendations, sets the compensation of the other named executive officers. The Compensation Committee relies on its judgment when making
+compensation decisions after reviewing our performance and evaluating each executive's performance against established goals, leadership ability and responsibilities, and current compensation
+arrangements. When evaluating total compensation for each of our executive officers, the Compensation Committee reviews the executive officer's current compensation, including equity and
+non-equity-based compensation. The Compensation Committee also evaluates surveys and other available data regarding the executive compensation programs of comparative companies. The compensation
+program for executive officers and the Compensation Committee assessment process are designed to be flexible so as to better respond to the evolving business environment and individual circumstances.
+See "Risk Oversight" (above) for the Compensation Committee's evaluation of our compensation program risk. 
+In
+2013, the Compensation Committee engaged an outside independent compensation consultant, Towers Watson, to provide an evaluation of the 2013 executive bonus plan, long-term incentives and other
+executive compensation matters. Please see "Compensation Discussion and Analysis" for further description of the role of the Compensation Committee. Towers Watson does not provide any services to
+management and had no prior relationship with management prior to the engagement. Prior to engaging Towers Watson, the Compensation Committee considered the independence of Towers Watson in accordance
+with the terms of the Compensation Committee Charter. The Committee determined that Towers Watson was independent and did not identify any conflicts of interest. 
+Nominating and Governance Committee. Messrs. Cannon (Chairperson), Frasch, and Smach served as the members of the Nominating and Governance Committee during
+2013. The Nominating and Governance Committee met two times in 2013. Effective January 27, 2014, Mr. Cannon resigned from his service on the Nominating and Governance Committee,
+Mr. Melwani was appointed as a new member of the Committee, and Mr. Frasch was appointed as the new Chairperson of the Committee. The Nominating and Governance Committee assists the
+Board in promoting our best interests and that of our stockholders through the implementation of sound corporate governance principles and practices. In furtherance of this purpose, the Nominating and
+Governance Committee identifies individuals qualified to become board members and recommends to the Board the director nominees 
+10 
+Table of Contents 
+for
+election at each annual meeting of stockholders. It also reviews the qualifications and independence of the members of the Board and its various committees and makes any recommendations the
+Nominating and Governance Committee members may deem appropriate concerning any changes in the composition of the Board and its committees. The Nominating and Governance Committee also
+recommends to the Board the corporate governance guidelines and standards regarding the independence of outside directors applicable to us and reviews the provisions of the Nominating and Governance
+Committee Charter on a regular basis to confirm that such guidelines, standards and charter remain consistent with sound corporate governance practices and with any applicable legal or regulatory
+requirements and the NASDAQ listing standards. The Nominating and Governance Committee also monitors and leads the Board in its annual review of the Board's performance. 
+The
+purpose and responsibilities of our Nominating and Governance Committee are set forth in the Nominating and Governance Committee Charter. The Nominating and Governance Committee Charter can be
+found on our website at www.crocs.com. All of the members of the Nominating and Governance Committee are independent, as determined in accordance with the NASDAQ listing standards. 
+Director Nomination Process and Director Qualifications. Except with respect to director nominees designated by Blackstone pursuant to the Investment Agreement, as
+described above, the Nominating and Governance Committee's process for identifying potential director candidates and the factors considered by the Committee in evaluating potential candidates are
+described below. In identifying potential director candidates, the Nominating and Governance Committee relies on recommendations from a number of sources, including current directors and officers. The
+Nominating and Governance Committee may also hire outside consultants, search firms or other advisors to assist in identifying director candidates. The Nominating and Governance Committee will
+consider director candidates recommended by stockholders on the same basis as it considers other candidates. Any stockholder wishing to recommend a candidate for consideration by the Nominating and
+Governance Committee may do so by submitting a written recommendation to the Nominating and Governance Committee in accordance with the procedures set forth under "Stockholder Proposals and
+Nominations for 2015 Annual Meeting." 
+In
+evaluating a candidate for director, our Nominating and Governance Committee considers, among other things, the candidate's judgment, knowledge, integrity, diversity, expertise and business and
+industry experience, and other expertise, which are likely to enhance the Board's ability to govern our affairs and business. We do not have a separate policy regarding consideration of diversity in
+identifying director nominees but the Nominating and Governance Committee strives to nominate directors with a variety of complementary skills and backgrounds so that, as a group, the Board will
+possess a broad perspective and the appropriate talent, skills and expertise to oversee our business. The Nominating and Governance Committee also takes into account independence requirements imposed
+by law or regulations (including the NASDAQ listing standards). In the case of director candidates recommended by stockholders, the Nominating and Governance Committee may also consider the number of
+shares held by the recommending stockholder, the length of time that such shares have been held and the relationship, if any, between the recommending stockholder and the recommended director nominee. 
+Business Systems Committee. Messrs. McCarvel (Chairperson), Croghan, Margolis, and Jacobi and Ms. Wright served as the members of our Business
+Systems Committee (formerly, the IT Steering Committee) during 2013. The Business Systems Committee met six times in 2013. Effective January 27,
+2014, Mr. Margolis resigned from his service on the Business Systems Committee, and Ms. Wright was appointed as the new Chairperson of the Committee. The Business Systems Committee
+oversees major information technology ("IT") related strategies, projects and technology architecture decisions. The Business Systems Committee also monitors whether our IT programs effectively
+support our business objectives and strategies and reports to the Board on IT related matters. The Business Systems Committee is also tasked with evaluating our significant IT strategies. The purpose
+and responsibilities 
+11 
+Table of Contents 
+of
+the Business Systems Committee are set forth in its charter, which can be found on our website at www.crocs.com. 
+Search Committee. Pursuant to the terms of the Investment Agreement, the Board formed a special search committee (the "Search Committee") and has granted to the
+Search Committee the sole power and authority to identify, consider, assess, evaluate, research, and recommend individual nominees for the position of Chief Executive Officer to replace
+Mr. McCarvel. Any recommendation from the Search Committee with respect to a Chief Executive Officer nominee requires the unanimous consent of the members of the Search Committee, and the Board
+may not appoint a new Chief Executive Officer without the recommendation of the Search Committee. The final candidate will be reviewed and appointed by the full Board. Messrs. Smach, Frasch,
+Jacobi, and Melwani are the current members of the Search Committee. 
+EXECUTIVE OFFICERS 
+In
+addition to John McCarvel, our President and Chief Executive Officer, whose biographical information is disclosed above under "Election of Directors," our executive officers as of March 31,
+2014 include the following individuals: 
+Name 
+Age 
+Position(s) 
+Daniel P. Hart 
+55 
+Executive Vice President, Chief Legal and Administrative Officer 
+Jeffrey J. Lasher 
+50 
+Senior Vice President—Finance, Chief Financial Officer 
+Scott E. Crutchfield 
+53 
+Chief Operating Officer 
+Daniel P. Hart has served as our Executive Vice President, Chief Legal and Administrative Officer since January 2010. From June 2009 through December
+2009, he served as our Executive Vice President of Administration and Corporate Development. Prior to joining us, Mr. Hart was employed by Océ North America, a digital printing
+and document management division of Océ, N.V., a manufacturing and engineering company publicly traded on the Euronext Amsterdam stock exchange, where he served as Senior Vice
+President and General Counsel from 2006 to 2009. From 2004 to 2006, Mr. Hart served as Senior Vice President—General Counsel and Human Resources for Invensys Controls, a global
+manufacturing and engineering operation within Invensys plc, a public U.K. conglomerate. From 2002 to 2004, Mr. Hart served as Chief Staff Officer for the Development Division of
+Invensys, a large portfolio of disposal companies within Invensys plc. Previously, Mr. Hart's experience included service in senior legal positions at Dictaphone Corporation and Brooke
+Group Ltd. and private legal practice in New York City. 
+Jeffrey J. Lasher has served as our Senior Vice President-Finance and Chief Financial Officer since April 2011. From January 2011 to March 2011,
+Mr. Lasher served as our principal accounting officer and interim principal financial officer. From June 2009 to January 2011, he served as our Corporate Controller and Chief Accounting
+Officer. Prior to joining us, Mr. Lasher was a Senior Consultant for Connelly Consulting, a privately-held financial services company, from October 2008 to June 2009. From December 2005 to
+September 2008, he was the Vice President—Corporate Controller for Corporate Express Inc., a publicly-held business supplies and equipment company.
+Mr. Lasher was also the Vice President—Finance of AutoNation, Inc., a publicly-held automotive retail company, from December 2000 to December 2005. 
+Scott E. Crutchfield has served as our Chief Operating Officer since September 2012 and was our Senior Vice President of World Wide Operations since May
+2010. From February 2006 to May 2010, he served as our Vice President for Worldwide Operations. Prior to joining us, he served as Senior Director, U.S. and South America Operations for Jabil Circuit,
+a publicly-held design and 
+12 
+Table of Contents 
+manufacturing
+company from May 2004 to January 2006. Mr. Crutchfield was also Vice President, General Manager Central/Eastern U.S. and South America for Flextronics from March 2000 to April
+2004. Previously, Mr. Crutchfield also held senior leadership positions at Dovatron International, a subsidiary of the Dii Group, and at Square D, a subsidiary of Schneider Electric.
+Mr. Crutchfield served as the Chairman of the Board of Directors of Biostem U.S. Corporation, a hair transplant and regrowth technology company, until July 2013. 
+BENEFICIAL OWNERSHIP OF OUR SECURITIES 
+Ownership by Our Directors, Executive Officers and Greater than 5% Stockholders 
+The following table sets forth information with respect to the beneficial ownership of our common stock and convertible preferred stock as of
+March 31, 2014 by: 
+• each person (or group of affiliated persons) who is known by us to own beneficially more than 5% of our outstanding common
+stock or convertible preferred stock; 
+• each current director or nominee; 
+• each of the named executive officers listed in the Summary Compensation Table below; and 
+• all directors and executive officers as a group. 
+Beneficial
+ownership is determined in accordance with SEC rules. In computing a person's percentage ownership of common stock, (a) shares of common stock subject to options or restricted stock
+units held by that person that are currently exercisable, or exercisable (or, in the case of restricted stock units, scheduled to vest and settle) within 60 days after March 31, 2014,
+and (b) shares of common stock into which shares of convertible preferred stock are convertible, are deemed to be outstanding and beneficially owned by that person. None of these shares,
+however, are deemed outstanding for the purpose of computing the percentage ownership of any other person. 
+Except
+as indicated and pursuant to applicable community property laws, each stockholder named in the table has sole voting and investment power with respect to the shares set forth opposite such
+stockholder's name. Percentage ownership is based on 87,888,964 shares of our common stock and 200,000 shares of our convertible preferred stock outstanding on March 31, 2014. Unless otherwise 
+13 
+Table of Contents 
+indicated
+below, the address for each director and named executive officer listed below is in care of Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503. 
+Common Stock 
+Series A Convertible Preferred Stock 
+Name of Beneficial Owner 
+Shares 
+Percent 
+Shares 
+Percent 
+5% Stockholders: 
+Blackstone Capital Partners VI L.P. (1) 
+2,479 
+* 
+200,000 
+100 
+% 
+Blackrock, Inc. (2) 
+7,923,707 
+9.02% 
+— 
+— 
+The Vanguard Group, Inc. (3) 
+5,297,784 
+6.03% 
+— 
+— 
+Royce & Associates, LLC (4) 
+6,449,288 
+7.34% 
+— 
+— 
+S.A.C. Capital Advisors, L.P. and associates (5) 
+4,808,630 
+5.47% 
+— 
+— 
+Directors: 
+Peter A. Jacobi (6) 
+62,125 
+* 
+— 
+— 
+Thomas J. Smach (7) 
+91,142 
+* 
+— 
+— 
+Raymond D. Croghan (8) 
+68,162 
+* 
+— 
+— 
+Prakash A. Melwani 
+— 
+* 
+— 
+— 
+Gregg S. Ribatt (9) 
+2,479 
+* 
+1,000 
+* 
+Ronald L. Frasch 
+44,300 
+* 
+— 
+— 
+Doreen A. Wright (10) 
+16,006 
+* 
+— 
+— 
+Officers: 
+John P. McCarvel (11) 
+350,906 
+* 
+— 
+— 
+Daniel P. Hart (12) 
+139,289 
+* 
+— 
+— 
+Jeffrey J. Lasher (13) 
+94,005 
+* 
+— 
+— 
+Scott E. Crutchfield (14) 
+113,248 
+* 
+— 
+— 
+All current directors and executive officers as a group (11 persons) (15) 
+981,662 
+1.12% 
+1,000 
+* 
+* Less
+than 1%
+(1) Reflects
+198,503 shares of Preferred Stock directly held by Blackstone Capital Partners VI L.P. ("BCP VI") and 497 shares of Preferred Stock directly
+held by Blackstone Family Investment Partnership VI-ESC L.P., and 2,479 shares of Common Stock directly held by Blackstone Management Partners L.L.C., an indirect subsidiary of The Blackstone
+Group L.P. Also reflects 1,000 shares of Preferred Stock held directly by Mr. Ribatt that BCP VI may be deemed to beneficially own pursuant to an Assignment and Assumption Agreement
+between Gregg S. Ribatt and BCP VI. 
+Blackstone
+Management Associates VI L.L.C. is the general partner of BCP VI. BMA VI L.L.C. is the sole member of Blackstone Management Associates VI L.L.C. Blackstone Holdings III L.P. is the
+managing member of BMA VI L.L.C. BCP VI Side-by-Side GP L.L.C. is the general partner of Blackstone Family Investment Partnership VI-ESC L.P. Blackstone Holdings III L.P. is the
+managing member of BCP VI Side-by-Side GP L.L.C. Blackstone Holdings III GP L.P. is the general partner of Blackstone Holdings III L.P. Blackstone Holdings III GP
+Management L.L.C. is the general partner of Blackstone Holdings III GP L.P. The Blackstone Group L.P. is the sole member of Blackstone Holdings III GP Management L.L.C.
+Blackstone Group Management L.L.C. is the general partner of The Blackstone Group L.P. Blackstone Group Management L.L.C. is wholly-owned by Blackstone's senior managing directors and
+controlled by its founder, Stephen A. Schwarzman. Each of such Blackstone entities (other than BCP VI, Blackstone Family Investment Partnership VI-ESC L.P. and Blackstone Management Partners
+L.L.C. to the extent of each of their direct holdings) and Mr. Schwarzman may be deemed to beneficially own the shares beneficially owned by BCP VI, Blackstone Family Investment Partnership
+VI-ESC L.P. and Blackstone Management Partners L.L.C. to the
+extent directly or indirectly controlled by it or him, but each disclaims beneficial ownership of such shares. The address of each of Mr. Schwarzman and each of the entities listed in this
+footnote is c/o The Blackstone Group L.P., 345 Park Avenue, New York, New York 10154. 
+(2) Based
+solely on a Schedule 13G/A filed with the SEC on January 28, 2014. The address for Blackrock, Inc. is 40 East
+52 nd Street, New York, New York 10022.
+(3) Based
+solely on a Schedule 13G/A filed with the SEC on February 12, 2014. The address for The Vanguard Group, Inc. is 100 Vanguard
+Blvd., Malvern, PA 19355. 
+14 
+Table of Contents 
+(4) Based
+solely on a Schedule 13G filed with the SEC on January 8, 2014. The address for Royce & Associates, LLC is 745 Fifth
+Avenue, New York, NY 10151
+(5) Based
+solely on a Schedule 13G/A filed with the SEC on February 14, 2014. The address of the principal business office for (i) S.A.C.
+Capital Advisors, L.P., SAC. Capital Advisors, Inc., and Steven A. Cohen is 72 Cummings Point Road, Stamford CT 06902; and (ii) Sigma Management is 510 Madison Avenue, New York,
+NY 10022.
+(6) Shares
+beneficially owned include 60,011 shares held in trust by Peter A Jacobi & Mary Louise Jacobi Living Trust.
+(7) Shares
+beneficially owned include (i) 7,500 shares subject to options exercisable within 60 days of March 31, 2014; (ii) 50,337
+Restricted Stock Units that become immediately vested upon the earlier of Mr. Smach's separation of service from the Board or a change in control of us; and (iii) 4,400 shares held as
+custodian for Mr. Smach's two children under the New York Uniform Gifts to Minors Act. Mr. Smach exercises voting and investment power over the shares.
+(8) Shares
+beneficially owned include an aggregate of 4,960 shares of common stock beneficially owned by two trusts for the benefit of Mr. Croghan's two
+daughters. Mr. Croghan's spouse is the trustee of both trusts and she exercises sole voting and investment power over the shares. Mr. Croghan disclaims beneficial ownership of such
+shares
+(9) Includes
+1,000 shares of Preferred Stock held directly by Mr. Ribatt that BCP VI may be deemed to beneficially own pursuant to an Assignment and
+Assumption Agreement between Mr. Ribatt and BCP VI.
+(10) Includes
+6,039 Restricted Stock Units that become immediately vested upon the earlier of Ms. Wright's separation of service from the Board or a
+change in control of us.
+(11) Shares
+beneficially owned include 90,540 shares subject to options exercisable within 60 days of March 31, 2014 and 260,366 shares held
+jointly with his spouse.
+(12) Shares
+beneficially owned include 70,831 shares subject to options exercisable within 60 days of March 31, 2014.
+(13) Shares
+beneficially owned include 51,125 shares subject to options exercisable within 60 days of March 31, 2014.
+(14) Shares
+beneficially owned include 66,548 shares subject to options exercisable within 60 days of March 31, 2014.
+(15) Shares
+beneficially owned include 7,500 shares of common stock subject to options issued to directors and 279,044 shares of common stock subject to options
+issued to named executive officers that are exercisable or issuable within 60 days of March 31, 2014. 
+Section 16 Beneficial Ownership Reporting Compliance 
+Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors and executive officers and persons who own more than
+ten percent of our common stock to file with the SEC and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of
+our common stock. 
+To
+our knowledge, based solely on a review of the copies of such reports furnished to us and written representations from certain of our officers and directors that no other reports were required, we
+believe that all required reports of our officers, directors and greater than ten percent stockholders under Section 16(a) were timely filed during the year ended December 31, 2013,
+except for one Form 4 for Mr. McCarvel relating to the cancellation of restricted stock awards and restricted stock units pursuant to the Separation Agreement entered into between us and
+Mr. McCarvel on December 27, 2013. 
+15 
+Table of Contents 
+CERTAIN RELATIONSHIPS AND RELATED PERSON TRANSACTIONS 
+Related Person Transactions 
+Investment Agreement with Blackstone 
+On January 27, 2014, we issued to Blackstone and certain of its permitted transferees (together with Blackstone, the "Blackstone Purchasers"),
+200,000 shares of our convertible preferred stock for an aggregate purchase price of $198 million, or $990 per share, pursuant to the Investment Agreement. In connection with the issuance of
+the convertible preferred stock (the "Closing") and pursuant to the Investment Agreement, we paid Blackstone a closing fee of $2 million and reimbursed Blackstone's transaction fees and
+expenses of approximately $4 million. As of March 31, 2014, the Blackstone Purchasers collectively owned all of our outstanding shares of convertible preferred stock and, on an
+as-converted basis, approximately 14% of our outstanding common stock. 
+As
+discussed above under "Proposal 1—Election of Directors," the Investment Agreement grants Blackstone certain rights to designate directors to serve on our Board. For so long as the
+Blackstone Purchasers (i) beneficially own at least 95% of our convertible preferred stock or the as-converted common stock purchased pursuant to the Investment Agreement or
+(ii) maintain beneficial ownership of at least 12.5% of the our outstanding common stock (the "Two-Director Threshold"), Blackstone will have the right to designate for nomination two directors
+to our Board. For so long as the Blackstone Purchasers beneficially own shares of our convertible preferred stock or the as-converted common stock purchased pursuant to the Investment Agreement that
+represent less than the Two-Director Threshold but more than 25% of the number of shares of the as-converted common stock purchased pursuant to the Investment Agreement, Blackstone will have the right
+to designate for nomination one director to our Board. The directors designated by Blackstone are entitled to serve on Board committees, subject to applicable law and stock exchange rules. Blackstone
+designated Messrs. Melwani and Ribatt for nomination to our Board. 
+Pursuant
+to the Investment Agreement, Blackstone is subject to certain standstill restrictions which restrict Blackstone from acquiring more than 25% of our outstanding common stock until the date on
+which Blackstone is no longer entitled to designate any directors to our Board. In addition, subject to certain customary exceptions, Blackstone is restricted from transferring any shares of the
+convertible preferred stock until the second anniversary of the Closing and, for so long as any convertible preferred stock is outstanding, may not transfer any shares of convertible preferred stock
+to certain of our competitors (as defined in the Investment Agreement) or holders of 25% or more of our common stock. Blackstone also has certain preemptive rights and information rights under the
+Investment Agreement, which are subject to certain conditions. 
+Certificate of Designations 
+Pursuant to the Certificate of Designations of Series A Convertible Preferred Stock filed with the Delaware Secretary of State on
+January 24, 2014, which establishes the designations, preferences, and other rights of the convertible preferred stock: 
+• The convertible preferred stock ranks senior to our common stock with respect to dividend rights and rights on
+liquidation, winding-up and dissolution; 
+• The Blackstone Purchasers are entitled to cumulative dividends payable quarterly in cash at a rate of 6% per annum of the
+stated value of $1,000 per share; 
+16 
+Table of Contents 
+• If we fail to make timely dividend payments to the holders of our convertible preferred stock, the dividend rate will
+increase to 8% per annum until such time as all accrued but unpaid dividends have been paid in full; 
+• The Blackstone Purchasers are entitled to receive any dividends declared or paid on our common stock and are entitled to
+vote together with the holders of our common stock as a single class, in each case, on an as-converted basis; 
+• The Blackstone Purchasers have certain limited special approval rights, including with respect to the issuance by us of pari passu 
+or senior equity securities; 
+• The Blackstone Purchasers may, at any time, require us to convert their shares of convertible preferred stock into shares
+of common stock at an implied conversion price of $14.50 per share, subject to certain adjustments; 
+• At our election, all or a portion of the convertible preferred stock will be convertible into the relevant number of
+shares of common stock on or after the third anniversary of the Closing, if the closing price of the common stock equals or exceeds $29.00 for 20 consecutive trading days; 
+• The conversion rate is subject to customary anti-dilution and other adjustments subject to certain share caps and other
+restrictions; 
+• At any time after the eighth anniversary of the Closing, we will have the right to redeem, and the Blackstone Purchasers
+will have the right to require us to repurchase, all or any portion of the convertible preferred stock at 100% of the stated value, plus all accrued but unpaid dividends; and 
+• Upon certain change of control events involving us, the Blackstone Purchasers can require us to repurchase their shares of
+convertible preferred stock at 101% of the stated value plus all accrued but unpaid dividends. 
+Registration Rights Agreement 
+In connection with the Closing, we and the Blackstone Purchasers entered into a Registration Rights Agreement (the "Registration Rights Agreement"),
+pursuant to which we have agreed to provide to the Blackstone Purchasers certain customary demand and piggyback registration rights in respect of the shares of convertible preferred stock and any
+shares of common stock issued upon conversion of the convertible preferred stock. The Registration Rights Agreement contains customary terms and conditions, including certain customary indemnification
+obligations. 
+Policy on Transactions with Related Persons 
+Our Code of Business Conduct and Ethics requires that any transaction involving us in which one of our directors, nominees for director, executive
+officers, or greater than five percent stockholders, or one of the aforementioned's immediate family members (each, a "related person"), have a material interest be approved or ratified by the Audit
+Committee if the amount involved, when aggregated with the amount of all other transactions between the related person and us, exceeds $100,000 in a fiscal year. The full Board reviews ordinary course
+of business transactions in which directors have an interest as part of the Board's annual director independence review, and our Code of Business Conduct and Ethics permits the full Board to waive any
+conflicts of interest between us and any director or officer. In determining whether to approve or ratify any such transaction, the Audit Committee must consider, in addition to other factors it deems
+appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. The full Board approved each of the transactions disclosed above. 
+17 
+Table of Contents 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify certain directors and executive officers in addition to the indemnification provided for in our
+certificate of incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain expenses (including attorneys' fees),
+judgments, fines and settlement amounts incurred by any such person in any action or proceeding, including any action by us or in our right, arising out of such person's services as a director or
+executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request. We believe that these provisions and agreements are necessary
+to attract and retain qualified persons as directors and executive officers. 
+DIRECTOR COMPENSATION 
+Non-employee
+directors are compensated with a combination of an annual retainer and fees for serving on committees, paid in cash or restricted stock at the director's election, and annual equity
+grants. Directors who are employees of the Company are not eligible to receive this compensation. Directors do not receive additional fees for attendance at meetings. The following describes amounts
+payable to our non-employee directors under our director compensation program. Non-employee directors designated by Blackstone under the Investment Agreement are entitled to receive the standard
+compensation for non-employee directors; however, such compensation may be paid to Blackstone or its designee, pursuant to the terms of the Investment Agreement. 
+Retainer Fees. The Chairman of the Board receives an annual retainer fee of $150,000 and the Lead Director receives $130,000. The other non-employee directors
+receive an annual retainer fee of $100,000. Directors who serve as chairpersons of Board committees receive additional retainer fees, as follows: Audit Committee $50,000; Compensation Committee
+$30,000; Nominating and Governance Committee $10,000; and the Business Systems Committee $35,000. Directors who serve as non-chair members of Board committees receive additional annual retainer fees
+for committee service, as follows: Audit Committee $20,000; Compensation Committee $20,000; Nominating and Governance Committee $5,000; and Business Systems Committee $20,000. These annual retainer
+fees are denominated in cash and payable in quarterly installments unless the director elects to be paid in shares of restricted stock or a combination of cash and restricted stock. The number of
+shares of restricted stock is determined based on the fair market value of our common stock on the date the retainer is payable. The restricted stock vests in four successive quarterly installments
+from the issuance date. During 2013, Messrs. Croghan and Jacobi elected to receive all their annual retainer fees in restricted stock. Ms. Wright and Messrs. Cannon, Margolis, and
+Smach elected to receive their annual retainer fees in cash. Mr. Frasch elected to receive his annual retainer fees in a combination of stock and cash. 
+Equity Awards. Directors receive annual equity awards for Board service consisting of a grant of $150,000 of our common stock for the Chairman of the Board and a
+grant of $100,000 of our common stock for each of our other non-employee directors. Rather than this common stock grant, directors can elect to receive restricted stock that vests upon their cessation
+of service on the Board. The number of shares of common stock was determined based on the fair market value of our common stock on the date of grant. The annual equity compensation for the Chairman of
+the Board also consists of an option to purchase 10,000 shares of our common stock at an exercise price equal to the fair market value of the shares on the date of grant. This option vests and becomes
+exercisable in four equal installments on the respective dates of each of the four annual meetings of stockholders following the
+year of grant. In addition, the Chairman of the Board received a special one-time grant of restricted stock units and options during 2013 in recognition for his additional service relating to the
+transaction with Blackstone and other additional service to the Company. Mr. Smach elected to defer the vesting of such restricted stock units until his cessation of service on the Board. 
+18 
+Table of Contents 
+All
+directors are reimbursed for their reasonable out-of-pocket expenses incurred in attending meetings of the Board and its committees. 
+The
+table below summarizes the total compensation paid to each of our non-employee directors who served during the fiscal year ended December 31, 2013. 
+Name 
+Fees Earned or 
+Paid in Cash 
+Stock Awards (1) 
+Option Awards (1) 
+Total 
+W. Stephen Cannon (2) 
+$ 
+115,000 
+$ 
+100,006 
+$ 
+— 
+$ 
+215,006 
+Raymond D. Croghan 
+— 
+240,021 
+— 
+240,021 
+Ronald L. Frasch 
+117,360 
+177,507 
+— 
+294,867 
+Peter A. Jacobi 
+— 
+240,021 
+— 
+240,021 
+Jeffrey H. Margolis (2) 
+140,000 
+100,006 
+— 
+240,006 
+Thomas J. Smach 
+180,000 
+646,800 
+461,034 
+1,287,834 
+Doreen A. Wright 
+$ 
+147,500 
+$ 
+100,006 
+$ 
+— 
+$ 
+247,506 
+(1) Amounts
+reflect the aggregate grant date fair value of grants computed in accordance with stock-based accounting rules (Financial Standards
+Accounting Board ("FASB") Accounting Standards Codification ("ASC") Topic 718-Stock Compensation), excluding the effect of estimated forfeitures. Assumptions used in to calculate these values are
+included in Note 9 to the Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2013.
+(2) Messrs. Cannon
+and Margolis resigned from the Board effective January 27, 2014. 
+As
+of December 31, 2013, each non-employee director who served during 2013 had the following number of stock options and unvested shares of restricted stock outstanding: 
+Options 
+Outstanding at 
+December 31, 2013 
+Unvested Restricted 
+Stock Awards 
+Outstanding at 
+December 31, 2013 
+W. Stephen Cannon 
+— 
+— 
+Raymond D. Croghan 
+— 
+4,228 
+Ronald L. Frasch 
+— 
+2,340 
+Peter A. Jacobi 
+— 
+4,228 
+Jeffrey H. Margolis 
+— 
+— 
+Thomas J. Smach 
+80,000 
+39,058 
+Doreen A. Wright 
+— 
+6,039 
+Director Ownership Guidelines 
+In June 2013, we modified the stock ownership guidelines for our directors. The guidelines require that each of our directors own shares of our
+common stock in an amount equal in value to a specified multiple (5x for the Chairman of the Board and 3x for all other directors) of such director's annual cash retainer for Board service (not
+including any retainers for service on Board committees), to be achieved by the fifth anniversary of (i) the adoption of the modified guidelines (for our existing directors) or (ii) the
+date of appointment for new directors. 
+19 
+Table of Contents 
+EXECUTIVE COMPENSATION 
+Compensation Discussion and Analysis 
+This Compensation Discussion and Analysis provides information about our executive compensation program as it relates to the following "named
+executive officers" whose compensation information is presented in the tables and accompanying narratives following this discussion: 
+• John P. McCarvel, Chief Executive Officer and President 
+• Jeffrey J. Lasher, Senior Vice President-Finance and Chief Financial Officer 
+• Daniel P. Hart, Executive Vice President, Chief Legal and Administrative Officer 
+• Scott E. Crutchfield, Chief Operating Officer 
+Mr. McCarvel
+has served as our Chief Executive Officer since early 2010 and led our turnaround strategy. On December 27, 2013, Mr. McCarvel resigned from his position as
+President, Chief Executive Officer and director effective upon the earlier to occur of April 30, 2014 and the Board's appointment of his successor as Chief Executive Officer. Details of his
+Separation Agreement can be found on page 27. 
+Executive Summary 
+2013 Business Performance. Our results for 2013 reflect our overall focus on becoming the leading brand in casual lifestyle footwear and delivering shareholder
+value through the balanced global expansion of our direct-to-consumer markets and wholesale partners, innovative product development and strategic financial decisions. Despite ongoing macroeconomic
+challenges around the globe, we grew revenue by $69.4 million, or 6.2%, to approximately $1.2 billion. Revenue growth was driven by increased sales volume and focused improvements on
+average footwear selling prices with new product styles as we continue to transform Crocs brand awareness into an all-season footwear brand. Gross profit increased by 2.5% and diluted earnings per
+share decreased by 91.7% in 2013 compared to 2012, primarily due to increased costs associated with our increased global retail presence and our product strategy to include styles that may utilize
+more expensive materials, as well as certain non-recurring charges. The following table highlights the year-over-year comparison of some of our key financial results. 
+($ in millions, except per share amounts) 
+2013 
+2012 
+Change 
+Annual revenues* 
+$ 
+1,193 
+$ 
+1,123 
+6.2% 
+Annual gross profit 
+$ 
+623 
+$ 
+608 
+2.5% 
+Annual gross margin 
+52.3 
+% 
+54.1 
+% 
+(180 bps) 
+Annual selling, general and administrative costs as a % of revenue 
+46.0 
+% 
+41.0 
+% 
+(500 bps) 
+Diluted earnings per share* 
+$ 
+0.12 
+$ 
+1.44 
+(91.7)% 
+Inventory as of December 31* 
+$ 
+162 
+$ 
+165 
+(1.5)% 
+Cash and cash equivalents as of December 31 
+$ 
+317 
+$ 
+294 
+7.7% 
+* Indicated
+metrics were used as performance measures in our 2013 incentive plans. 
+Pay for Performance Philosophy, Goals and Principles. The Board and the Compensation Committee (the "Committee") are firmly committed to a pay-for-performance
+compensation program. For 2013, over 75% of our Chief Executive Officer's 2013 total direct compensation (base salary, annual incentive and long-term equity incentive) was at risk or performance
+based. Our 2013 annual cash incentive compensation program was tied to the achievement of annual revenue, earnings per share and inventory turnover performance metrics. Our annual long-term equity
+incentive program is designed to align the interests of our executive officers with those of our stockholders, combining time-based restricted stock units (RSUs) whose value depends on the value of
+our common stock and performance-based RSUs that are earned based on our performance on a two-year cumulative earnings per share goal with further time vesting. 
+20 
+Table of Contents 
+Impact of Company Performance on CEO Compensation. Mr. McCarvel's 2013 and prior year compensation reflects our performance and our challenging performance
+goals. His 2013 annual cash incentive award payout was 53.5% of the target amount due to below target performance on the revenue and inventory turnover metrics and below threshold performance on the
+earnings per share metric. The performance-based portion of Mr. McCarvel's 2010 and 2012 RSU awards did not vest based on failure to achieve the applicable threshold cumulative earnings per
+share performance goal and free cash flow metric, while the 2011 award was earned based on achievement of 99% of the target performance goal. In connection with his resignation, Mr. McCarvel
+forfeited the performance-based RSUs granted in 2013 and certain other outstanding RSU awards that were unvested at the effective time of his resignation. 
+Changes in 2014. On January 27, 2014, we sold $200 million of convertible preferred stock to Blackstone, an investment representing approximately 14%
+ownership in the Company on an as converted to common stock basis. We intend to use the proceeds from this investment as well as internal cash to directly benefit our stockholders by repurchasing up
+to $350 million of our common stock. Given the investment from Blackstone and the resignation of our Chief Executive Officer, we expect to undergo strategic transitioning during 2014 to refine
+our short-term and long-term growth strategies, which will include prioritizing earnings growth and our focus on becoming the leading brand in casual lifestyle footwear. 
+Elements of Compensation. Our executive compensation objectives and principles are implemented through the use of the following principal elements of
+compensation: 
+• Base salary, which provides a fixed level of cash compensation; 
+• Annual cash incentive awards, which motivate and reward annual company performance; 
+• Long-term incentives (in the form of equity awards), which motivate and retain executives by rewarding long-term financial
+performance and tying incentives to the performance of our common stock over the long-term; and 
+• Limited executive benefits and perquisites. 
+Corporate Governance Highlights. In order to further align the long-term interests of management with those of our stockholders and align our compensation program
+with best practices, the Committee has established the following policies and practices: 
+• Independent Compensation Committee. The Committee,
+comprised solely of independent directors, approves all compensation for our named executive officers. 
+• Independent compensation consultant. The Committee retains
+an independent compensation consultant that does not provide any services to management. 
+• Assessment of compensation risk. The Committee assessed
+our compensation policies and programs and determined that we have no compensation policies and programs that give rise to risks reasonably likely to have a material adverse effect on the Company. 
+• Annual say-on-pay vote. We hold annual advisory say-on-pay
+votes to approve executive compensation. 
+• Stock ownership guidelines. Our Board adopted robust
+stock ownership guidelines that our officers and non-employee directors are expected to meet within five years. 
+21 
+Table of Contents 
+• Clawback. All annual and long-term incentive awards
+granted since 2012 are subject to any clawback or recoupment policy adopted by us pursuant to the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act. 
+• Limited enhanced benefit programs. We do not provide our
+management with pensions or any other enhanced benefit programs beyond those that are typically available to all other employees other than a deferred compensation plan for senior executives and a
+limited supplemental retirement plan. 
+• Reasonable change of control protections. During 2013, our
+Board approved a change in control plan ("CIC Plan"). The CIC Plan provides for "double trigger" vesting with a definition of "change in control" consistent with our stockholder-approved equity plans.
+In order to keep management focused on the best interests of our stockholders during potentially uncertain periods, the CIC Plan provides our named executive officers with reasonable compensation
+protections upon a change of control followed by a termination without cause or for good reason. 
+• No excise tax gross-ups. We do not provide our management
+with "excise tax gross-ups" in the event of a change of control. 
+• Reasonable severance benefits. In connection with the
+investment from Blackstone and the resignation of our Chief Executive Officer, the Board approved reasonable base salary severance agreements for Messrs. Lasher and Crutchfield in order to
+ensure their continued dedication to us and to diminish the distraction that may occur by virtue of the personal uncertainties and risks created by these events. As described below, the severance
+agreements for Messrs. Lasher and Crutchfield have a limited life of only two years and diminish in value after one year. 
+• Limited perquisites. Our management receives minimal
+perquisites, consisting primarily of health insurance premiums. 
+• No hedging or pledging. We do not allow our management or
+directors to engage in hedging transactions in our stock or to pledge our stock to secure loans or other obligations. 
+• No repricings. Our equity plans do not allow repricing of
+stock option awards without stockholder approval. 
+Executive Compensation Objectives and Principles 
+The objectives of our executive compensation program are to: 
+• attract and retain exemplary executive talent who are able to succeed in our fast-paced, rapidly evolving company; 
+• hold our executives accountable to stockholders; 
+• motivate our executives to achieve our financial and strategic business objectives; 
+• align our executives' compensation with our stockholders' interests; and 
+• assure that our total compensation program aligns with good corporate governance and best practices. 
+In
+2013, we sought to achieve these objectives through implementing the following pay principles. 
+• Fair and
+Competitive: We believe that a fair and competitive pay package for our executives is essential to attract and retain talented
+executives in key positions. 
+22 
+Table of Contents 
+• Short and Long-Term
+Incentives: Our compensation program rewards both short-term and long-term performance. Annual cash incentive awards are tied to
+achievement of short-term quantitative performance goals that we believe closely correlate to stockholder value. Long-term performance is rewarded through equity-based awards, which align our
+executives' interests with those of our stockholders. The value of equity awards depends on future share prices, and the realization of the awards is contingent on satisfaction of vesting schedules
+requiring continued service with us and the achievement of performance goals. 
+• Pay for
+Performance: Our executives have a high proportion of variable, performance-based compensation, including annual cash incentive awards
+and long-term equity awards. We aim to tie more than 50% of our executive pay to performance metrics. In 2013, over 60% of our named executive officer compensation reported in the Summary Compensation
+Table below was performance based. Actual realized compensation will be above or below targeted levels depending on the level of performance achieved. 
+• Good
+Governance: We have designed our executive compensation program in light of the best practice governance policies and practices
+discussed above under "Corporate Governance Highlights." 
+At
+our annual meeting of stockholders in June 2013, we held our third advisory stockholder vote to approve the compensation of our named executive officers ("say-on-pay"). The compensation of our
+named executive officers reported in our 2013 proxy statement was approved by over 99% of the votes cast at the 2013 annual meeting, similar to the results at our 2012 and 2011 annual meetings. The
+Committee believes this affirms our stockholders' support of our approach to executive compensation, and the Committee did not change its approach in 2013. The Committee has considered and will
+continue to consider the outcome of our say-on-pay votes when making future compensation decisions for the named executive officers. 
+Governance of Pay Setting Process 
+Role of Compensation Committee, Chief Executive Officer and Compensation Consultant 
+The Committee has overall responsibility for evaluating and approving our executive officer compensation, benefits, severance, equity-based or other
+compensation plans, policies and programs. The Committee sets the Chief Executive Officer's compensation, and considers the recommendations of the Chief Executive Officer with respect to the
+compensation of the other named executive officers. The Committee works with Towers Watson, an independent executive compensation consultant engaged by the Committee, for advice and perspective
+regarding market trends and best practices. For a more detailed discussion about the Committee, its methodology and the role of consultants, see "Compensation Committee" on page 9. 
+Peer Group Companies 
+The Committee uses peer company and survey data to guide its review of the total compensation of our officers and executives and generally reviews
+the compensation data of our peer companies and industry to understand market competitive compensation. The Committee focuses on ensuring that the performance-based elements of our executive
+compensation program are consistent with peer and industry trends. However, the Committee does not benchmark compensation to a specific percentage of the compensation of peer companies. 
+The
+Committee has approved a peer group based on analysis and recommendations by Towers Watson. The peer group is selected based on the key industry criteria noted below, and takes into consideration
+the company's revenue, market capitalization and other key financial metrics. This peer group is 
+23 
+Table of Contents 
+comprised
+of 14 publicly traded companies. As of December 31, 2013, our market capitalization was at the 14th percentile of this group, and our annual revenue was at the
+14th percentile of the group, based on annual revenue as of the most recent applicable fiscal year end. We believe these companies are broadly comparable to us, and represent our labor market
+for talent for key leadership positions. The Committee regularly reviews our peer group to determine if adjustments are necessary to ensure that it continues to be relevant or if additional peer
+companies or groups are necessary to provide appropriate information on market practices and compensation levels. 
+The
+2013 peer companies are listed below: 
+Columbia Sportswear Co. 
+G III Apparel Group, Ltd. 
+Skechers USA, Inc. 
+Deckers Outdoor Corp. 
+lululemon athletica inc. 
+Steven Madden, LTD 
+DSW Inc. 
+Oxford Industries, Inc. 
+Under Armour, Inc. 
+Fossil, Inc. 
+Perry Ellis International, Inc. 
+Wolverine Worldwide, Inc. 
+Genesco Inc. 
+Quiksilver, Inc. 
+The
+only difference between the peer group used in 2013 and the peer group used in the 2012 executive compensation review process was the removal of The Warnaco Group, Inc., as it was acquired
+by PVH Corp. in February 2013. 
+Elements of Compensation 
+As noted, we utilize the following principal elements of compensation, each of which is discussed more fully
+below: 
+• Base salary, which provides a fixed level of cash compensation; 
+• Annual cash incentive awards, which motivate and reward annual company performance; 
+• Long-term incentives (in the form of equity awards), which motivate and retain executives by rewarding long-term financial
+performance and tying incentives to the performance of our common stock over the long-term; and 
+• Limited executive benefits and perquisites. 
+The
+Committee does not utilize an exact calculation in determining the break-down or weighting of named executive officer compensation among base salary, annual cash incentive awards and long-term
+equity awards. Rather, the Committee considers all forms of compensation in light of the market competition for executive talent, the risk to an executive inherent in employment with our fast-paced,
+rapidly evolving Company and our financial goals. Accordingly, we believe that over 50% of each named executive officer's compensation should be in the form of annual cash performance-based awards and
+equity awards that vest upon performance. We believe that the total compensation opportunities offered to our executives are sufficient to reduce the need for anything other than limited executive
+perquisites or enhanced benefit programs beyond those that are typically available to all other employees. 
+Base Salary. The Committee establishes base salary for our named executive officers by considering the size of our operations, the responsibilities of the named
+executive officers and the competitive marketplace for executive talent in similar positions. The Committee sets the base salary of the Chief Executive Officer. Base salary for other named executive
+officers is set by the Committee after considering the recommendation of the Chief Executive Officer. 
+Base
+salary is reviewed on an annual basis and at the time of hire or promotion. Annual adjustments are influenced by growth of our operations, revenues and profitability, individual performance,
+changes 
+24 
+Table of Contents 
+in
+responsibility, peer company comparisons and other factors. In 2012, after considering a peer company comparative review with Towers Watson, and for retention purposes, the Committee approved
+increases to the 2013 base salaries of Messrs. McCarvel, Lasher and Crutchfield. There was no change to the base salary for Mr. Hart. 
+The
+current base salaries of our named executive officers are below: 
+Named Executive Officer 
+2013 Base Salary 
+Increase Over 
+2012 Base Salary 
+John P. McCarvel 
+$ 
+1,000,000 
+19 
+% 
+Daniel P. Hart 
+$ 
+498,750 
+0 
+% 
+Jeffrey J. Lasher 
+$ 
+400,000 
+19 
+% 
+Scott E. Crutchfield 
+$ 
+400,000 
+19 
+% 
+Annual Incentive Awards. The Committee believes that an annual cash incentive plan that offers significant awards to our named executive officers for meeting or
+exceeding company performance goals provides our officers additional incentive to outperform our peer companies and ensures that we attract and retain talented named executive officers. 
+Each
+year, the Committee establishes a target annual incentive award for each named executive officer expressed as a percentage of the executive's base salary, based on the estimated contribution and
+responsibility of the individual named executive officer and considering market practices. For 2013, the targets were: 
+Named Executive Officer 
+Annual Incentive Plan Target 
+(as a percentage of Base Salary) 
+John P. McCarvel 
+100 
+% 
+Daniel P. Hart 
+60 
+% 
+Jeffrey J. Lasher 
+60 
+% 
+Scott E. Crutchfield 
+60 
+% 
+The
+total annual incentive award actually paid to each named executive officer is determined based on the extent to which specified weighted objective performance goals are achieved. Each of these
+performance targets has a threshold payout of 75% of the named executive officer's annual incentive award target and a maximum payout of 175% of the target. For 2013, these goals and their applicable
+weightings were: 
+2013 Performance Goal Targets 
+Actual 2013 Results 
+Weighting 
+Weighted 2013 Actual 
+Performance as a 
+Percentage of Target 
+Annual Revenues: $1,300.3 million 
+$1,192.7 million 
+50% 
+38.5% 
+Earnings Per Share: $1.51 
+$0.12 
+30% 
+0.0% 
+Inventory Turnover: 3.6 
+3.5 
+20% 
+15.0% 
+Based
+on 2013 actual results and applying the weighting described above, our named executive officers were eligible to be paid annual cash incentive awards at up to 53.5% of their respective target
+annual incentive award amounts. The Committee has discretion to depart from the formula in approving the annual incentive awards by decreasing, but not increasing, incentive awards after general
+results are known, but did not exercise that discretion in 2013. 
+The
+Committee sets the annual performance goal targets under the annual cash incentive plan in the first quarter of each fiscal year. For 2014, payments under the annual cash incentive plan will be
+based on achievement of performance goals relating to 2014 earnings before interest and taxes (60% weighting), revenue (30% weighting) and inventory turnover (10% weighting). 
+25 
+Table of Contents 
+Long-Term Equity Awards. The Committee grants long-term equity awards annually to the named executive officers in order to provide long-term performance-based
+compensation, to encourage the named executive officers to continue their employment throughout the vesting periods of the awards, and to align management and stockholder interests. We believe that a
+significant portion of each named executive officer's compensation should be in the form of equity awards. Each year the Committee considers the number of shares to grant and the appropriate type and
+combination of equity-based awards in making named executive officer grant decisions. 
+2013 Long-Term Performance Incentive Program. In 2013, all of our named executive officers received grants of restricted stock units ("RSUs"), half of which vest
+based on satisfaction of performance goals and half of which vest based on continued service. The material terms of the 2013 RSU awards are as follows: 
+Performance Vested RSUs (50% of Award) 
+Time Vested RSUs 
+(50% of Award) 
+Performance Goal 
+Potential Award 
+Further Time Vesting 
+Vest in three annual installments beginning one year after the date of grant 
+Achievement of at least 70% of a two-year cumulative earnings per share performance goal 
+Executive may earn from 50% to 200% of the target number of RSUs based on the level of achievement of the performance goal 
+Earned RSUs vest 50% upon satisfaction of performance goal and 50% one year later 
+For
+2013, the amount of RSU awards granted to the named executive officers was based on a review of the equity compensation of our peer companies, input from the independent compensation consultant
+and the Committee's assessment of each named executive officer's expected future contributions. 
+The
+Committee grants performance-based awards to further demonstrate our pay for performance philosophy and better align the interests of our named executive officers with those of our stockholders.
+The Committee grants RSUs because it generally believes that full value awards such as RSUs offer a stronger retention incentive than do stock options. In addition, RSUs are less dilutive to our
+current stockholders as fewer RSUs are necessary to provide the same equity benefit compared to stock options. 
+The
+Committee selected cumulative earnings per share as the performance metric used in the 2013 RSU grant because it views cumulative earnings per share as a primary driver of enhanced stockholder
+value. The performance based portion of the RSUs granted to our executive officers in 2010 (based on a free cash flow performance goal) and 2012 (based on a cumulative earnings per share performance
+goal) did not vest based on failure to achieve the applicable performance goal. The RSUs granted to our executive officers in 2011 achieved 99% of the cumulative earnings per share performance goal.
+Therefore, the Compensation Committee believes cumulative earnings per share performance goals set by the Committee are very challenging further demonstrating the Committee's pay for performance
+philosophy. 
+Other Benefits. We provide other benefits to our named executive officers in order to achieve a competitive pay package. The Committee believes that those
+benefits, which are detailed in the Summary Compensation Table under the heading "All Other Compensation," are reasonable,
+competitive and consistent with our overall executive compensation program. Those benefits consist principally of employer-paid premiums on health insurance. 
+26 
+Table of Contents 
+Post-Employment Compensation 
+Senior Executive Deferred Compensation Plan. Certain senior executives are eligible to participate in the 2007 Senior Executive Deferred Compensation Plan (the
+"Deferred Compensation Plan"), which permits executives to defer all or a part of their cash compensation and save for future financial needs. No named executive officers have contributed to the
+Deferred Compensation Plan since 2008. For a more detailed discussion of the Deferred Compensation Plan, see the Nonqualified Deferred Compensation table and accompanying narrative below. 
+Mr. McCarvel's Separation Agreement. As noted above, Mr. McCarvel resigned as our Chief Executive Officer on December 27, 2013 effective upon
+the earlier to occur of April 30, 2014 and the Board's appointment of his successor as Chief Executive Officer. The Board negotiated and approved potential separation payments to
+Mr. McCarvel in the aggregate of $2.1 million in exchange for a release of claims in favor of the Company and his compliance with the noncompetition, nonsolicitation and confidentiality
+covenants contained in the Separation Agreement. The separation payments are subject to clawback and offsets upon certain violations of such covenants by Mr. McCarvel. For a more detailed
+discussion of the Separation Agreement, see the Potential Payments on Termination or Change in Control below. 
+Change in Control Benefits. In 2013, we approved and adopted the CIC Plan for eligible employees, including the named executive officers. The CIC Plan contains a
+"double trigger" whereby if a "change in control" occurs and the participant's employment is terminated by us without "cause" or the participant resigns for "good reason" within the two-year period
+following the change in control, the executive officer participants will be entitled to accelerated vesting of certain equity awards, a multiple of salary and bonus and certain continuing health care
+benefits. The Committee believes that this
+approach will enhance stockholder value in the context of an acquisition, and align executives with the interests of our stockholders. For a more detailed discussion of the CIC Plan and definitions of
+"change in control," "cause," and "good reason" under CIC Plan, see the Potential Payments on Termination or Change in Control below. 
+Severance Agreements. On December 26, 2013, the Board approved a form of severance agreement (the "Severance Agreement") and authorized us to enter into
+Severance Agreements with certain officers, including Messrs. Lasher and Crutchfield. The Severance Agreement provides that if we terminate either Mr. Lasher's or
+Mr. Crutchfield's employment without "cause" (i) at any time prior to December 26, 2014, the executive will be entitled to receive a severance payment in cash equal to two times
+the executive's annual base salary and (ii) at any time after December 26, 2014, but before December 26, 2015, the executive will be entitled to receive a severance payment in
+cash equal to the executive's annual base salary. The separation payments are conditioned upon the effectiveness of the executive's release of claims in favor of us and compliance with the
+noncompetition, nonsolicitation and confidentiality covenants in the Severance Agreement. For a more detailed discussion of the Severance Agreement, see Potential Payments on Termination or Change in
+Control below. 
+Employment Agreement. We entered into an employment agreement with Mr. Hart concurrent with his appointment as an officer in 2009. The agreement provides
+for guaranteed payments and accelerated vesting of certain equity awards upon his involuntary termination of employment with us (other than for "cause") or his resignation for "good reason." For a
+more detailed discussion of the agreement and definitions of "cause" and "good reason," see Potential Payments on Termination or Change in Control below. 
+Additional Considerations 
+Executive Stock Ownership. In June 2013, the Committee increased stock ownership guidelines to ensure that our executive officers have a meaningful stake in the
+equity of the Company and to further 
+27 
+Table of Contents 
+align
+the interests of our executives with the long-term interests of our stockholders. The guidelines require that each of our named executive officers own shares of our common stock in an amount
+equal in value to a specified multiple (5x for our Chief Executive Officer and 3x for all other named executive officers) of such named executive officer's base salary, to be achieved by the fifth
+anniversary of (i) the adoption of the modified guidelines (for our existing executive officers) or (ii) the date of hire for new executive officers. The ownership guidelines are based
+on analysis of peer and market practices, as prepared by the Committee's independent compensation consultant. 
+Equity Granting Practices. The Committee has generally determined to make our annual equity award grants at the regular meeting of the Committee held in the first
+quarter of each year. The Committee meeting date, or the next business day if the meeting falls on a day where the Nasdaq is closed for trading, is typically the effective grant date for the grants.
+For stock options, the exercise price is the fair market value of our common stock on that date. 
+We
+also may grant equity awards (e.g., options, restricted stock) to recognize increased responsibilities or special contributions, attract new hires, retain executives or recognize certain
+other special circumstances that occur throughout the year. The effective date of these grants is determined based on the timing of the recognition or recruitment event and approved on or in advance
+of the effective date of the grant. The exercise/grant price is the fair market value of our common stock on the effective date. The Committee approves all equity grants to executive officers. We do
+not permit repricing of stock options without stockholder approval. 
+Clawbacks. In 2010, our Compensation Committee adopted a clawback policy for awards made under our annual incentive plan. Under this policy, at the discretion of
+the Committee, executives may be required to repay awards to us if within two years of the award: (i) we are required to restate our financial statements due to fraud or willful misconduct
+involving the executive; or (ii) the executive took part in any fraud, negligence or breach of fiduciary duty. 
+In
+2012, our Board also adopted a policy whereby any incentive compensation awards granted to management, including annual and long-term incentive awards granted in 2013, will be subject to any
+clawback or recoupment policy adopted by the us pursuant to the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act. 
+Deductibility of Executive Compensation. Section 162(m) of the Code imposes a $1.0 million annual limit on the amount that a public company may
+deduct for compensation paid to the company's chief executive officer during a tax year or to any of the company's four other most highly compensated executive officers who are still employed at the
+end of the tax year. The limit does not apply to compensation that meets the requirements of the Code for "qualified performance-based" compensation (i.e., compensation paid only if the
+executive meets pre-established, objective goals based on performance criteria approved by the company's stockholders). 
+The
+Committee reviews and considers the deductibility of executive compensation under Section 162(m) of the Code. In certain situations, the Committee may approve compensation that does not
+meet the requirements of the Code in order to ensure competitive levels of total compensation for our executive officers. The annual incentive awards paid in 2013 under our 2008 Cash Incentive Plan
+and the performance-vested restricted stock units granted in 2013 are designed to meet the requirements for consideration as "qualified performance-based compensation" under Section 162(m). 
+28 
+Table of Contents 
+COMPENSATION COMMITTEE REPORT 
+The
+Compensation Committee has reviewed and discussed the foregoing Compensation Discussion and Analysis with our management. Based on such review and discussion, the Compensation Committee
+recommended to the Board that the foregoing Compensation Discussion and Analysis be included in this proxy statement. 
+THE
+COMPENSATION COMMITTEE 
+Doreen A. Wright (Chairperson) 
+Raymond D. Croghan 
+Prakash A. Melwani 
+Summary Compensation Table 
+The following table sets forth information regarding compensation earned for services rendered during fiscal years 2013, 2012, and 2011 for our Chief
+Executive Officer, our Chief Financial Officer, and the two other most highly compensated executive officers who were serving as executive officers at the end of 2013. 
+Name and Principal Position 
+Year 
+Salary 
+($) 
+Stock 
+Awards (1) ($) 
+Option 
+Awards (1) ($) 
+Non-Equity 
+Incentive Plan 
+Compensation 
+($) 
+All Other 
+Compensation (2) ($) 
+Total 
+($) 
+John P. McCarvel 
+2013 
+$ 
+1,000,000 
+$ 
+2,994,617 
+$ 
+— 
+$ 
+535,000 
+$ 
+98,282 
+$ 
+4,627,899 
+President and Chief Executive Officer 
+2012 
+840,000 
+1,313,550 
+— 
+— 
+32,203 
+2,185,753 
+2011 
+828,333 
+2,349,981 
+— 
+1,285,200 
+15,015 
+4,478,529 
+Daniel P. Hart 
+2013 
+498,750 
+938,879 
+— 
+175,164 
+27,512 
+1,640,305 
+Executive Vice President, Chief Legal 
+2012 
+498,750 
+462,175 
+— 
+— 
+29,883 
+990,808 
+and Administrative Officer 
+2011 
+491,823 
+475,019 
+— 
+450,000 
+14,606 
+1,431,448 
+Jeffrey J. Lasher 
+2013 
+400,000 
+745,000 
+— 
+122,237 
+26,000 
+1,293,237 
+Senior Vice President-Finance 
+2012 
+332,313 
+462,175 
+— 
+— 
+32,260 
+826,748 
+and Chief Financial Officer 
+2011 
+300,000 
+1,078,320 
+266,802 
+300,000 
+14,606 
+1,959,728 
+Scott E. Crutchfield 
+2013 
+400,000 
+871,571 
+— 
+135,629 
+26,235 
+1,433,435 
+Chief Operating Officer 
+2012 
+332,313 
+462,175 
+— 
+— 
+32,957 
+827,445 
+2011 
+$ 
+325,000 
+$ 
+350,009 
+$ 
+— 
+$ 
+240,000 
+$ 
+15,106 
+$ 
+930,115 
+(1) Amounts
+reflect the aggregate grant date fair value of grants made in each respective fiscal year computed in accordance with stock-based
+accounting rules (FASB ASC Topic 718-Stock Compensation), excluding the effect of estimated forfeitures. Assumptions used in the calculations of these amounts are included in Note 9 to our
+Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2013. The grant date fair value of stock awards, which are comprised of
+time-vested and performance-vested restricted stock units, includes the grant date fair value for the performance-vested restricted stock units calculated based on the target amount for the award
+period commencing in the year indicated. For 2013, the total aggregate grant date fair value of stock awards, including the time-vested restricted stock units and the performance-vested restricted
+stock units assuming the highest level of payout for performance against assigned targets would be as follows: $4.2 million for Mr. McCarvel, $1.3 million for Mr. Hart,
+$1.1 million for Mr. Lasher, and $1.2 million for Mr. Crutchfield.
+(2) All
+other compensation for 2013 represents the following: (i) Company matches to employee 401(k) contributions in the amounts of
+$10,000 for Mr. Hart, Mr. Lasher, Mr. Crutchfield, and Mr. McCarvel, (ii) a $9,600 car allowance for Mr. McCarvel, (iii) $14,919 in incremental
+healthcare premiums paid by us on behalf of each named executive officer that is not offered to other non-executive employees, (iv) group term life insurance premiums paid-in full by the
+Company for each named executive officer, (v) certain recognition gifts made to the named executive officers and (vi) $61,440 in tax preparation fees paid for by us on behalf of
+Mr. McCarvel. 
+29 
+Table of Contents 
+Grants of Plan-Based Awards Table 
+The following table provides information for each of our named executive officers regarding annual and long-term incentive award opportunities,
+including the range of potential payouts under our non-equity annual incentive plan and our performance-vested restricted stock units granted during fiscal year 2013. 
+Estimated Future 
+Payouts Under 
+Non-Equity 
+Incentive 
+Plan Awards 
+Estimated Future 
+Payouts Under 
+Equity Incentive 
+Plan Awards 
+All Other 
+Stock Awards: 
+Number of 
+Shares of 
+Stock or 
+Units 
+(#) 
+Grant Date 
+Fair Value 
+of Stock 
+and Option 
+Awards (1) 
+($) 
+Name 
+Type of Award 
+Grant 
+Date 
+Target 
+($) 
+Maximum 
+($) 
+Threshold 
+(#) 
+Target 
+(#) 
+Maximum 
+(#) 
+John P. McCarvel 
+Annual Incentive Award 
+1,000,000 
+1,750,000 
+Restricted Stock Unit 
+2/21/2013 
+39,375 
+78,750 
+157,500 
+78,750 
+2,346,750 
+Restricted Stock Unit 
+1/29/2013 
+42,679 
+647,867 
+Daniel P. Hart 
+Annual Incentive Award 
+299,250 
+523,688 
+Restricted Stock Unit 
+2/21/2013 
+12,500 
+25,000 
+50,000 
+25,000 
+745,000 
+Restricted Stock Unit 
+1/29/2013 
+12,772 
+193,878 
+Jeffrey J. Lasher 
+Annual Incentive Award 
+240,000 
+420,000 
+Restricted Stock Unit 
+2/21/2013 
+12,500 
+25,000 
+50,000 
+25,000 
+745,000 
+Scott E. Crutchfield 
+Annual Incentive Plan 
+240,000 
+420,000 
+Restricted Stock Units 
+2/21/2013 
+12,500 
+25,000 
+50,000 
+25,000 
+745,000 
+Restricted Stock Unit 
+1/29/2013 
+8,338 
+126,570 
+(1) The
+aggregate grant date fair value for the restricted stock units was calculated based on the target number of restricted stock units. 
+Annual Incentive Awards. The amounts shown for annual incentive awards represent the target and maximum amounts of annual cash incentive compensation that,
+depending on performance results, might have been paid to each executive for 2013 performance based on achievement of specified target levels of revenue, earnings per share and inventory turnover. The
+target payments were based on achieving the target level of performance with ranges from zero to 175% of the executive's annual incentive target. In 2013, annual incentive amounts were paid at 53.5%
+of target, as reflected in the "Non-Equity Incentive Plan Compensation" column of the "Summary Compensation Table" set forth above. These awards are described in further detail under "Compensation
+Discussion and Analysis" above. 
+Restricted Stock Units ("RSUs"). The amounts shown for RSUs represent the number of RSUs awarded to the executives in 2013 and the grant date fair value of the
+RSUs determined in accordance with FASB ASC 718, as follows. The amounts shown for RSUs granted on February 21, 2013 represent awards of restricted stock units to certain of our named executive
+officers as part of a performance incentive plan. One-half of these RSUs vest in three equal annual installments beginning one year after the date of grant based on continued employment. The other
+half may be earned from 50% to 200% of the target number of RSUs based on the level of achievement of a two-year cumulative earnings per share performance goal, and vest in two equal annual
+installments, 50% on certification of the achievement of performance goal by the Compensation Committee and 50% one year later subject to continued employment. These RSU awards are described in
+further detail under "Compensation Discussion and Analysis" above. 
+Employment Agreement with Mr. Hart. In May 2009, we entered into an employment agreement with Mr. Hart. The agreement provides that Mr. Hart
+will receive an annual base salary of $475,000, subject to annual adjustments. His salary may be reduced only if such reduction is a uniformly applied reduction affecting all senior executives and is
+no greater than 10% of Mr. Hart's base pay in any case, may not be reduced by greater than $47,500 in total during his employment with us. Mr. Hart is also eligible for a bonus pursuant
+to our annual incentive plan. Mr. Hart's target under the annual incentive plan was 60% of his base pay in 2013. He is also entitled to participate in all employee benefit plans and programs
+generally available to our executives, including our Deferred Compensation Plan. The 
+30 
+Table of Contents 
+agreement
+also contains provisions relating to benefits Mr. Hart may receive in connection with a termination of his employment, as described in further detail under "Potential Payments on
+Termination or Change in Control." Mr. Hart's Agreement requires him to maintain confidential information regarding us and to assign certain inventions and intellectual property to us. During
+his employment with us and for twelve months after the termination of his employment with us, Mr. Hart will be restricted from participating in certain competitive businesses and from
+soliciting our employees and customers. 
+Salary and Bonus in Proportion to Total Compensation. As noted in "Compensation Discussion and Analysis" above, we believe that a substantial portion of each named
+executive officer's compensation should be in the form of performance-based annual incentive awards and equity awards. Base salary of the named executive officers is set at levels that the
+Compensation Committee believes are competitive with our peer companies, with the expectation that shortfalls in base pay, if any, will be recouped through performance bonuses. The Compensation
+Committee believes that our current program substantially aligns the compensation of our named executive officers with the compensation of executive officers of our peer companies, while also
+permitting the Compensation Committee to provide incentives to the named executive officers to pursue performance that increases stockholder value. Please see "Compensation Discussion and Analysis"
+for a description of the objectives of our compensation program and overall compensation philosophy. 
+Outstanding Equity Awards at Fiscal Year-End 
+The following table sets forth information regarding outstanding options and unvested restricted stock and restricted stock unit awards held by our
+named executive officers as of December 31, 2013. Market values for outstanding stock awards are presented as of the end of 2013 based on the closing price of our common stock on the NASDAQ
+Global Select Market on December 31, 2013 of $15.92. 
+Option Awards 
+Stock Awards 
+Name 
+Number of 
+Securities 
+Underlying 
+Unexercised 
+Options (#) 
+Exercisable 
+Number of 
+Securities 
+Underlying 
+Unexercised 
+Options (#) 
+Unexercisable 
+Option 
+Exercise 
+Price 
+($) 
+Option 
+Expiration 
+Date 
+Number of 
+Shares or 
+Units of 
+Stock That 
+Have Not 
+Vested (#) 
+Market Value 
+of Shares or 
+Units of 
+Stock That 
+Have Not 
+Vested ($) 
+Equity Incentive 
+Plan Awards: 
+Number of 
+Unearned 
+Shares, Units or 
+Other Rights 
+That Have Not 
+Vested (#) (1) 
+Equity 
+Incentive Plan 
+Awards: 
+Market or 
+Payout Value of 
+Unearned 
+Shares, Units 
+or Other 
+Rights That 
+Have Not 
+Vested ($) 
+John P. McCarvel 
+80,454 
+— 
+$ 
+1.14 
+11/17/2018 
+10,086 
+— 
+10.50 
+02/07/2016 
+58,840 
+(2) 
+936,732 
+— 
+— 
+Daniel P. Hart 
+70,831 
+— 
+3.99 
+06/15/2019 
+56,433 
+(3) 
+898,413 
+49,430 
+786,925 
+Jeffrey J. Lasher 
+20,000 
+10,000 
+(4) 
+20.11 
+04/29/2021 
+28,000 
+— 
+3.99 
+06/15/2019 
+51,522 
+(5) 
+820,230 
+40,875 
+650,730 
+Scott E. Crutchfield 
+33,000 
+— 
+1.14 
+11/17/2018 
+43,548 
+— 
+$ 
+10.50 
+02/07/2016 
+49,108 
+(6) 
+781,799 
+45,875 
+730,330 
+(1) The
+aggregate number of restricted stock units was calculated based on the achievement of target performance.
+(2) Represents
+the unvested portion of three restricted stock grants for: (i) 33,750 restricted stock units awarded on March 14,
+2012 of which one-third of the restricted stock units vested on March 14, 2013, one-third were cancelled on December 27, 2013 per Mr. McCarvel's separation agreement and one-third
+vested on March 14, 2014; (ii) 42,679 restricted stock units awarded on January 29, 2013 of which one-half were cancelled on December 27, 2013 per Mr. McCarvel's
+separation agreement and one-half vested on January 29, 2014; and (iii) 78,750 restricted stock units awarded on February 21, 2013 of which two-thirds of the shares were cancelled
+on December 27, 2013 per Mr. McCarvel's separation agreement and one-third of the shares vested on March 1, 2014.
+(3) Represents
+the unvested portion of five restricted stock grants for: (i) 25,110 shares awarded on June 15, 2010 of which half
+vest ratably on each of the first four anniversaries of the grant date based on continued employment and the other half based on achievement of performance metrics which were not met resulting in
+forfeiture on February 7, 2014; (ii) 18,376 restricted stock units awarded on June 28, 2011 of which one-half of the restricted stock units vest in three equal installments on
+June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and up to one-half of the restricted stock units based on target 
+31 
+Table of Contents 
+performance
+which on February 26, 2013 were certified 99% achieved and as a result 4,537shares vested on February 26, 2013 and 4,537 vested on February 26, 2014;
+(iii) 23,750 restricted stock units awarded on March 14, 2012 of which one-half of the restricted stock units ratably on each of the first three anniversaries of the grant date based on
+continued employment and the other half based on achievement of performance metrics which were not met resulting in forfeiture on February 7, 2014; (iv) 12,772 restricted stock units
+awarded on January 29, 2013 of which 50% of the shares vested on January 29, 2014, 40% will vest on January 29, 2015 and 10% will vest on January 29, 2016; and
+(v) 50,000 restricted stock units awarded on February 21, 2013 of which one-half of the restricted stock units vest in three equal annual installments on March 1, 2014,
+March 1, 2015 and March 1, 2016 based on continued employment and up to one-half of the restricted stock units based on target performance vest in two equal annual installments on the
+date in 2015 that the achievement of certain performance metrics is established and one year from that date, respectively, based on continued employment. 
+(4) Represents
+the unvested portion of stock options to purchase 30,000 shares of common stock, which were granted on April 29, 2011. This
+stock option award has a four year vesting period with 25% vesting on the first anniversary of the grant date and the remaining options vesting in 36 equal monthly installments thereafter, based on
+continued employment.
+(5) Represents
+the unvested portion of five restricted stock grants for: (i) 8,000 shares awarded on August 2, 2010 half of which
+vest ratably on June 15, 2011, June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and the other half based on achievement of performance metrics
+which were not met resulting in forfeiture on February 7, 2014; (ii) 30,000 shares granted on April 29, 2011 which vest annually in equal installments on the next three grant date
+anniversaries, based on continued employment; (iii) 18,376 restricted stock units awarded on June 28, 2011 half of which vest in three equal installments on June 15, 2012,
+June 15, 2013 and June 15, 2014 based on continued employment and up to one-half of the restricted stock units based on target performance which on February 26, 2013 was certified
+99% achieved and as a result 4,537shares vested on February 26, 2013 and 4,537 vested on February 26, 2014; (iv) 23,750 restricted stock units awarded on March 14, 2012 of
+which one-half of the restricted stock units vest in three equal annual installments on March 14, 2013, March 14, 2014 and March 14, 2015 based on continued employment and the
+other half based on achievement of performance metrics which were not met resulting in forfeiture on February 7, 2014; and (v) 50,000 restricted stock units awarded on
+February 21, 2013 of which one-half of the restricted stock units vest in three equal annual installments on March 1, 2014, March 1, 2015 and March 1, 2016 based on
+continued employment and up to one-half of the restricted stock units based on target performance vest in two equal annual installments on the date in 2015 that the achievement of certain performance
+metrics is established and one year from that date, respectively, based on continued employment.
+(6) Represents
+the unvested portion of five restricted stock grants for: (i) 18,000 shares awarded on August 2, 2010 half of which
+vest ratably on June 15, 2011, June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and the other half based on achievement of performance metrics
+which were not met resulting in forfeiture on February 7, 2014; (ii) 13,540 restricted stock units awarded on June 28, 2011 half of which vest in three equal installments on
+June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and up to one-half of the restricted stock units based on target performance which on
+February 26, 2013 was certified 99% achieved and as a result 3,343shares vested on February 26, 2013 and 3,343 vested on February 26, 2014; (iii) 23,750 restricted stock
+units awarded on March 14, 2012 of which one-half of the restricted stock units vest in three equal annual installments on March 14, 2013, March 14, 2014 and March 14, 2015
+based on continued employment and the other half based on achievement of performance metrics which were not met resulting in forfeiture on February 7, 2014; (iv) 8,338 restricted stock
+units awarded on January 29, 2013 of which 50% of the shares vested on January 29, 2014, 40% vest on January 29, 2015 and 10% vest on January 29, 2016; and
+(v) 50,000 restricted stock units awarded on February 21, 2013 of which one-half of the restricted stock units vest in three equal annual installments on March 1, 2014,
+March 1, 2015 and March 1, 2016 based on continued employment and up to one-half of the restricted stock units based on target performance vest in two equal annual installments on the
+date in 2015 that the achievement of certain performance metrics is established and one year from that date, respectively, based on continued employment. 
+Options Exercises and Stock Vested 
+The following table sets forth information for each of our named executive officers regarding stock options exercised and stock awards vested during
+2013. 
+Option Awards 
+Stock Awards 
+Name 
+Number of 
+Shares Acquired 
+on Exercise 
+(#) 
+Value 
+Realized on 
+Exercise 
+($) (1) 
+Number of 
+Shares Acquired 
+on Vesting 
+(#) 
+Value 
+Realized on 
+Vesting 
+($) (1) 
+John P. McCarvel 
+25,000 
+$ 
+117,200 
+54,650 
+$ 
+879,935 
+Daniel P. Hart 
+12,502 
+154,080 
+14,694 
+234,783 
+Jeffrey J. Lasher 
+— 
+— 
+22,555 
+359,375 
+Scott E. Crutchfield 
+— 
+— 
+11,806 
+$ 
+188,870 
+(1) For
+option awards, the value realized is the difference between the fair market value of our common stock at the time of exercise and the
+exercise price. For stock awards, the value realized is based on the closing price of our common stock on the vesting date. 
+32 
+Table of Contents 
+Nonqualified Deferred Compensation 
+Under our Deferred Compensation Plan, participants have the option to defer all or a part of their cash compensation in accordance with the terms and
+conditions established by the Compensation Committee. The deferred amount will vest ratably on a quarterly basis over a three-year period, with a pro rata amount vesting on each calendar quarter. Any
+unvested balance will vest immediately upon the death or disability of the participant or upon a "change in control," as defined in the plan. None of the named executive officers have deferred any
+compensation since 2008. The table below summarizes the 2013 accrued earnings and balances at December 31, 2013 under our Deferred Compensation Plan for each of the named executive officers. 
+Name 
+Executive 
+Contributions 
+in Last Fiscal 
+Year 
+$ 
+Registrant 
+Contributions 
+in Last Fiscal 
+Year 
+$ 
+Aggregate 
+Earnings in 
+Last Fiscal 
+Year (1) 
+$ 
+Aggregate 
+Withdrawals/ 
+Distributions 
+$ 
+Aggregate 
+Balance at 
+Last Fiscal 
+Year End 
+$ 
+John P. McCarvel 
+$ 
+— 
+$ 
+— 
+$ 
+5,576 
+$ 
+— 
+$ 
+816,280 
+Daniel P. Hart 
+— 
+— 
+— 
+— 
+— 
+Jeffrey J. Lasher 
+— 
+— 
+— 
+— 
+— 
+Scott E. Crutchfield 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+(1) Each
+participant in the Deferred Compensation Plan may choose, at his or her discretion, a portfolio of investments in which their
+contributions may be hypothetically invested. We are not obligated to invest the participant's contributions into these accounts; however, upon the participant's withdrawal, we are obligated to pay
+the amount, inclusive of earnings, interest, and capital gains, that the participant's contributions would have earned had we actually invested the money as the participant directed. The aggregate
+earnings on each individual's contribution varies widely depending on the portfolio of investments the participant chooses. We received investment direction from Mr. McCarvel and the aggregate
+earnings from those hypothetical investments are reflected in the table above. 
+Potential Payments on Termination or Change in Control 
+CIC Plan 
+Except for Mr. McCarvel, our named executive officers are participants in the CIC Plan, which was adopted by the Board in June 2013 and later
+amended and restated. Under the Plan, if a "change in control" (as defined below) occurs, and the named executive officer's employment is terminated by us without "cause" (as defined below) or the
+named executive officer resigns for "good reason" (as defined below) within the two-year period following the change in control, the named executive officer will be entitled to the following payments
+and benefits: 
+• up to two times the sum of (i) the named executive officer's annual base salary in effect on the date immediately
+prior to the change in control and (ii) the greater of (x) the named executive officer's target annual bonus for the year in which the change in control occurs and (y) the average
+annual bonus payments actually made to the named executive officer in the three years prior to the year in which the change in control occurs; 
+• full vesting of any time-vested equity awards held by the named executive officer; 
+• vesting at the target performance level of any performance-based equity awards held by the named executive officer; 
+33 
+Table of Contents 
+• if the named executive officer is age 55 or over, payment by us of the employer and employee premiums for continued health
+coverage for the named executive officer and his/her covered dependents until the named executive officer becomes eligible to enroll in Medicare Part A or until the named executive officer
+becomes eligible for coverage under a subsequent employer's health plan; and 
+• if the named executive officer is under age 55, payment by us of the employer and employee premiums for continued health
+coverage for the named executive officer and his/her covered dependents for the shorter of 18 months following cessation of employment and the period for which the named executive officer is
+eligible for and elects such coverage. 
+The
+definition of "change in control" in the CIC Plan is consistent with the definition in our stockholder-approved equity plans. "Change in control" is generally defined in the CIC Plan to mean any
+one of the following: (i) any person becomes the beneficial owner of 35% or more of our common stock or voting securities, with certain exceptions; (ii) incumbent directors (including
+those nominees subsequently nominated or elected by incumbent directors) cease to constitute a majority of the members of the Board; (iii) consummation of a reorganization, merger or
+consolidation or sale or other disposition of all or substantially all of the assets of the Company, unless (a) after the transaction, the beneficial owners of our common stock and voting
+securities immediately prior to the transaction retain more than 50% of such common stock and voting securities of the entity resulting from the transaction, (b) no person immediately after the
+merger beneficially owns 35% or more of the voting power of the entity resulting from the transaction (except to the extent that such ownership existed with respect to the Company prior to the
+transaction), and (c) at least a majority of the members of the board of directors of the entity resulting from the transaction shall have been members of the incumbent board at the time of the
+execution of the initial agreement, or of the action of the Board, providing for such transaction; or (iv) stockholder approval of a complete liquidation or dissolution of the Company. 
+"Cause"
+is defined in the CIC Plan to mean, with respect to any participant: (i) the participant's conviction, or guilty or no contest plea, to any felony; (ii) any act of fraud by the
+participant related to or connected with the participant's employment by the Company; (iii) the participant's material breach of his or her fiduciary duty to the Company; (iv) the
+participant's gross negligence or gross misconduct in the performance of duties reasonably assigned to the participant which causes material harm to the Company; (v) any willful violation by
+the participant of the Company's codes of conduct or other rules or policies of the Company; or (vi) any entry of any court order or other ruling that prevents the participant from performing
+his or her material duties and responsibilities. 
+"Good
+reason" is defined in the CIC Plan to mean the existence of any one or more of the following conditions without the written consent of the participant: (i) the Company's assignment to the
+participant of any duties inconsistent in any material negative respect with the participant's authority, duties or responsibilities immediately prior to the change in control or any other action by
+the Company that results in a material diminution in such authority, duties or responsibilities; (ii) a material reduction in the participant's base salary, as in effect immediately prior to
+the change in control; (iii) a material reduction in the participant's target bonus and/or target long-term incentive opportunity, as in effect immediately prior to the change in control;
+(iv) relocation of the participant's office more than 50 miles from the Company's principal office immediately prior to the change in control; or (v) a material breach by the Company of
+the CIC Plan. To resign for "good reason," a participant must provide certain notice to the Company, and the Company must fail to remedy the condition believed to constitute "good reason" within a
+specified time period. 
+Severance Agreements 
+In addition to participating in the CIC Plan, Messrs. Lasher and Crutchfield have severance agreements with us. The severance agreements
+provide that, if the Company terminates Mr. Lasher's or 
+34 
+Table of Contents 
+Mr. Crutchfield's
+employment, as applicable, without cause (i) at any time prior to December 26, 2014, the executive will be entitled to receive a severance payment in cash equal
+to two times the executive's annual base salary and (ii) at any time after December 26, 2014, but before December 26, 2015, the executive will be entitled to receive a severance
+payment in cash equal to the executive's annual base salary. The separation payments are conditioned upon the effectiveness of the executive's release of claims in favor of the Company and compliance
+with the noncompetition, nonsolicitation and confidentiality covenants in the severance agreement. "The definition of "cause" in the severance agreements is substantially similar to the definition
+provided in the CIC Plan. 
+McCarvel Separation Agreement 
+On December 27, 2013, Mr. McCarvel resigned from his position as our President, Chief Executive Officer and director effective upon the
+earlier to occur of (i) April 30, 2014 or (ii) the Board's appointment of his successor as Chief Executive Officer. In connection with his resignation, we and Mr. McCarvel
+entered into a separation agreement (the "Separation Agreement"). The Separation Agreement provides that we will pay Mr. McCarvel (i) a $1.1 million separation payment on the
+first regularly scheduled payroll date after the effectiveness of his resignation and (ii) a $1 million separation payment on the first anniversary of the effectiveness of his
+resignation. Mr. McCarvel will also be entitled to receive any amount earned pursuant to our 2013 annual incentive program. Mr. McCarvel earned a cash bonus of $535,000 under the 2013
+annual incentive program. 
+Mr. McCarvel
+agreed to continue in a consulting capacity with us at his regular salary through April 30, 2014 if his successor is appointed prior to such date. Subject to continued
+service, Mr. McCarvel will be entitled to continued vesting through April 30, 2014 of the unvested portion of certain of his restricted stock and restricted stock unit awards. 
+The
+separation payments are conditioned upon the effectiveness of Mr. McCarvel's release of claims in favor of the Company and his compliance with the noncompetition, nonsolicitation and
+confidentiality covenants contained in the Separation Agreement. The separation payments are subject to claw back and offsets upon certain violations of such covenants by Mr. McCarvel. 
+Hart Employment Agreement 
+Mr. Hart's employment agreement provides certain benefits in the event of certain terminations of employment. No other named executive officer
+currently has an employment agreement. Mr. Hart's employment agreement was modified by the CIC Plan to provide that the terms of the CIC Plan supersede and replace the terms of the employment
+agreement with respect to a change in control. Mr. Hart's employment agreement provides that if Mr. Hart is terminated by us involuntarily without "cause" (as defined below) or if he
+resigns for "good reason" (as defined below), he will receive: (i) a lump sum payment equal to one year of his base pay as of the termination date; (ii) a lump sum payment equal to 80%
+of his base pay in effect as of the termination date, pro-rated to equal the proportion of the year that he was employed by us; (iii) a lump sum payment equal to 80% of his base pay as of the
+termination date; and (iv) immediate vesting of any unvested stock options or unvested stock awards then held by him that would have been vested had he remained employed for 24 months
+after the termination date. The agreement also provides that any stock options granted to Mr. Hart during his employment will remain exercisable for ten years after the date of grant, including
+if Mr. Hart ceases to be employed by us for any reason other than termination for cause. 
+Under
+Mr. Hart's employment agreement, "cause" and "good reason" are defined as follows: 
+"Cause"
+is defined by the agreement to mean: (i) the executive's conviction, or guilty or no contest plea, to any felony; (ii) any act of fraud by the executive related to or connected
+with the executive's employment by the Company; (iii) the executive's material breach of his fiduciary duty to the Company; 
+35 
+Table of Contents 
+(iv) the
+executive's gross negligence or gross misconduct in the performance of duties reasonably assigned to the executive which causes material harm to the Company; (v) any willful and
+material violation by the executive of the Company's codes of conduct or other rules or policies of the Company; (vi) any entry of any court order or other ruling that prevents the executive
+from performing his material duties and responsibilities hereunder; or (vii) any willful and material breach of the agreement by the executive. 
+"Good
+reason" is defined by the agreement to mean any of the following conditions arising during the executive's term of employment without the consent of the executive: (i) a material
+diminution in the executive's responsibilities, authority, position, or duties; (ii) a reduction in the executive's base salary (except as provided for in the agreement); (iii) a
+reduction in the executive's incentive or equity compensation opportunity such that it is materially less favorable than those provided generally to other senior executive officers; (iv) the
+Company's material failure to honor its incentive compensation plans, as then in effect; (v) assignment of duties or responsibilities materially inconsistent with those described in the
+agreement; (vi) removal from the position of Executive Vice President of Administration and Corporate Development of the Company or its successor; (vii) any change in the executive's
+reporting responsibility being solely to the Chief Executive Officer; (viii) relocation of the executive's office or the Company 50 miles or more from the place of relocation agreed between the
+executive and Chief Executive Officer; or (ix) any other action or inaction that constitutes a material breach by the Company of the agreement. 
+Below
+is a summary of the potential payments that each of our named executive officers would have received upon the occurrence of the termination events specified below, assuming that each triggering
+event occurred on December 31, 2013. 
+Involuntary Termination without Cause or Resignation for Good Reason 
+Involuntary Termination without Cause or Resignation for Good Reason within Two Years Following a Change in Control 
+Name 
+Severance 
+($) 
+Acceleration 
+of Equity 
+Awards 
+($) (1) 
+Total 
+($) 
+Severance 
+($) 
+Health 
+Benefits 
+($) 
+Acceleration 
+of Equity 
+Awards 
+($) (1) 
+Total 
+($) 
+John P. McCarvel (2) 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Daniel P. Hart 
+1,296,750 
+745,406 
+2,042,156 
+1,596,000 
+162,200 
+1,685,338 
+3,443,538 
+Jeffrey J. Lasher 
+800,000 
+— 
+800,000 
+1,280,000 
+25,388 
+1,470,960 
+2,776,348 
+Scott E. Crutchfield 
+800,000 
+— 
+800,000 
+1,280,000 
+25,388 
+1,512,129 
+2,817,517 
+(1) Amounts
+based on the fair market value of our common stock of $15.92 per share, which was the closing price of our common stock on December 31, 2013
+as reported on the Nasdaq Global Select Market.
+(2) See
+"McCarvel Separation Agreement" above for a description of the actual payments payable to Mr. McCarvel in connection with his resignation,
+pursuant to the Separation Agreement. 
+REPORT OF THE AUDIT COMMITTEE 
+The
+Audit Committee has reviewed and discussed the audited financial statements for the fiscal year ended December 31, 2013 with our management and Deloitte & Touche LLP, our
+independent registered public accounting firm. Management is responsible for the preparation, presentation and integrity of the financial statements, accounting and financial reporting principles and
+internal control over financial reporting. Deloitte & Touche LLP is responsible for performing an independent audit of the financial statements in accordance with generally accepted
+auditing standards and for expressing opinions on the conformity of the financial statements with accounting principles generally accepted in the United States. 
+36 
+Table of Contents 
+The
+Audit Committee has discussed with Deloitte & Touche LLP the matters required to be discussed by Statement on Auditing Standards No. 61, as amended, Communication With Audit Committees , and the Public Company Accounting Oversight Board ("PCAOB") AU Section 380, Communications with Audit Committees , and has received the written disclosures and the letter from
+Deloitte & Touche LLP required by
+applicable requirements of the PCAOB regarding the independent auditor's communications with the Audit Committee concerning independence. The Audit Committee has also discussed with Deloitte &
+Touche LLP their independence. 
+Based
+on its reviews and discussions referred to above, the Audit Committee recommended to the Board that the audited financial statements be included in our Annual Report on Form 10-K for the
+year ended December 31, 2013 for filing with the SEC. 
+THE
+AUDIT COMMITTEE 
+Thomas J. Smach (Chairperson) 
+Ronald L. Frasch 
+Peter A. Jacobi 
+INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+The
+following table sets forth the aggregate fees for professional services provided during 2013 and 2012 by Deloitte & Touche LLP, our independent registered public accounting firm, and
+its affiliates. The Audit Committee is required to pre-approve all audit and non-audit services provided by Deloitte & Touche LLP. All of the services provided by, and fees paid to,
+Deloitte & Touche LLP during 2013 and 2012 were pre-approved by the Audit Committee. 
+2013 
+2012 
+Audit fees (1) 
+$ 
+1,920,306 
+$ 
+1,911,663 
+Audit-related fees (2) 
+$ 
+385,750 
+— 
+Tax fees (3) 
+$ 
+232,968 
+$ 
+349,314 
+All other fees 
+— 
+— 
+Total fees 
+$ 
+2,539,024 
+$ 
+2,260,977 
+(1) Audit
+fees relate to professional services rendered in connection with the audit of our annual financial statements and internal control over
+financial reporting, both of which are included in our Annual Report on Form 10-K and services attendant to, or required by, statute or regulation, such as: (i) consents and other audit
+services related to SEC and other regulatory filings; (ii) accounting consultation related to the audit; and (iii) statutory audit requirements in foreign countries.
+(2) Audit-related
+fees substantially relate to services rendered in connection with statutory audits.
+(3) Tax
+fees include professional services rendered in connection with tax compliance, tax advice, tax consulting and tax planning. 
+PROPOSAL 2—RATIFICATION OF THE APPOINTMENT OF INDEPENDENT REGISTERED 
+PUBLIC ACCOUNTING FIRM 
+The
+Audit Committee has appointed Deloitte & Touche LLP as the independent registered public accounting firm for the fiscal year ending December 31, 2014. Deloitte &
+Touche LLP has served as our independent public accounting firm since 2005. We are not required to submit this appointment to 
+37 
+Table of Contents 
+the
+stockholders for approval, but the Board believes it is desirable as a matter of policy. We expect that a representative of Deloitte & Touche LLP will attend the Annual Meeting and
+will have the opportunity to make any statements if he or she so desires and to respond to appropriate stockholder questions. 
+If
+the stockholders do not ratify this appointment, the Audit Committee will investigate the reasons for the rejection and consider other independent registered public accounting firms. Even if the
+appointment is ratified, the Audit Committee may, in its discretion, appoint a different independent registered public accounting firm. 
+THE BOARD RECOMMENDS A VOTE "FOR" THE RATIFICATION OF DELOITTE & TOUCHE LLP AS THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR FISCAL YEAR
+2014. 
+PROPOSAL 3—ADVISORY VOTE TO APPROVE THE COMPENSATION OF OUR 
+NAMED EXECUTIVE OFFICERS 
+Pursuant
+to Section 14A of the Securities Exchange Act of 1934, our stockholders have an opportunity to cast a non-binding advisory vote to approve the compensation of our named executive
+officers as disclosed in this proxy statement. This proposal, commonly known as a "Say on Pay" proposal, gives stockholders the opportunity to approve or reject our executive pay program. Accordingly,
+we ask our stockholders to vote "FOR" the following resolution at the Annual Meeting: 
+"RESOLVED,
+that the stockholders approve, on an advisory basis, the compensation of our named executive officers, as disclosed pursuant to Item 402 of Regulation S-K, including the
+Compensation
+Discussion and Analysis, the compensation tables and any other related disclosure in this proxy statement." 
+As
+discussed in the "Compensation Discussion and Analysis," the primary objective of our executive compensation program is to create long-term value for our stockholders by attracting and retaining
+talented executives, holding our executives accountable to stockholders, motivating our executives to achieve superior financial and business objectives and aligning the interests of our executives
+with those of our stockholders. We believe our executive compensation strikes the appropriate balance between utilizing responsible, measured pay practices and effectively incentivizing our named
+executive officers to dedicate themselves fully to value creation for our stockholders. Please see "Compensation Discussion and Analysis" section above for an explanation of our executive
+compensation. 
+This
+"Say on Pay" proposal allows our stockholders to express their view regarding the decisions of the Compensation Committee on the 2013 compensation of our named executive officers. Your advisory
+vote will serve as a tool to guide the Board and the Compensation Committee in continuing to improve the alignment of our executive compensation programs with the objective of creating long-term value
+for our stockholders. 
+Our
+current policy is to provide stockholders with an opportunity to approve the compensation of our named executive officers each year at the annual meeting of stockholders until the next required
+stockholder vote on the frequency of such votes. It is expected that the next such frequency vote will occur at the 2017 annual meeting of stockholders. 
+THE BOARD RECOMMENDS A VOTE "FOR" THE ADVISORY VOTE TO APPROVE THE COMPENSATION OF OUR NAMED EXECUTIVE OFFICERS. 
+38 
+Table of Contents 
+OTHER MATTERS 
+We
+do not intend to bring before the Annual Meeting any matters other than the proposals specifically described above, and we know of no matters other than those to come before the Annual Meeting. If
+any other matters properly come before the Annual Meeting, it is the intention of the persons named in the accompanying proxy to vote such proxy in accordance with the recommendation of our management
+on such matters, including any matters dealing with the conduct of the Annual Meeting. 
+STOCKHOLDER PROPOSALS AND NOMINATIONS FOR 2015 ANNUAL MEETING 
+Any proposal of a stockholder intended to be included in our proxy statement for the 2015 annual meeting of stockholders pursuant to SEC
+Rule 14a-8, must be received by us no later than December 30, 2014 unless the date of our 2015 annual meeting is more than 30 days before or after June 10, 2015, in which
+case the proposal must be received a reasonable time before we begin to print and mail our proxy materials. All proposals should be addressed to the Corporate Secretary, Crocs, Inc., 7477 East
+Dry Creek Parkway, Niwot, Colorado 80503. 
+In
+order for a stockholder to nominate a candidate for director for election or to bring other business before the 2015 annual meeting, we must receive timely notice of the nomination or business in
+writing by the close of business not later than March 12, 2015 and not earlier than February 10, 2015. However, in the event that the 2015 annual meeting is called for a date that is not
+within 30 days before or 60 days after June 10, 2015, notice by the stockholder to be timely must be delivered not earlier than the close of business on the 120th day prior
+to such annual meeting and not later than the close of business on the later of the 90th day prior to such annual meeting or the 10th day following the date on which public announcement
+of the date of the 2015 annual meeting is made. 
+39 
+THIS PROXY CARD
+IS VALID ONLY WHEN SIGNED AND DATED. KEEP THIS PORTION FOR YOUR RECORDS
+DETACH AND RETURN THIS PORTION ONLY TO VOTE, MARK BLOCKS BELOW IN BLUE OR
+BLACK INK AS FOLLOWS: Signature (Joint Owners) Signature [PLEASE SIGN WITHIN
+BOX] Date Date To withhold authority to vote for any individual nominee(s),
+mark “For All Except” and write the number(s) of the nominee(s) on the line
+below. 0 0 0 0 0 0 0 0 0 0000211500_1 R1.0.0.51160 For Withhold For All All
+All Except The Board of Directors recommends you vote FOR the following: 1.
+Election of Directors Nominees 01 Prakash A. Melwani 02 Thomas J. Smach
+CROCS, INC. ATTN: CORPORATE SECRETARY 7477 EAST DRY CREEK PARKWAY NIWOT, CO
+80503 VOTE BY INTERNET - www.proxyvote.com Use the Internet to transmit your
+voting instructions and for electronic delivery of information up until 11:59
+P.M. Eastern Time the day before the cut-off date or meeting date. Have your
+proxy card in hand when you access the web site and follow the instructions
+to obtain your records and to create an electronic voting instruction form.
+ELECTRONIC DELIVERY OF FUTURE PROXY MATERIALS If you would like to reduce the
+costs incurred by our company in mailing proxy materials, you can consent to
+receiving all future proxy statements, proxy cards and annual reports
+electronically via e-mail or the Internet. To sign up for electronic
+delivery, please follow the instructions above to vote using the Internet
+and, when prompted, indicate that you agree to receive or access proxy
+materials electronically in future years. VOTE BY PHONE - 1-800-690-6903 Use
+any touch-tone telephone to transmit your voting instructions up until 11:59
+P.M. Eastern Time the day before the cut-off date or meeting date. Have your
+proxy card in hand when you call and then follow the instructions. VOTE BY
+MAIL Mark, sign and date your proxy card and return it in the postage-paid
+envelope we have provided or return it to Vote Processing, c/o Broadridge, 51
+Mercedes Way, Edgewood, NY 11717. The Board of Directors recommends you vote
+FOR proposals 2 and 3. For Against Abstain 2 Ratification of the appointment
+of Deloitte & Touche LLP as our independent registered public accounting
+firm for fiscal year 2014. 3 An advisory vote to approve the compensation of
+our named executive officers. NOTE: Such other business as may properly come
+before the meeting or any adjournment thereof. Please sign exactly as your
+name(s) appear(s) hereon. When signing as attorney, executor, administrator,
+or other fiduciary, please give full title as such. Joint owners should each
+sign personally. All holders must sign. If a corporation or partnership,
+please sign in full corporate or partnership name, by authorized officer. 
+0000211500_2
+R1.0.0.51160 Important Notice Regarding the Availability of Proxy Materials
+for the Annual Meeting: The Notice & Proxy Statement, 2013 Annual Report
+is/are available at www.proxyvote.com . CROCS, INC. Annual Meeting of
+Stockholders June 10, 2014 11:00 AM This proxy is solicited by the Board of
+Directors The undersigned hereby appoints Jeffrey J. Lasher and Daniel P.
+Hart and each of them, with power of substitution, as proxies of the
+undersigned, to attend the Annual Meeting of Stockholders of Crocs, Inc. (the
+"Company"), to be held at the St. Julien Hotel, 900 Walnut Street,
+Boulder, Colorado, on June 10, 2014 at 11 a.m. Mountain Time, and all
+adjournments thereof, and to vote, as indicated on the reverse side, the
+shares of Common Stock of the Company which the undersigned is entitled to
+vote with all the powers the undersigned would possess if present at the
+meeting. THIS PROXY, WHEN PROPERLY EXECUTED, WILL BE VOTED AS DIRECTED HEREIN
+BY THE UNDERSIGNED STOCKHOLDER(S). IF NO SPECIFIC DIRECTIONS ARE GIVEN, THIS
+PROXY WILL VOTED FOR ALL NOMINEES LISTED AND "FOR" PROPOSALS 2 AND
+3. PLEASE MARK, SIGN, DATE AND RETURN THIS PROXY CARD PROMPTLY USING THE
+ENCLOSED REPLY ENVELOPE. Continued and to be signed on reverse side
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001047469-14-004292/proxy_rpt.txt b/raw/proxies/0001334036/0001047469-14-004292/proxy_rpt.txt
new file mode 100644
index 0000000000000000000000000000000000000000..28623282b44b7fdc91f00c24de8919e44f51c28c
--- /dev/null
+++ b/raw/proxies/0001334036/0001047469-14-004292/proxy_rpt.txt
@@ -0,0 +1,67 @@
+CERTAIN RELATIONSHIPS AND RELATED PERSON TRANSACTIONS 
+Related Person Transactions 
+Investment Agreement with Blackstone 
+On January 27, 2014, we issued to Blackstone and certain of its permitted transferees (together with Blackstone, the "Blackstone Purchasers"),
+200,000 shares of our convertible preferred stock for an aggregate purchase price of $198 million, or $990 per share, pursuant to the Investment Agreement. In connection with the issuance of
+the convertible preferred stock (the "Closing") and pursuant to the Investment Agreement, we paid Blackstone a closing fee of $2 million and reimbursed Blackstone's transaction fees and
+expenses of approximately $4 million. As of March 31, 2014, the Blackstone Purchasers collectively owned all of our outstanding shares of convertible preferred stock and, on an
+as-converted basis, approximately 14% of our outstanding common stock. 
+As
+discussed above under "Proposal 1—Election of Directors," the Investment Agreement grants Blackstone certain rights to designate directors to serve on our Board. For so long as the
+Blackstone Purchasers (i) beneficially own at least 95% of our convertible preferred stock or the as-converted common stock purchased pursuant to the Investment Agreement or
+(ii) maintain beneficial ownership of at least 12.5% of the our outstanding common stock (the "Two-Director Threshold"), Blackstone will have the right to designate for nomination two directors
+to our Board. For so long as the Blackstone Purchasers beneficially own shares of our convertible preferred stock or the as-converted common stock purchased pursuant to the Investment Agreement that
+represent less than the Two-Director Threshold but more than 25% of the number of shares of the as-converted common stock purchased pursuant to the Investment Agreement, Blackstone will have the right
+to designate for nomination one director to our Board. The directors designated by Blackstone are entitled to serve on Board committees, subject to applicable law and stock exchange rules. Blackstone
+designated Messrs. Melwani and Ribatt for nomination to our Board. 
+Pursuant
+to the Investment Agreement, Blackstone is subject to certain standstill restrictions which restrict Blackstone from acquiring more than 25% of our outstanding common stock until the date on
+which Blackstone is no longer entitled to designate any directors to our Board. In addition, subject to certain customary exceptions, Blackstone is restricted from transferring any shares of the
+convertible preferred stock until the second anniversary of the Closing and, for so long as any convertible preferred stock is outstanding, may not transfer any shares of convertible preferred stock
+to certain of our competitors (as defined in the Investment Agreement) or holders of 25% or more of our common stock. Blackstone also has certain preemptive rights and information rights under the
+Investment Agreement, which are subject to certain conditions. 
+Certificate of Designations 
+Pursuant to the Certificate of Designations of Series A Convertible Preferred Stock filed with the Delaware Secretary of State on
+January 24, 2014, which establishes the designations, preferences, and other rights of the convertible preferred stock: 
+• The convertible preferred stock ranks senior to our common stock with respect to dividend rights and rights on
+liquidation, winding-up and dissolution; 
+• The Blackstone Purchasers are entitled to cumulative dividends payable quarterly in cash at a rate of 6% per annum of the
+stated value of $1,000 per share; 
+16 
+Table of Contents 
+• If we fail to make timely dividend payments to the holders of our convertible preferred stock, the dividend rate will
+increase to 8% per annum until such time as all accrued but unpaid dividends have been paid in full; 
+• The Blackstone Purchasers are entitled to receive any dividends declared or paid on our common stock and are entitled to
+vote together with the holders of our common stock as a single class, in each case, on an as-converted basis; 
+• The Blackstone Purchasers have certain limited special approval rights, including with respect to the issuance by us of pari passu 
+or senior equity securities; 
+• The Blackstone Purchasers may, at any time, require us to convert their shares of convertible preferred stock into shares
+of common stock at an implied conversion price of $14.50 per share, subject to certain adjustments; 
+• At our election, all or a portion of the convertible preferred stock will be convertible into the relevant number of
+shares of common stock on or after the third anniversary of the Closing, if the closing price of the common stock equals or exceeds $29.00 for 20 consecutive trading days; 
+• The conversion rate is subject to customary anti-dilution and other adjustments subject to certain share caps and other
+restrictions; 
+• At any time after the eighth anniversary of the Closing, we will have the right to redeem, and the Blackstone Purchasers
+will have the right to require us to repurchase, all or any portion of the convertible preferred stock at 100% of the stated value, plus all accrued but unpaid dividends; and 
+• Upon certain change of control events involving us, the Blackstone Purchasers can require us to repurchase their shares of
+convertible preferred stock at 101% of the stated value plus all accrued but unpaid dividends. 
+Registration Rights Agreement 
+In connection with the Closing, we and the Blackstone Purchasers entered into a Registration Rights Agreement (the "Registration Rights Agreement"),
+pursuant to which we have agreed to provide to the Blackstone Purchasers certain customary demand and piggyback registration rights in respect of the shares of convertible preferred stock and any
+shares of common stock issued upon conversion of the convertible preferred stock. The Registration Rights Agreement contains customary terms and conditions, including certain customary indemnification
+obligations. 
+Policy on Transactions with Related Persons 
+Our Code of Business Conduct and Ethics requires that any transaction involving us in which one of our directors, nominees for director, executive
+officers, or greater than five percent stockholders, or one of the aforementioned's immediate family members (each, a "related person"), have a material interest be approved or ratified by the Audit
+Committee if the amount involved, when aggregated with the amount of all other transactions between the related person and us, exceeds $100,000 in a fiscal year. The full Board reviews ordinary course
+of business transactions in which directors have an interest as part of the Board's annual director independence review, and our Code of Business Conduct and Ethics permits the full Board to waive any
+conflicts of interest between us and any director or officer. In determining whether to approve or ratify any such transaction, the Audit Committee must consider, in addition to other factors it deems
+appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. The full Board approved each of the transactions disclosed above. 
+17 
+Table of Contents 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify certain directors and executive officers in addition to the indemnification provided for in our
+certificate of incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain expenses (including attorneys' fees),
+judgments, fines and settlement amounts incurred by any such person in any action or proceeding, including any action by us or in our right, arising out of such person's services as a director or
+executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person provided services at our request. We believe that these provisions and agreements are necessary
+to attract and retain qualified persons as directors and executive officers.
\ No newline at end of file
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new file mode 100644
index 0000000000000000000000000000000000000000..d8cd5818f2a9c5c2f16425d869d6d7109b02cda2
--- /dev/null
+++ b/raw/proxies/0001334036/0001193125-12-157146/proxy.txt
@@ -0,0 +1,2070 @@
+DEF 14A
+1
+d285852ddef14a.htm
+DEFINITIVE PROXY STATEMENT
+Definitive Proxy Statement 
+Table of Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549
+SCHEDULE 14A 
+Proxy Statement Pursuant to Section 14(a) of 
+the Securities Exchange Act of
+1934 (Amendment No. ) 
+Filed by the Registrant x 
+Filed by a Party other than the Registrant ¨ 
+Check the appropriate box: 
+¨ 
+Preliminary Proxy Statement 
+¨ 
+Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2)) 
+x 
+Definitive Proxy Statement 
+¨ 
+Definitive Additional Materials 
+¨ 
+Soliciting Material Pursuant to §240.14a-12 
+CROCS, INC. 
+(Name of Registrant as Specified In Its Charter)
+(Name of Person(s) Filing Proxy Statement, if other than the Registrant) 
+Payment of Filing Fee (Check the appropriate box): 
+x 
+No fee required. 
+¨ 
+Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11. 
+(1) 
+Title of each class of securities to which transaction applies: 
+(2) 
+Aggregate number of securities to which transaction applies: 
+(3) 
+Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and
+state how it was determined): 
+(4) 
+Proposed maximum aggregate value of transaction: 
+(5) 
+Total fee paid: 
+¨ 
+Fee paid previously with preliminary materials. 
+¨ 
+Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was
+paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing. 
+(1) 
+Amount Previously Paid: 
+(2) 
+Form, Schedule or Registration Statement No.: 
+(3) 
+Filing Party: 
+(4) 
+Date Filed: 
+Table of Contents 
+Crocs, Inc. 
+7477 East Dry Creek Parkway 
+Niwot, Colorado 80503 
+NOTICE OF THE
+2012 ANNUAL MEETING OF STOCKHOLDERS 
+TO BE HELD JUNE 4, 2012 
+To the Stockholders of Crocs, Inc.: 
+We will hold the 2012 Annual Meeting of Stockholders of
+Crocs, Inc. at the St. Julien Hotel, 900 Walnut Street, Boulder, Colorado, on June 4, 2012 at 2 p.m. Mountain Time. 
+The
+meeting’s purpose is to: 
+1. 
+elect two Class I directors; 
+2. 
+ratify the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for fiscal year 2012; 
+3. 
+approve the amendment and restatement of our 2008 Cash Incentive Plan; 
+4. 
+hold an advisory vote to approve the compensation of our named executive officers; and 
+5. 
+consider any other matters that properly come before the meeting or any postponement or adjournment thereof. 
+Only stockholders of record of our common stock at the close of business on April 9, 2012 are entitled to receive notice of and to vote at the
+meeting. Each share of common stock is entitled to one vote. 
+A list of the stockholders entitled to vote at the meeting will be available
+for examination at the meeting by any stockholder for any purpose relevant to the meeting. The list will also be available on the same basis for ten days prior to the meeting at our principal executive office, 7477 East Dry Creek Parkway, Niwot,
+Colorado 80503. 
+All stockholders are cordially invited to attend the meeting in person. Whether or not you plan to attend the meeting in
+person, please vote your shares as instructed in the Notice of Internet Availability of Proxy Materials, over the internet, or by telephone after your receipt of hard copies of the proxy materials, as promptly as possible. You may also request a
+paper proxy card, which will include a reply envelope, to submit your vote by mail, as described in the Notice of Internet Availability of Proxy Materials. Stockholders who are present at the Annual Meeting may withdraw their proxy and vote in
+person if they so desire. 
+BY ORDER OF THE BOARD OF DIRECTORS 
+John P. McCarvel 
+President and Chief Executive Officer 
+Niwot, Colorado 
+April 10, 2012 
+Table of Contents 
+TABLE OF CONTENTS 
+Page 
+Proxy Statement 
+1 
+General Information Regarding Annual Meeting 
+1 
+Proposal 1—Election of Directors 
+4 
+Corporate Governance 
+7 
+Board of Directors and Committees of the Board 
+9 
+Executive Officers 
+12 
+Beneficial Ownership of Our Common Stock 
+13 
+Certain Relationships and Related Person Transactions 
+15 
+Director Compensation 
+16 
+Executive Compensation 
+18 
+Compensation Committee Report 
+26 
+Report of the Audit Committee 
+33 
+Independent Registered Public Accounting Firm 
+34 
+Proposal 2—Ratification of the Appointment of Independent Registered Public Accounting
+Firm 
+35 
+Proposal 3—Approval of the Amendment and Restatement of the 2008 Cash Incentive
+Plan 
+36 
+Proposal 4—Advisory Vote to Approve the Compensation of our Named Executive
+Officers 
+40 
+Other Matters 
+41 
+Table of Contents 
+Crocs, Inc. 
+7477 East Dry Creek Parkway 
+Niwot, Colorado 80503 
+2012 ANNUAL MEETING OF STOCKHOLDERS 
+PROXY STATEMENT 
+This proxy statement will first be made available to stockholders on or about April 10, 2012. It is furnished to stockholders of Crocs, Inc., a
+Delaware corporation (“we,” “us,” or “our”), in connection with the solicitation of proxies by our Board of Directors. The proxies being solicited will be voted at the 2012 Annual Meeting of Stockholders (the
+“Annual Meeting”), to be held on June 4, 2012 at the St. Julien Hotel, 900 Walnut Street, Boulder, Colorado at 2 p.m. Mountain Time, or at any postponement or adjournment thereof, for the purpose of voting on the proposals as set
+forth herein as well as other business matters which may properly come before the meeting. 
+Under the rules of the Securities and Exchange
+Commission (the “SEC”), we are furnishing proxy materials to our stockholders on the Internet, rather than mailing printed copies. If you received a Notice of Internet Availability of Proxy Materials by mail, you will not receive a printed
+copy of the proxy materials unless you request one as instructed in that notice. Instead, the Notice of Internet Availability of Proxy Materials will instruct you as to how you may access and review the proxy materials on the Internet. This proxy
+statement and our 2011 annual report to stockholders are available at www.edocumentview.com/crox. 
+GENERAL INFORMATION REGARDING ANNUAL MEETING 
+Record Date. Stockholders of record at the close of business on April 9, 2012 are entitled to notice of and to vote at the Annual Meeting. On the record date, there were
+89,898,760 shares of our common stock outstanding. Each such share is entitled to one vote on each matter submitted to a vote at the Annual Meeting. 
+Quorum Requirements. A quorum is required to conduct business at the Annual Meeting. The holders of a majority of the outstanding shares entitled to vote generally in the election of
+directors must be present in person or by proxy at the Annual Meeting in order for a quorum to exist. Abstentions and broker non-votes count as present for purposes of determining a quorum. A broker non-vote occurs when a broker returns a proxy card
+but does not vote on one or more matters because the broker does not have the authority to do so without instructions from the beneficial owner. Shares represented by proxies that are marked withhold with respect to the election of our Class I
+directors will be counted as present in determining whether there is a quorum. 
+1 
+Table of Contents 
+Vote Requirements. If a quorum is present at the Annual Meeting, the following vote is
+required for approval of each matter to be voted on. 
+Election of Directors. The two director nominees
+receiving the highest number of “for” votes cast in person or by proxy at the Annual Meeting will be elected as directors. Proxies marked withhold and broker non-votes will have no effect on the outcome of this proposal. Cumulative voting
+is not permitted. 
+Ratification of Appointment of Deloitte & Touche LLP. The affirmative vote
+of the holders of a majority of the shares of our common stock present in person or by proxy and entitled to vote on the proposal is required for the ratification of the appointment of Deloitte & Touche LLP as our independent
+registered public accounting firm for fiscal year 2012. Abstentions will have the effect of voting against this proposal. Broker non-votes will have no impact on this proposal. 
+Approval of the Amendment and Restatement of the 2008 Cash Incentive Plan. The affirmative vote of the holders of a
+majority of the shares of our common stock present in person or by proxy and entitled to vote on the proposal is required for the approval of the amended and restated 2008 Cash Incentive Plan. Abstentions will have the effect of voting against this
+proposal. Broker non-votes will have no effect on the outcome of this proposal. 
+Advisory Vote to Approve Named Executive
+Officer Compensation. The affirmative vote of the holders of a majority of the shares of our common stock present in person or by proxy and entitled to vote on the proposal is required to approve the advisory resolution to approve the
+compensation of our named executive officers. Abstentions will have the effect of voting against this proposal. Broker non-votes will have no effect on the outcome of this proposal. 
+Approval of all Other Proposals: With respect to any other matters properly brought before the Annual Meeting, the
+affirmative vote of the holders of a majority of the shares of our common stock present in person or by proxy and entitled to vote on the proposals will be the act of the stockholders. Abstentions will have the effect of voting against these
+proposals. Broker non-votes will have no effect on these proposals. 
+Board Recommendations. Our Board of Directors’
+recommendation is set forth together with the description of each proposal. In summary, our Board of Directors recommends a vote: 
+• 
+FOR election of each of the Class I director nominees (see Proposal 1); 
+• 
+FOR the ratification of the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for
+our fiscal year ending December 31, 2012 (see Proposal 2); 
+• 
+FOR the approval of the amendment and restatement of the 2008 Cash Incentive Plan (see Proposal 3); and 
+• 
+FOR the advisory vote to approve the compensation of our named executive officers as disclosed in this proxy statement (see Proposal 4).
+Your Proxy. Whether or not you are able to personally attend the Annual Meeting, you are encouraged to
+vote your shares as instructed in the Notice of Internet Availability of Proxy Materials. Shares represented by properly executed methods, and not revoked prior to the Annual Meeting, will be voted at the Annual Meeting as directed in the proxy.
+If no directions are specified, such proxies will be voted FOR each of the proposals described in this proxy statement and in the best judgment of the proxy holders as to other matters that may properly come before the Annual Meeting. 
+2 
+Table of Contents 
+If your shares are held in the name of a bank or brokerage firm, your bank or broker will send you a
+separate package describing the procedures and options for voting your shares. You should follow the instructions provided by your bank or brokerage firm. On routine matters, such as the ratification of the appointment of our independent registered
+public accounting firm, your broker will vote your shares for you at his or her discretion if you do not instruct your broker how to vote. For non-routine matters, which include all other matters to be voted upon at the Annual Meeting, your broker
+may not vote your shares without specific voting instructions from you. 
+Revocation. Any stockholder giving a proxy has the
+power to revoke the proxy, or change the proxy, at any time before the proxy is voted at the Annual Meeting by (i) re-voting online at www.proxyvote.com, (ii) sending another properly executed proxy bearing a later date or a written notice
+of revocation of the proxy to Corporate Secretary, Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503 or (iii) voting in person at the Annual Meeting. 
+Cost of Proxy Solicitation. Our Board of Directors is soliciting the proxies. We will bear the entire cost of this proxy solicitation. We have retained the services of Georgeson, Inc., a
+professional proxy solicitation firm, to aid in the solicitation of proxies. Georgeson, Inc. may solicit proxies by personal interview, mail, telephone, facsimile, email or otherwise. We will pay Georgeson, Inc. its customary fee, estimated to be
+approximately $20,000, plus reasonable out-of-pocket expenses incurred in the process of soliciting proxies. We may also reimburse brokers, custodians, nominees and other fiduciaries for normal handling charges incurred for forwarding proxy
+materials to beneficial owners. Solicitation of proxies may be made personally or by mail or telephone by our directors, officers and other employees, who will receive no additional compensation for such services. 
+3 
+Table of Contents 
+PROPOSAL 1—ELECTION OF DIRECTORS 
+Our Board of Directors (the “Board”) currently consists of seven members divided into three classes, with each director elected to a three-year
+term. Class I consists of Ronald L. Frasch and W. Stephen Cannon, whose terms will expire at the Annual Meeting. Class II consists of Raymond D. Croghan, Peter A. Jacobi and Doreen A. Wright, whose terms will expire at the annual meeting to be
+held in 2013. Class III consists of Thomas J. Smach and John P. McCarvel, whose terms will expire at the annual meeting to be held in 2014. Under our amended and restated bylaws, each of our directors holds office until his or her successor has been
+elected and qualified or until such director’s earlier resignation or removal. 
+At each annual meeting of stockholders, the successors to
+directors whose terms expire at such meeting will be elected, or such directors will be re-elected, and will serve from the time of election and qualification until the third annual meeting following their election or until their successors are duly
+elected and qualified. The current authorized number of directors is eight. The authorized number of directors may be changed by resolution of the Board. Any additional directorships resulting from an increase in the number of directors will be
+distributed among the three classes so that, as nearly as possible, each class will consist of one-third of the directors. Vacancies on the Board can be filled by resolution of the Board. 
+Upon the recommendation of the Nominating and Governance Committee, the Board has nominated Messrs. Frasch and Cannon for re-election as Class I directors to serve for a three-year term expiring
+at the 2015 annual meeting of stockholders. 
+A stockholder cannot vote for more than two nominees. Each of the director nominees has consented
+to serve for a three-year term. We do not contemplate that any of the nominees will be unable to stand for election, but should any nominee become unable to serve or will not serve for any reason, all proxies (except proxies marked to the contrary)
+will be voted for the election of a substitute nominee as the Board may recommend. 
+Class I Director Nominees 
+Ronald L. Frasch (Class I) , age 63, has served as a member of the Board since October 2006. Since February 2007, Mr. Frasch has
+served as President and Chief Merchandising Officer of Saks Fifth Avenue, a division of Saks, Incorporated, a NYSE-listed luxury fashion retailer. From November 2004 until January 2007, he held the post of Vice Chairperson and Chief Merchant of Saks
+Fifth Avenue. From January 2004 to November 2004, he was employed by Saks in a non-executive capacity. From April 2000 to January 2004, Mr. Frasch served as Chairperson and Chief Executive Officer of Bergdorf Goodman (a subsidiary of Neiman
+Marcus Group, Inc.) and served as President of GFT North America (a subsidiary of Gruppo GFT, based in Turin, Italy, a global producer, marketer and distributor of fine men’s and women’s clothing, sportswear and furnishings) from 1996
+to 2000. Mr. Frasch also served as President and Chief Executive Officer of Escada USA from 1994 to 1996. Mr. Frasch has extensive executive expertise in the fashion retail industry, most notably demonstrated by his current position at
+Saks Fifth Avenue. Mr. Frasch’s experience and insight into this industry is invaluable to the Board and management in understanding the consumer retail and fashion industry, including current buying trends by our wholesale customers.
+W. Stephen Cannon ( Class I ), age 60, has served as a member of the Board since February 2009. Since 2005, he has
+served as the Chairperson of Constantine Cannon LLP, a law firm, and the Managing Partner of Constantine Cannon’s Washington D.C. office. From 1994 to 2005, Mr. Cannon was the Senior Vice President, General Counsel and Secretary of Circuit
+City Stores, Inc., a retailer of consumer electronics, which, at the time, was publicly traded on the New York Stock Exchange. Prior to joining Circuit City Stores, Inc., Mr. Cannon served as a partner at the law firm of Wunder, Diefenderfer,
+Ryan, Cannon and Thelen and spent ten years in government service, including serving as Chief Antitrust Counsel to the United States Senate Judiciary Committee. Mr. Cannon has demonstrated significant legal and business expertise through his
+role as general 
+4 
+Table of Contents 
+counsel of Circuit City, a public company with significant retail operations. This experience assists the Board with its risk oversight and retail expansion plans. Mr. Cannon’s legal
+expertise also allows him to effectively chair the Nominating and Governance Committee and understand corporate governance and SEC developments. 
+THE BOARD RECOMMENDS A VOTE “FOR” EACH OF THE ABOVE-NAMED NOMINEES FOR DIRECTOR. 
+Information About Continuing Directors 
+Raymond D. Croghan ( Class II ), age 62, has served as a member of the Board since August 2004. Since 1999, Mr. Croghan has
+been retired. From 1991 to 1999, Mr. Croghan managed Croghan & Associates, Inc., a healthcare information technology consulting firm, which merged with Margolis Health Enterprise to form The TriZetto Group. Mr. Croghan
+currently serves on the boards of directors of several privately-held companies. Mr. Croghan has successfully operated and grown private companies and has served on the boards of several companies in a variety of industries. His experience
+successfully operating companies in different industries provides us with a unique perspective as does his board experience. In addition, Mr. Croghan is our longest serving director and has extensive knowledge of our company and its operations.
+Peter A. Jacobi ( Class II ), age 68, has served as a member of the Board since October 2008. Mr. Jacobi was
+employed by Levi Strauss & Company (“Levi Strauss”), a jeans and casual wear manufacturer, from 1970 until his retirement in 1999. During his 29 years of tenure at Levi Strauss, Mr. Jacobi held various senior levels
+positions, including President of the Men’s Jeans Division, President of Global Sourcing, President of Levi Strauss International, and from 1996 until his retirement, President and Chief Operating Officer. Mr. Jacobi has extensive
+executive experience in the apparel industry gained through his tenure at Levi Strauss. The apparel industry is similar and complementary to the footwear industry and Mr. Jacobi has provided us significant insights from this industry. In
+addition, Levi Strauss is an established international brand. Mr. Jacobi’s experience with a global brand has helped us as we continue to build our brand internationally. 
+Doreen A. Wright ( Class II ), age 55, has served as a member of the Board since June 2011 prior to which
+she served as Senior Vice President and Chief Information Officer of Campbell Soup Company from 2001 to 2008. Ms. Wright also served as Interim Chief of Human Resources for Campbell Soup Company in 2002. From 1999 to 2001, Ms. Wright
+served as Executive Vice President and Chief Information Officer for Nabisco Inc. Prior to that, from 1995 to 1998 Ms. Wright held the position of Senior Vice President, Operations & Systems, Prudential Investments, for Prudential
+Insurance Company of America, and held various positions with American Express Company, Bankers Trust Corporation and Merrill Lynch & Co. Since 2009, Ms. Wright has served on the Board of Directors of Dean Foods Company, a leading food
+and beverage company. She also serves on the Board of New Hope Arts, Inc., a regional nonprofit arts center. In addition, Ms. Wright served on the Board of Directors of Citadel Broadcasting Corporation from 2010 to 2011, where she chaired the
+Compensation Committee; The Oriental Trading Company from 2008 to 2011, where she served on the Audit and Compensation Committees; Yankee Candle Company from 2003 to 2007, where she served on the Compensation and Audit Committees; and Conseco, Inc.
+from 2007 to 2010, where she served on the Audit and Enterprise Risk Committee. Ms. Wright brings more than 30 years of leadership experience in the financial services and consumer products industries, with emphasis in the area of information
+technology, operations, and human resources. Ms. Wright also has extensive experience as a public company director, including service on audit, compensation and corporate governance committees. 
+Thomas J. Smach ( Class III ), age 51, has served as the Chairperson of the Board since June 2011, prior to which he was a member
+of the Board since April 2005. Mr. Smach is currently a co-founding partner of Riverwood Capital Management, a private equity firm. From January 2005 to June 2008, Mr. Smach served as the Chief Financial Officer of Flextronics
+International (“Flextronics”) a NASDAQ-listed electronics manufacturing services (EMS) provider. From April 2000 to December 2004, Mr. Smach served as Senior Vice President—Finance of Flextronics. From 1997 to April 2000, he
+served as the Senior Vice President, Chief Financial Officer and Treasurer of The Dii Group, Inc., an EMS provider and publicly-traded company that 
+5 
+Table of Contents 
+merged with Flextronics in early 2000 (“The Dii Group”). Mr. Smach is a certified public accountant and also serves on the Board of Directors of ADVA AG Optical Networking, a
+publicly-traded company in Germany. Mr. Smach has extensive accounting and financial management experience having served as the chief financial officer of global public companies. In addition, Mr. Smach has significant experience with
+international manufacturing and business from his leadership positions at Flextronics. This experience is useful as we continue to expand our international operations. Mr. Smach is also well versed in SEC compliance and risk oversight, which
+makes him particularly well suited to serve as the chairperson of the Audit Committee and as the Board’s Chairperson. 
+John P.
+McCarvel (Class III) , age 55, has served as our President and Chief Executive Officer and as a director since March 1, 2010. Previously, Mr. McCarvel served as our Chief Operating Officer and Executive Vice President from
+February 2007 to March 2010, as our Senior Vice President—Global Operations from October 2005 to February 2007 and as our Vice President—Asian & Australian Operations from January 2005 to September 2005, after providing consulting
+services to us during 2004. From October 2001 to January 2005, Mr. McCarvel served as Vice President for the Design, Test and Semiconductor division of Flextronics, where he was responsible for building Flextronics’ engineering
+infrastructure in Asia and growing Flextronics’ business in the region. From 1999 to October 2001, he served as President of U.S. Operations and Senior Vice President of Worldwide Sales and Marketing for Singapore Technology Assembly Test
+Services Ltd., a semiconductor services company. He previously worked in executive level positions with Micron Custom Manufacturing Services, Inc., a manufacturer of electronic products for computing and digital applications, and The Dii
+Group. Mr. McCarvel has served us as an executive since 2005. He has been our chief operating officer and has extensive knowledge of our day-to-day operations along with a strategic vision as our chief executive officer.
+Mr. McCarvel’s leadership, extensive knowledge of our business and previous manufacturing expertise provide significant value and insights to the Board. 
+6 
+Table of Contents 
+CORPORATE GOVERNANCE 
+Crocs, Inc. is committed to maintaining sound corporate governance practices. The Board has formalized several policies, procedures and standards of
+corporate governance, including our Corporate Governance Guidelines, some of which are described below. We continue to monitor best practices and legal and regulatory developments with a view to further revising our governance policies and
+procedures, as appropriate. 
+Corporate Governance Guidelines. Since 2005, the Board has had in place a set of governance
+guidelines, the Crocs, Inc. Corporate Governance Guidelines, which are designed to assure the continued vitality of the Board and excellence in the execution of its duties. Our Corporate Governance Guidelines establish the practices and procedures
+of the Board with respect to board composition and member selection, board independence, board meetings and involvement of senior management, management succession planning, board committees and the evaluation of senior management and the Board. The
+Board periodically reviews our Corporate Governance Guidelines and updates them as necessary to reflect improved corporate governance practices and changes in regulatory requirements. 
+Director Independence. NASDAQ listing standards require that the Board consist of a majority of independent directors. The Board has determined that all of the current non-management
+members of the Board (Messrs. Cannon, Croghan, Frasch, Jacobi, and Smach and Ms. Wright) are independent directors as defined by NASDAQ listing standards. The Board makes a determination regarding the independence of each director annually
+based on relevant facts and circumstances. Applying the standards and independence criteria defined by the NASDAQ listing standards, the Board has made a subjective determination as to each independent director that no relationships exist which, in
+the opinion of the Board, would interfere with the exercise of his or her independent judgment in carrying out the responsibilities of a director. The independent directors of the Board regularly hold executive sessions without members of management
+present. 
+Communicating with Directors. Stockholders who wish to communicate with the Board or with specified individual
+directors may do so by mailing such written communication to: Corporate Secretary, Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503. The Corporate Secretary will review all correspondence and will forward to the Board or an
+individual director a summary of the correspondence received and copies of correspondence that the Corporate Secretary determines requires the attention of the Board or such individual director. The Board and any individual director may at any time
+request copies and review all correspondence received by the Corporate Secretary that is intended for the Board or such individual director. 
+Board Leadership. The Board does not have a policy regarding separation of the roles of Chief Executive Officer and Chairperson of the Board. The
+Board believes it is in our best interests to make that determination based on current circumstances. The Board has determined that an independent director serving as Chairperson is in the best interests of our stockholders at this time. This
+structure ensures a greater role of independent directors in the active oversight of our business, including risk management oversight, and in setting agendas and establishing Board priorities and procedures. This structure also allows the Chief
+Executive Officer to focus to a greater extent on the management of our day-to-day operations. 
+Risk Oversight. The Board oversees our
+risk management activities. The Board implements its risk oversight function both as a whole and through delegation to its committees. These committees meet regularly and report back to the full Board. The Audit Committee has primary oversight
+responsibility with respect to financial risks as well as oversight responsibility for our overall risk assessment and risk management policies and systems. The Audit Committee oversees our procedures for the receipt, retention and treatment of
+complaints relating to accounting and auditing matters and oversees our management of legal and regulatory compliance systems. The Compensation Committee oversees risks relating to our compensation plans and programs. The Compensation Committee has
+reviewed and considered our compensation policies and programs in light of the Board’s risk assessment and management responsibilities and will do so in the future on an annual basis. The Compensation Committee believes that we have no
+compensation policies and programs that give rise to risks reasonably likely to have a material adverse effect on us. 
+7 
+Table of Contents 
+The Chief Legal and Administrative Officer serves as our chief compliance officer and chairs an
+inter-disciplinary Compliance Council which is charged with assessing and managing our legal and other compliance obligations on a global basis. The Chief Legal and Administrative Officer regularly reports to the Audit Committee regarding our legal
+and compliance obligations. 
+The Director of Internal Audit coordinates the day-to-day risk management process and reports directly to the
+Chief Financial Officer and to the Audit Committee. The Director of Internal Audit performs a risk assessment annually, and updates the Audit Committee at least quarterly regarding our risk analyses, assessments, risk mitigation strategies and
+activities. The Treasury Director updates the Audit Committee at least annually, or more frequently as needed, regarding our directors and officers insurance coverage and on matters regarding certain financial risks. 
+Code of Business Conduct and Ethics and Committee Charters. We have adopted a Code of Business Conduct and Ethics that applies to all directors
+and employees, including our principal executive, financial and accounting officers. The Amended and Restated Code of Business Conduct and Ethics is posted on our website at www.crocs.com. We intend to satisfy the requirements under Item 5.05
+of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of our Code of Business Conduct and Ethics that apply to our directors and principal executive, financial and accounting officers by posting such information on our
+website. The Audit Committee Charter, Compensation Committee Charter and Nominating and Governance Committee Charter are also available on our website at www.crocs.com. Any person may request a copy of the Code of Business Conduct and Ethics or
+committee charters free of charge by submitting a written request to: Corporate Secretary, Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503. 
+8 
+Table of Contents 
+BOARD OF DIRECTORS AND COMMITTEES OF THE BOARD 
+During 2011, the Board met eight times. All directors attended 75% or more of the Board’s meetings and the meetings of the Board committees on which
+they served. We encourage, but do not require, our directors to attend the annual meeting of stockholders. Messrs. Cannon, Croghan, Frasch, Jacobi, McCarvel and Smach and Ms. Wright attended our 2011 Annual Meeting of Stockholders. 
+Board Committees. The Board has the authority to appoint committees to perform certain management and administrative functions and has established
+the following committees. 
+Audit Committee. Messrs. Smach (Chairperson), Frasch and Cannon are the current
+members of the Audit Committee. The Audit Committee met eight times in 2011. The functions of the Audit Committee include oversight of the integrity of our financial statements, our compliance with legal and regulatory requirements, the performance,
+qualifications and independence of our independent auditors and the performance of our internal audit function. The Audit Committee is directly responsible for the appointment, retention, compensation, evaluation, termination and oversight of the
+work of any independent auditor engaged for the purpose of preparing or issuing an audit report or related work. The purpose and responsibilities of the Audit Committee are set forth in the Audit Committee Charter. The Audit Committee Charter can be
+found on our website at www.crocs.com. 
+All of the members of the Audit Committee are independent, as determined in accordance with NASDAQ
+listing standards and relevant federal securities laws and regulations. The Board has determined that Mr. Smach qualifies as an “audit committee financial expert” as defined by the applicable regulations of the SEC. 
+Compensation Committee. Ms. Wright (Chair), Mr. Croghan and Mr. Jacobi are the current members of the Compensation
+Committee. The Compensation Committee, which met four times in 2011, has overall responsibility for defining, articulating, evaluating and approving our executive officer compensation, benefits, severance, equity-based or other compensation plans,
+policies and programs. The Compensation Committee is also responsible for approving our Compensation Discussion and Analysis for inclusion in this proxy statement. The purpose and responsibilities of our Compensation Committee are set forth in the
+Compensation Committee Charter, which can be found on our website at www.crocs.com. All of the current members of the Compensation Committee are independent, as determined in accordance with NASDAQ listing standards and relevant federal securities
+laws and regulations. 
+Pursuant to its charter, the Compensation Committee has the authority to, among other things: (i) establish,
+monitor and approve our overall compensation and benefits strategy and philosophy; (ii) review and approve annually corporate goals and objectives relevant to the compensation of our Chief Executive officer, and to approve the Chief Executive
+Officer’s compensation; (iii) oversee management’s decisions concerning the performance and compensation of other executive officers; (iv) oversee the compensation and benefits structure for our employees generally;
+(v) review and make recommendations to the Board with respect to the establishment of any new incentive compensation and equity-based plans; (vi) supervise the administration of our equity-based incentive plans, including the authorization
+of equity grants under such plans; (vii) review and recommend to the Board the terms of written employment agreements, post-employment consulting agreements and severance arrangements for executive officers; (viii) assist the Board in
+developing and evaluating potential candidates for executive officer positions and oversee the development of succession plans for executive officers; (ix) review and recommend to the Board compensation to be paid to our outside directors and
+(x) review and evaluate the relationship between our incentive compensation arrangements and our corporate strategy and risk management policies and practices. 
+The Compensation Committee sets the Chief Executive Officer’s compensation. The Compensation Committee also reviews the recommendations of the Chief Executive Officer with respect to compensation of
+the other named executive officers and, after reviewing such recommendations, sets the compensation of the other named 
+9 
+Table of Contents 
+executive officers. The Compensation Committee relies on its judgment when making compensation decisions after reviewing our performance and evaluating each executive’s performance against
+established goals, leadership ability and responsibilities, and current compensation arrangements. When evaluating total compensation for each of our executive officers, the Compensation Committee reviews the executive officer’s current
+compensation, including equity and non-equity-based compensation. The Compensation Committee also evaluates surveys and other available data regarding the executive compensation programs of comparative companies. The compensation program for
+executive officers and the Compensation Committee assessment process are designed to be flexible so as to better respond to the evolving business environment and individual circumstances. See “Risk Oversight” (above) for the Compensation
+Committee’s evaluation of our compensation program risk. 
+In 2011, the Compensation Committee engaged an outside independent compensation
+consultant, Towers Watson, to provide an evaluation of the 2011 executive bonus plan, long-term incentives and other executive compensation matters. Please see “Compensation Discussion and Analysis” for further description of the role of
+the Compensation Committee. Towers Watson does not provide any services to management and had no relationship with management prior to the engagement. 
+Nominating and Governance Committee. Our Nominating and Governance Committee currently consists of Messrs. Cannon (Chairperson), Frasch and Smach. The Nominating and Governance
+Committee met three times in 2011. The Nominating and Governance Committee assists the Board in promoting our best interests and that of our stockholders through the implementation of sound corporate governance principles and practices. In
+furtherance of this purpose, the Nominating and Governance Committee identifies individuals qualified to become board members and recommends to the Board the director nominees for election at each annual meeting of stockholders. It also reviews the
+qualifications and independence of the members of the Board and its various committees and makes any recommendations the Nominating and Governance Committee members may deem appropriate concerning any changes in the composition of the Board and its
+committees. The Nominating and Governance Committee also recommends to the Board the corporate governance guidelines and standards regarding the independence of outside directors applicable to us and reviews the provisions of the Nominating and
+Governance Committee Charter on a regular basis to confirm that such guidelines, standards and charter remain consistent with sound corporate governance practices and with any applicable legal or regulatory requirements and the NASDAQ listing
+standards. The Nominating and Governance Committee also monitors and leads the Board in its annual review of the Board’s performance. 
+The purpose and responsibilities of our Nominating and Governance Committee are set forth in the Nominating and Governance Committee Charter. The
+Nominating and Governance Committee Charter can be found on our website at www.crocs.com. All of the members of the Nominating and Governance Committee are independent, as determined in accordance with the NASDAQ listing standards. 
+IT Steering Committee. Our IT Steering Committee currently consists of Messrs. McCarvel (Chairperson), Croghan and Jacobi and
+Ms. Wright and met twice in 2011. The IT Steering Committee oversees major information technology (“IT”) related strategies, projects and technology architecture decisions. The IT Steering Committee also monitors whether our IT
+programs effectively support our business objectives and strategies and reports to the Board on IT related matters. The IT Steering Committee is also tasked with evaluating our significant IT strategies. The purpose and responsibilities of the IT
+Steering Committee are set forth in the Audit Committee Charter. 
+Director Nomination Process and Director Qualifications. In
+identifying potential director candidates, the Nominating and Governance Committee relies on recommendations from a number of sources, including current directors and officers. The Nominating and Governance Committee may also hire outside
+consultants, search firms or other advisors to assist in identifying director candidates. The Nominating and Governance Committee will consider director candidates recommended by stockholders on the same basis as it considers other candidates. Any
+stockholder wishing to recommend a candidate for consideration by the Nominating and 
+10 
+Table of Contents 
+Governance Committee may do so by submitting a written recommendation to the Nominating and Governance Committee in accordance with the procedures set forth under “Stockholder Proposals and
+Nominations for 2013 Annual Meeting.” 
+When evaluating a candidate for director, our Nominating and Governance Committee considers, among
+other things, the candidate’s judgment, knowledge, integrity, diversity, expertise and business and industry experience, which are likely to enhance the Board’s ability to govern our affairs and business. We do not have a separate policy
+regarding consideration of diversity in identifying director nominees but the Nominating and Governance Committee strives to nominate directors with a variety of complementary skills and backgrounds so that, as a group, the Board will possess a
+broad perspective and the appropriate talent, skills and expertise to oversee our business. The Nominating and Governance Committee also takes into account independence requirements imposed by law or regulations (including the NASDAQ listing
+standards). In the case of director candidates recommended by stockholders, the Nominating and Governance Committee may also consider the number of shares held by the recommending stockholder, the length of time that such shares have been held and
+the relationship, if any, between the recommending stockholder and the recommended director nominee. 
+11 
+Table of Contents 
+EXECUTIVE OFFICERS 
+In addition to John McCarvel, our President and Chief Executive Officer, whose biographical information is disclosed above under “Election of
+Directors,” our executive officers as of March 31, 2012 include the following individuals: 
+Name 
+Age 
+Position(s) 
+Daniel P. Hart 
+53 
+Executive Vice President, Chief Legal and Administrative Officer 
+Jeffrey J. Lasher 
+47 
+Senior Vice President-Finance, Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) 
+Scott E. Crutchfield 
+50 
+Senior Vice President of Worldwide Operations 
+Daniel P. Hart has served as our Executive Vice President, Chief Legal and Administrative Officer since January
+2010. From June 2009 through December 2009, he served as our Executive Vice President of Administration and Corporate Development. Prior to joining us, Mr. Hart was employed by Océ North America, a digital printing and document
+management division of Océ, N.V., a manufacturing and engineering company publicly traded on the Euronext Amsterdam stock exchange, where he served as Senior Vice President and General Counsel from 2006 to 2009. From 2004 to 2006,
+Mr. Hart served as Senior Vice President – General Counsel and Human Resources for Invensys Controls, a global manufacturing and engineering operation within Invensys plc, a public U.K. conglomerate. From 2002 to 2004, Mr. Hart served
+as Chief Staff Officer for the Development Division of Invensys, a large portfolio of disposal companies within Invensys plc. Previously, Mr. Hart’s experience included service in senior legal positions at Dictaphone Corporation and Brooke
+Group Ltd. and private legal practice in New York City. 
+Jeffrey J. Lasher has served as our Senior Vice
+President-Finance and Chief Financial Officer since April 2011. From January 2011 to March 2011, Mr. Lasher served as our principal accounting officer and interim principal financial officer. From June 2009 to January 2011, he served as our
+Corporate Controller and Chief Accounting Officer. Prior to joining us, Mr. Lasher was a Senior Consultant for Connelly Consulting, a privately-held financial services company, from October 2008 to June 2009. From December 2005 to September
+2008, he was the Vice President - Corporate Controller for Corporate Express Inc., a publicly-held business supplies and equipment company. Mr. Lasher was also the Vice President – Finance of AutoNation, Inc., a publicly-held automotive
+retail company, from December 2000 to December 2005. 
+Scott E. Crutchfield has served as our Senior Vice President of
+World Wide Operations since May 2010. From February 2006 to May 2010, he served as our Vice President for Worldwide Operations. Prior to joining us, he served as Senior Director, U.S. and South America Operations for Jabil Circuit, a publicly-held
+design and manufacturing company from May 2004 to January 2006. Mr. Crutchfield was also Vice President, General Manager Central/Eastern U.S. and South America for Flextronics from March 2000 to April 2004. Previously, Mr. Crutchfield also
+held senior leadership positions at Dovatron International, a subsidiary of the Dii Group, and at Square D, a subsidiary of Schneider Electric. 
+12 
+Table of Contents 
+BENEFICIAL OWNERSHIP OF OUR COMMON STOCK 
+Ownership by Our Directors, Executive Officers and Greater than 5% Stockholders 
+The following table sets forth information with respect to the beneficial ownership of our common stock as of March 31, 2012 by: 
+• 
+each person (or group of affiliated persons) who is known by us to own beneficially more than 5% of our common stock; 
+• 
+each current director or nominee; 
+• 
+each of the named executive officers listed in the Summary Compensation Table below; and 
+• 
+all directors and executive officers as a group. 
+Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, shares of common stock subject to options held by that person that are currently
+exercisable, or exercisable within 60 days after March 31, 2012, are deemed to be outstanding and beneficially owned by that person. None of these shares, however, are deemed outstanding for the purpose of computing the percentage
+ownership of any other person. 
+Except as indicated and pursuant to applicable community property laws, each stockholder named in the table
+has sole voting and investment power with respect to the shares set forth opposite such stockholder’s name. Percentage ownership is based on 89,895,490 shares of our common stock outstanding on March 31, 2012. Unless otherwise indicated
+below, the address for each director and named executive officer listed below is in care of Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado. 
+Beneficial Ownership 
+Name of Beneficial Owner 
+Shares 
+Percent 
+5% Stockholders: 
+Blackrock, Inc. (1) 
+6,801,358 
+7.6 
+% 
+The Vanguard Group, Inc (2) 
+5,338,891 
+5.9 
+% 
+Cramer Rosenthal McGlynn LLC (3) 
+6,659,850 
+7.4 
+% 
+Directors: 
+Peter A. Jacobi (4) 
+33,067 
+* 
+Thomas J. Smach (5) 
+174,312 
+* 
+Raymond D. Croghan (6) 
+39,104 
+* 
+W. Stephen Cannon (7) 
+56,620 
+* 
+Ronald L. Frasch 
+51,764 
+* 
+Doreen A. Wright 
+3,899 
+* 
+Officers: 
+John P. McCarvel (8) 
+615,685 
+* 
+Daniel P. Hart (9) 
+168,827 
+* 
+Jeffrey J. Lasher (10) 
+150,815 
+* 
+Scott E. Crutchfield (11) 
+162,655 
+* 
+All current directors and executive officers as a group
+(10 persons) (12) 
+1,456,748 
+1.6 
+% 
+* 
+Less than 1% 
+(1) 
+Based solely on a Schedule 13G/A filed with the SEC on February 13, 2012. The address for Blackrock, Inc. is 40 East 52 nd Street, New York, New York 10022. 
+(2) 
+Based solely on a Schedule 13G/A filed with the SEC on February 8, 2012. The address for The Vanguard Group, Inc. is 100 Vanguard Blvd., Malvern,
+PA 19355. 
+13 
+Table of Contents 
+(3) 
+Based solely on a Schedule 13G filed with the SEC on February 13, 2012. The address for Cramer Rosenthal McGlynn, LLC is 520 Madison Ave., New
+York, NY 10022. 
+(4) 
+Shares beneficially owned include 31,945 shares held in trust by Peter A Jacobi & Mary Louise Jacobi Living Trust.
+(5) 
+Shares beneficially owned include 122,609 shares subject to options exercisable within 60 days of March 31, 2012 and 4,400 shares held as
+custodian for Mr. Smach’s two children under the New York Uniform Gifts to Minors Act. Mr. Smach exercises voting and investment power over the shares. 
+(6) 
+Shares beneficially owned include 18,406 shares subject to options exercisable within 60 days of March 31, 2012 and an aggregate of 4,960
+shares of common stock beneficially owned by two trusts for the benefit of Mr. Croghan’s two daughters. Mr. Croghan’s spouse is the trustee of both trusts and she exercises sole voting and investment power over the shares.
+Mr. Croghan disclaims beneficial ownership of such shares. 
+(7) 
+Shares beneficially owned include 56,375 shares held in trust by The W. Stephen Cannon Revocable Trust. 
+(8) 
+Shares beneficially owned include 127,664 shares subject to options exercisable within 60 days of March 31, 2012 and 207,774 shares held
+jointly with his spouse. 
+(9) 
+Shares beneficially owned include 29,166 shares subject to options exercisable within 60 days of March 31, 2012.
+(10) 
+Shares beneficially owned include 27,292 shares subject to options exercisable within 60 days of March 31, 2012.
+(11) 
+Shares beneficially owned include 72,423 shares subject to options exercisable within 60 days of March 31, 2012.
+(12) 
+Shares beneficially owned include 141,015 shares of common stock subject to options issued to directors and 256,545 shares of common stock subject to
+options issued to named executive officers that are exercisable or issuable within 60 days of March 31, 2012. 
+Section 16 Beneficial Ownership and Compliance 
+Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors and executive officers and persons who own more than ten percent of our common stock to file with the SEC and
+any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common stock. 
+To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations from certain of our officers and directors that no other reports were required, we
+believe that all required reports of our officers, directors and greater than ten percent stockholders under Section 16(a) were timely filed during the year ended December 31, 2011, except for one Form 4 for Scott Crutchfield relating to
+the exercise of options and the sale of common stock. 
+14 
+Table of Contents 
+CERTAIN RELATIONSHIPS AND RELATED PERSON TRANSACTIONS 
+Related Person Transactions 
+We had no
+transactions with related persons during 2011 which are required to be disclosed by the rules of the SEC. 
+Policy on Transactions with
+Related Persons 
+Our Code of Business Conduct and Ethics requires that any transaction involving us in which one of our directors,
+nominees for director, executive officers, or greater than five percent stockholders, or one of the aforementioned’s immediate family members (each, a “related person”), have a material interest be approved or ratified by the Audit
+Committee if the amount involved, when aggregated with the amount of all other transactions between the related person and us, exceeds $100,000 in a fiscal year. The full Board reviews ordinary course of business transactions in which directors have
+an interest as part of the Board’s annual director independence review, and our Code of Business Conduct and Ethics permits the full Board to waive any conflicts of interest between us and any director or officer. In determining whether to
+approve or ratify any such transaction, the Audit Committee must consider, in addition to other factors it deems appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify certain directors and executive officers in addition to the indemnification provided for in our certificate
+of incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain expenses (including attorneys’ fees), judgments, fines and settlement amounts incurred by any
+such person in any action or proceeding, including any action by us or in our right, arising out of such person’s services as a director or executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person
+provided services at our request. We believe that these provisions and agreements are necessary to attract and retain qualified persons as directors and executive officers. 
+15 
+Table of Contents 
+DIRECTOR COMPENSATION 
+On June 29, 2011, the Board approved a new compensation program for non-employee directors, effective as of that date (the “2011
+Program”), following a review by our Nominating and Governance Committee. The Committee was assisted in this review by its outside compensation consultant, Towers Watson, which provided advice and perspective regarding peer group practices
+(using the same companies that were used for peer comparisons for executive compensation) and broader market trends. Directors are compensated with a combination of an annual retainer and fees for serving on committees, paid in cash or restricted
+stock at the director’s election, and annual equity grants. Directors who are employees of the Company are not eligible to receive this compensation. Directors do not receive additional fees for attendance at meetings. The following describes
+amounts payable to our non-employee directors under the 2011 Program. 
+Retainer Fees. Directors receive an annual retainer
+fee for Board service, which under the 2011 Program was $150,000 for the Chairman of the Board and $100,000 for each of our other non-employee directors. Directors who serve as chairpersons of the Audit Committee, the Compensation Committee and the
+Nominating and Governance Committee receive additional annual retainer fees of $30,000, $20,000 and $10,000, respectively. Directors also receive additional annual retainer fees for committee service, as follows: members of the Audit Committee
+receive an additional $15,000, members of the Compensation Committee receive an additional $10,000 and members of the Nominating and Governance Committee and members of the IT Steering Committee receive an additional $5,000. These annual retainer
+fees are denominated in cash and payable in quarterly installments unless the director elects to be paid in shares of restricted stock or a combination of cash and restricted stock. The number of shares of restricted stock is determined based on the
+fair market value of our common stock on the date the retainer is payable. The restricted stock vests in four successive quarterly installments from the issuance date. Messrs. Cannon and Smach elected to receive their annual retainer fees partly in
+cash and partly in restricted stock, and Messrs Croghan, Frasch and Jacobi elected to receive all their annual retainer fees in restricted stock. Ms. Wright elected to receive her annual retainer fees in cash. 
+Equity Awards. Directors receive annual equity awards for Board service, which under the 2011 Program consisted of a grant of $150,000
+of our common stock for the Chairman of the Board and a grant of $100,000 of our common stock for each of our other non-employee directors. The number of shares of common stock was determined based on the fair market value of our common stock on the
+date of grant. The annual equity compensation for the Chairman of the Board also consisted of an option to purchase 10,000 shares of our common stock at an exercise price equal to the fair market value of the shares on the date of grant. These
+options vest and become exercisable in four equal installments on the respective dates of each of the four annual meetings of stockholders following the year of grant. 
+All directors are reimbursed for their reasonable out-of-pocket expenses incurred in attending meetings of the Board and its committees. 
+16 
+Table of Contents 
+The table below summarizes the total compensation paid to each non-employee directors during the fiscal year
+ended December 31, 2011. 
+Name 
+Fees Earned or 
+Paid in Cash 
+Stock 
+Awards (1) 
+Option Awards (1) 
+Total 
+W. Stephen Cannon 
+$ 
+110,000 
+$ 
+125,018 
+$ 
+— 
+$ 
+235,018 
+Raymond D. Croghan 
+— 
+215,024 
+— 
+215,024 
+Ronald L. Frasch 
+— 
+220,026 
+— 
+220,026 
+Peter A. Jacobi 
+— 
+215,024 
+— 
+215,024 
+Richard L. Sharp (2) 
+— 
+199,993 
+— 
+199,993 
+Thomas J. Smach 
+117,500 
+200,695 
+112,481 
+430,676 
+Doreen A. Wright (3) 
+$ 
+62,500 
+$ 
+101,413 
+$ 
+— 
+$ 
+163,913 
+(1) 
+Represents the grant date fair value. Assumptions used in to calculate these values are included in Note 9 to the Consolidated Financial
+Statements included in our Annual Report on Form 10-K for the year ended December 31, 2011. 
+(2) 
+Mr. Sharp resigned as a member of the Board on June 29, 2011. 
+(3) 
+Ms. Wright was elected to the Board on June 29, 2011. 
+As of December 31, 2011, each non-employee director had the following number of stock options and unvested shares of restricted stock outstanding: 
+Options 
+Outstanding at 
+December 31, 2011 
+Unvested Restricted 
+Stock Awards 
+Outstanding
+at 
+December 31, 2011 
+W. Stephen Cannon 
+— 
+489 
+Raymond D. Croghan 
+18,406 
+2,244 
+Ronald L. Frasch 
+— 
+2,341 
+Peter A. Jacobi 
+— 
+2,244 
+Richard L. Sharp 
+— 
+— 
+Thomas J. Smach 
+132,609 
+975 
+Doreen A. Wright 
+— 
+— 
+Director Ownership Guidelines 
+In 2012, we adopted stock ownership guidelines for our directors. The guidelines require that each of our directors own at least 5,000 shares of our common stock within the later of three years from
+(i) adoption of the policy or (ii) within three years of their election to the Board. 
+17 
+Table of Contents 
+EXECUTIVE COMPENSATION 
+Compensation Discussion and Analysis 
+This Compensation Discussion and Analysis provides information about our executive compensation program as it relates to the following “named
+executive officers” whose compensation information is presented in the tables and accompanying narratives following this discussion: 
+• 
+John P. McCarvel, Chief Executive Officer and President 
+• 
+Jeffrey J. Lasher, Senior Vice President-Finance and Chief Financial Officer 
+• 
+Daniel P. Hart, Executive Vice President, Chief Legal and Administrative Officer 
+• 
+Scott E. Crutchfield, Senior Vice President, Worldwide Operations 
+Executive Summary 
+2011 Business Performance. In 2011, we reached
+an important milestone by achieving more than $1.0 billion in revenue for the first time. Gross profit increased by 26.6% and diluted earnings per share increased by 63.2% in 2011. The following table highlights the year-over-year comparison of some
+of our Company’s key financial results. 
+($ in millions, except per share amounts) 
+2011 
+2010 
+Change 
+Annual revenues* 
+$1,001 
+$790 
+26.7% 
+Annual gross profit 
+$536 
+$424 
+26.6% 
+Annual selling, general and administrative costs as a % of revenue 
+40.2% 
+43.3% 
+(0.7)% 
+Diluted earnings per share* 
+$1.24 
+$0.76 
+63.2% 
+Annual gross margin 
+53.6% 
+53.7% 
+(0.1)% 
+Inventory as of December 31* 
+$130 
+$121 
+0.7% 
+Cash and cash equivalents as of December 31* 
+$258 
+$146 
+76.7% 
+*
+Indicated metrics were used as performance measures in our 2011 incentive plans. 
+During the year ended December 31, 2011, revenues
+increased $211.2 million, or 26.7%, compared to the same period in 2010, and exceeded $1.0 billion for the first time in the history of our business. This revenue growth was driven by expansion in all three of our operating segments as we
+focused on improving average footwear selling prices with new product styles, the expansion of existing and new wholesale accounts and the continued expansion of our direct-to-consumer sales channels. 
+Also during the year ended December 31, 2011, diluted earnings per share improved to $1.24 compared to $0.76 during the same period in 2010 and
+operating margin increased to 13.6% from 10.3% which were both driven by improved leverage from selling, general and administrative expenses while gross margin remained relatively flat. 
+These financial improvements resulted from stronger sales in each of our geographic operating segments and more effective marketing and merchandising programs, ongoing investment in the growth of our
+retail and internet channels which have historically yielded higher margins. They also reflect strong global demand for our diversified product line as we continue to transform Crocs brand awareness to an all-season footwear brand despite a
+difficult global economic selling environment and increased global competition from footwear manufacturers and retailers. As a percentage of total revenues, revenues generated from the clog silhouette sales continued to decrease with the expansion
+of our product line. 
+18 
+Table of Contents 
+CEO Performance and Compensation . Since being named our Chief Executive Officer in
+early 2010, John McCarvel has led the Company’s turnaround strategy. Highlights of the Company’s achievements under Mr. McCarvel’s leadership include: 
+• 
+Return to profitable growth in 2011 and 2010 for the first time since 2007; 
+• 
+Annual revenue growth to over $1.0 billion for the first time in our 10-year history; 
+• 
+Expansion of product offerings, bringing the total number of Crocs™ shoe styles to more than 300 including sneakers and boots, which allows Crocs
+to become a viable four-season brand; 
+• 
+Opening of 97 new Crocs retail stores worldwide, as well as increasing online presence so consumers can shop the brand from anywhere; and
+• 
+Reinvigoration of our corporate social responsibility platform, Crocs Cares, which focuses on helping to make a difference in the lives of children and
+families in need through initiatives that positively impact the environment, employees and local and global communities. 
+In
+recognition of his achievements, Mr. McCarvel received the prestigious Stevie Award for turnaround executive of the year at the 2011 American Business Awards. 
+Mr. McCarvel’s 2011 compensation reflects these achievements and our pay for performance philosophy. Mr. McCarvel received an annual cash incentive award payout of $1.3 million which
+represented 153% of target and reflected Company performance that exceeded the 2011 goals for sales growth, earnings per share, inventory turnover and net unrestricted cash. Mr. McCarvel also received a 5.0% increase in salary for 2011 to align
+with peer company practices, and an annual award of 52,224 restricted stock units (at target subject to achievement of an earnings per share growth target and time-based vesting) to provide incentive for long-term performance. In recognition of his
+contributions and achievements, and for purposes of retention, the Compensation Committee (the “Committee”) granted Mr. McCarvel a special award of $1.0 million in value of time vested restricted stock units (38,986 units) in June
+2011. The Committee believes that time based restricted stock units were the appropriate award to achieve the grant’s retention goal. 
+Corporate Governance Highlights. In order to further align the long-term interests of management with those of our
+stockholders and align our compensation program with best practices, the Committee has established the following policies and practices. 
+• 
+Independent Compensation Committee . The Committee, comprised solely of independent directors, approves all compensation for our named executive
+officers. 
+• 
+Independent compensation consultant . The Committee retains an independent compensation consultant that does not provide any services to
+management and that had no relationship with management prior to the engagement. 
+• 
+Assessment of compensation risk. The Committee assessed our compensation policies and programs and determined that we have no compensation
+policies and programs that give rise to risks reasonably likely to have a material adverse effect on the Company. 
+• 
+Annual Say-on-Pay vote . We will hold annual say-on-pay, or advisory votes to approve executive compensation. 
+• 
+Executive stock ownership guidelines . Our Board adopted stock ownership guidelines that our named executive officers are expected to meet within
+three years. 
+19 
+Table of Contents 
+• 
+Clawback policy . Our Board adopted a clawback policy for awards made pursuant to our annual cash incentive plan and in 2012 also implemented a
+clawback policy under which all annual and long-term incentive awards, including those granted in 2012, are subject to any clawback or recoupment policy adopted by us pursuant to the requirements of the Dodd-Frank Wall Street Reform and Consumer
+Protection Act. 
+• 
+No excise tax gross-ups . We do not provide our management with “excise tax gross-ups” in the event of a change of control.
+• 
+No enhanced benefit programs . We do not provide our management with pensions, supplemental executive retirement plans or any other enhanced
+benefit programs beyond those that are typically available to all other employees other than a deferred compensation plan for senior executives, which is funded by deferred bonus payments to senior executives. 
+• 
+Limited perquisites . Our management receives minimal perquisites, consisting primarily of health insurance premiums.
+Executive Compensation Objectives and Principles 
+The objectives of our executive compensation program are to: 
+• 
+attract and retain exemplary executive talent who are able to succeed in our fast-paced, rapidly evolving Company; 
+• 
+hold our executives accountable to stockholders; 
+• 
+motivate our executives to achieve our financial and strategic business objectives; 
+• 
+align our executives’ compensation with our stockholders’ interests; and 
+• 
+assure that our total compensation program aligns with good corporate governance and best practices. 
+We achieve these objectives through implementing the following pay principles. 
+• 
+Fair and Competitive : We believe that a fair and competitive pay package for our executives is essential to attract and
+retain talented executives in key positions. 
+• 
+Short and Long-Term Incentives: Our compensation program rewards both short-term and long-term performance. Annual cash incentive
+awards are tied to achievement of short-term quantitative performance goals that we believe closely correlate to shareholder value. Long-term performance is rewarded through equity-based awards, which align our executives’ interests with those
+of our stockholders. The value of equity awards depends on future share prices, and the realization of the awards is contingent on satisfaction of vesting schedules requiring continued service with us and the achievement of performance goals.
+• 
+Pay for Performance : Our executives have a high proportion of variable, performance-based compensation. We aim to tie more
+than 50% of our executive pay to performance metrics. Actual compensation will be above or below targeted levels depending on the level of performance achieved. 
+• 
+Good Governance: We have designed our executive compensation program in light of the best practice governance policies and practices
+discussed above under “Corporate Governance Highlights.” 
+At our annual meeting of stockholders in June 2011, we
+held our first advisory stockholder vote to approve the compensation of our named executive officers (“say-on-pay”). The compensation of our named executive 
+20 
+Table of Contents 
+officers reported in our 2011 proxy statement was approved by over 98% of the votes cast at the 2011 annual meeting. The Committee believes this affirms our stockholders’ support of our
+approach to executive compensation, and the Committee did not change its approach in 2011. The Committee will continue to consider the outcome of our say-on-pay votes when making future compensation decisions for the named executive officers.
+Governance of Pay Setting Process 
+Role of Compensation Committee, Chief Executive Officer and Compensation Consultant 
+The Committee has overall responsibility for evaluating and approving our executive officer compensation, benefits, severance, equity-based or other
+compensation plans, policies and programs. The Committee sets the Chief Executive Officer’s compensation, and considers the recommendations of the Chief Executive Officer with respect to the compensation of the other named executive officers.
+The Committee works with Towers Watson, an independent executive compensation consultant engaged by the Committee, for advice and perspective regarding market trends and best practices. For a more detailed discussion about the Committee, its
+methodology and the role of consultants, see “Compensation Committee” on page 9. 
+Peer Group Companies 
+The Committee uses peer company and survey data to guide its review of the total compensation of our officers and executives and generally reviews the
+compensation data of our peer companies and industry to understand market competitive compensation. The Committee focuses on ensuring that the performance-based elements of our executive compensation program are consistent with peer and industry
+trends. However, the Committee does not benchmark compensation to a specific percentage of the compensation of peer companies. 
+In 2011, the
+Committee approved a revised peer group based on analysis and preliminary recommendations by Towers Watson. The peer group was selected based on the key industry criteria noted below, and took into consideration the company’s revenue, market
+capitalization and other key financial metrics. This peer group is comprised of 14 publicly traded companies. As of the most recent fiscal year-end, our market capitalization was at the fifth percentile of this group and our revenue was at the
+fourth percentile of the group. We believe these companies are broadly comparable to us, and represent our labor market for talent for key leadership positions. The Committee will regularly review our peer group to determine if adjustments are
+necessary to ensure that it continues to be relevant or if additional peer companies or groups are necessary to provide appropriate information on market practices and compensation levels. 
+The 2011 peer companies and the criteria for their inclusion are listed below: 
+Columbia Sportswear Co. 
+G III Apparel Group, Ltd. 
+Skechers USA, Inc 
+Deckers Outdoor Corp. 
+Oxford Industries, Inc. 
+Steven Madden, LTD 
+DSW Inc. 
+Perry Ellis International, Inc. 
+Under Armour, Inc. 
+Fossil, Inc. 
+Quiksilver, Inc. 
+Wolverine Worldwide, Inc 
+Genesco Inc. 
+Shoe Carnival Inc. 
+The peer group used in 2011 differs from the peer group used in the 2010 executive compensation review process in the
+following respects: (i) DSW Inc., Fossil, Inc., Genesco Inc. and Shoe Carnival Inc., were added and (ii) American Apparel, Inc., Brown Shoe Co., Inc., Kenneth Cole Productions, Inc., Delta Apparel, Inc., K-Swiss,
+Inc., Lululemon Athletica, Inc., Timberland Co., True Religion Apparel, Inc. and Volcom, Inc. were deleted. These changes served to make the overall composition of the peer group better reflect our size, complexity, growth prospects,
+product focus and labor market for executive talent. The Committee intends to continue to monitor how changes in the peer group will impact the peer group information it reviews in making its executive compensation decisions. 
+21 
+Table of Contents 
+Elements of Compensation 
+Our executive compensation objectives and principles are implemented through the use of the following principal elements of compensation, each of which is discussed more fully below: 
+• 
+Base salary, which provides a fixed level of cash compensation; 
+• 
+Annual cash incentive awards, which motivate and reward annual company performance; 
+• 
+Long-term incentives (in the form of equity awards), which motivate and retain executives by rewarding long-term financial performance and tying
+incentives to the performance of our common stock over the long-term; and 
+• 
+Limited executive benefits and perquisites. 
+The Committee does not utilize an exact calculation in determining the break-down or weighting of named executive officer compensation among base salary, annual cash incentive awards and long-term equity
+awards. Rather, the Committee considers all forms of compensation in light of the market competition for executive talent, the risk to an executive inherent in employment with our fast-paced, rapidly evolving Company and our financial goals.
+Accordingly, we believe that over 50% of each named executive officer’s compensation should be in the form of annual cash performance-based awards and equity awards that vest upon performance. We believe that the total compensation
+opportunities offered to our executives are sufficient to reduce the need for anything other than limited executive perquisites or enhanced benefit programs beyond those that are typically available to all other employees. 
+Base Salary. The Committee establishes base salary for our named executive officers by considering the size of our operations, the
+responsibilities of the named executive officers and the competitive marketplace for executive talent in similar positions. The Committee sets the base salary of the Chief Executive Officer. Base salary for other named executive officers is set by
+the Committee after considering the recommendation of the Chief Executive Officer. 
+Base salary is reviewed on an annual basis and at the time
+of hire or promotion. Annual adjustments are influenced by growth of our operations, revenues and profitability, individual performance, changes in responsibility, peer company comparisons and other factors. 
+The current base salaries of our named executive officers and the percentage increase over 2010 base salary follows: 
+Named Executive Officer 
+2011 Base Salary 
+Increase Over 
+2010 Base Salary 
+John P. McCarvel 
+$ 
+840,000 
+5.0% 
+Daniel P. Hart 
+$ 
+498,750 
+5.0% 
+Jeffrey J. Lasher 
+$ 
+325,000 
+30.0% 
+Scott E. Crutchfield 
+$ 
+325,000 
+— 
+Upon Mr. Lasher’s promotion to Chief Financial Officer in April 2011, the Committee increased his base salary to
+reflect the additional responsibilities of his position and to align his base salary with the chief financial officers of our peer companies. 
+Annual Incentive Awards. The Committee believes that an annual cash incentive plan that offers significant awards to our
+named executive officers for meeting or exceeding company performance goals provides our officers additional incentive to outperform our peer companies and ensures that we attract and retain talented named executive officers. 
+22 
+Table of Contents 
+Each year, the Committee establishes a target annual incentive award for each named executive officer
+expressed as a percentage of the executive’s base salary, based on the estimated contribution and responsibility of the individual named executive officer and considering market practices. For 2011, the targets were: 
+Named Executive Officer 
+Annual Incentive Plan Target 
+(as a percentage of Base Salary) 
+John P. McCarvel 
+100% 
+Daniel P. Hart 
+60% 
+Jeffrey J. Lasher 
+60% 
+Scott E. Crutchfield 
+60% 
+The total annual incentive award actually paid to each named executive officer is determined based on the extent to which
+specified weighted objective performance goals are achieved. Each of these performance targets has a threshold payout of 75% of the named executive officer’s annual incentive award target and a maximum payout of 175% of the target. For 2011,
+these goals and their applicable weightings were: 
+Performance Goal Targets 
+Weighting 
+2011
+Actual 
+Performance as 
+a Percentage of 
+Target 
+Annual Revenues: $934.6
+million 
+20% 
+35.0% 
+Earnings Per Share:
+$1.09 
+50% 
+81.3% 
+Inventory Turnover: 3.48 
+15% 
+20.1% 
+Net unrestricted cash (net of short- and long-term debt): 
+$254.9 million 
+15% 
+16.7% 
+After reviewing 2011 actual results and applying the weighting described above, the Committee determined that our named
+executive officers would be paid annual incentive awards at up to 153% of their respective target annual incentive award amounts because our 2011 performance results, in the aggregate, exceeded the aggregate weighted performance targets by 53%.
+In keeping with our pay for performance philosophy, if we did not reach the threshold targets, the named executive officers would not have
+been eligible for that portion of the annual incentive award. The Committee has discretion to depart from the formula in approving the annual incentive awards by decreasing, but not increasing, incentive awards after general results are known.
+Long-Term Equity Awards. The Committee grants long-term equity awards annually to the named executive officers in order to
+provide long-term performance-based compensation, to encourage the named executive officers to continue their employment throughout the vesting periods of the awards, and to align management and stockholder interests. We believe that a significant
+portion of each named executive officer’s compensation should be in the form of equity awards. The Committee considers each year the number of shares to grant and the appropriate type and combination of equity-based awards in making named
+executive officer grant decisions. 
+23 
+Table of Contents 
+2011 Long-Term Performance Incentive Program . In 2011, all of our named executive officers received
+grants of restricted stock units (“RSUs”), half of which vest based on satisfaction of performance goals and half of which vest based on continued service. The material terms of the 2011 restricted stock awards are as follows: 
+Time Vested RSUs 
+(50% of Award) 
+Performance Vested RSUs
+(50% of Award) 
+Performance Goal 
+Potential Award 
+Further Time 
+Vesting 
+Vest in 3 annual installments beginning one year after the
+date of grant 
+Achievement of at least 70% of a two-year cumulative earnings per share
+performance goal 
+Executive may earn from 50% to 200% of the target number of RSUs based on the level of achievement of the
+performance goal 
+Earned RSUs vest 50% upon satisfaction of performance goal
+and 50% one year later 
+For 2011, the amount of restricted stock unit awards granted to the named executive officers was based on a review of the
+equity compensation of our peer companies, input from the independent compensation consultant and the Committee’s assessment of each named executive officer’s expected future contributions. 
+The Committee grants performance-based awards to further demonstrate our pay for performance philosophy and better align the interests of our named
+executive officers with those of our stockholders. The Committee grants restricted stock units because it generally believes that full value awards such as restricted stock units offer a stronger retention incentive than do stock options. In
+addition, restricted stock units are less dilutive to our current stockholders and to the Company’s 2007 Amended and Restated Equity Incentive Plan than are stock options, as fewer restricted stock units are necessary to provide the same equity
+benefit compared to stock options. The Committee selected cumulative earnings per share as the performance metric because it views cumulative earnings per share as a primary driver of enhanced stockholder value. 
+However, the Committee believes it is appropriate to grant stock options in certain cases of promotion or new hire, and in April 2011 granted to
+Mr. Lasher stock options for 30,000 shares in connection with his promotion to Chief Financial Officer. These stock options vest 25% on the first anniversary of the grant date and in 36 equal monthly installments thereafter. The Committee also
+granted Mr. Lasher 30,000 restricted shares that vest ratably on each of the first three anniversaries of the grant date subject to Mr. Lasher’s continuous employment with us. The Committee granted these awards in recognition of the
+additional responsibilities of Mr. Lasher’s position and to align his compensation with the chief financial officers of our peer companies. 
+In June 2011, the Committee recommended and the Board granted a special retention award of $1.0 million in value of restricted stock units (38,986 units) to Mr. McCarvel, which will vest ratably
+on each of the first three anniversaries of the grant date. As described above, this special award was granted to Mr. McCarvel in recognition of his contributions in leading the turnaround strategy of the Company and for purposes of retention.
+Other Benefits. We provide other benefits to our named executive officers in order to achieve a competitive pay package. The
+Committee believes that those benefits, which are detailed in the Summary Compensation Table under the heading “All Other Compensation,” are reasonable, competitive and consistent with our overall executive compensation program. Those
+benefits consist principally of employer-paid premiums on health insurance. 
+Post-Employment Compensation 
+Senior Executive Deferred Compensation Plan. Certain senior executives are eligible to participate in the 2007 Senior Executive
+Deferred Compensation Plan (the “Deferred Compensation Plan”). Under the Deferred Compensation Plan, an executive may defer all or a part of his or her cash compensation in accordance with the 
+24 
+Table of Contents 
+terms and conditions established by the Committee. The Deferred Compensation Plan permits executives to save for future financial needs, and contributes to the Company’s attractiveness
+as an employer. The amount of salary and annual incentive earned by an executive is not affected by the Deferred Compensation Plan. No named executive officers have contributed to the Deferred Compensation Plan since 2008. For a more detailed
+discussion of the Deferred Compensation Plan, see the Nonqualified Deferred Compensation table and accompanying narrative on page 31. 
+Severance and Change in Control Benefits. We entered into an employment agreement with Mr. Hart concurrent with his appointment as an officer in 2009. The agreement provides for
+guaranteed payments and accelerated vesting of certain equity awards upon his involuntary termination of employment with us (other than for cause) or his resignation for good reason. For a more detailed discussion of the agreement, see Potential
+Payments on Termination or Change in Control beginning on page 31. 
+Additional Considerations 
+Executive Stock Ownership. In March 2012, the Committee adopted stock ownership guidelines to ensure that our senior executive
+officers have a meaningful stake in the equity of the Company and to further align the interests of our executives with the long-term interests of our stockholders. Under these guidelines, our Chief Executive Officer is required to hold 10,000
+shares of our common stock and the other named executive officers are required to hold 5,000 shares. The ownership guidelines assume that, in normal circumstances, an executive can reach the requisite stock ownership within the later of three years
+from (i) the adoption of the guidelines or (ii) the date the executive’s employment commences. These ownership guidelines are based on analysis of peer and market practices, as prepared by the Committee’s independent compensation
+consultant. 
+Equity Granting Practices. The Committee has determined to make our annual equity award grants at the regular
+meeting of the Committee held in the first quarter of each year. The Committee meeting date, or the next business day if the meeting falls on a day where the Nasdaq is closed for trading, is the effective grant date for the grants. The stock option
+exercise price is the fair market value of our common stock on that date. 
+We also may grant equity awards (e.g., options, restricted stock)
+to recognize increased responsibilities or special contributions, attract new hires, retain executives or recognize certain other special circumstances that occur throughout the year. The effective date of these grants is determined based on the
+timing of the recognition or recruitment event and approved on or in advance of the effective date of the grant. The exercise/grant price is the fair market value of our common stock on the effective date. The Committee approves all equity grants to
+executive officers. We do not permit repricing of stock options without stockholder approval. 
+Clawbacks. In 2010, our Compensation
+Committee adopted a clawback policy for awards made under our annual incentive plan. Under this policy, at the discretion of the Committee, executives may be required to repay awards to us if within two years of the award: (i) we are required
+to restate our financial statements due to fraud or willful misconduct involving the executive; or (ii) the executive took part in any fraud, negligence or breach of fiduciary duty. 
+In 2012, our Board also adopted a policy whereby any incentive compensation awards granted to management, including annual and long-term incentive awards granted in 2012, will be subject to any clawback
+or recoupment policy adopted by the Company pursuant to the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act. 
+Deductibility of Executive Compensation. Section 162(m) of the Code imposes a $1.0 million annual limit on the amount that a public
+company may deduct for compensation paid to the company’s chief executive officer during a tax year or to any of the company’s four other most highly compensated executive officers who are still employed at the end of the tax year. The
+limit does not apply to compensation that meets the requirements of the Code for “qualified performance-based” compensation (i.e., compensation paid only if the executive meets pre-established, objective goals based on performance
+criteria approved by the company’s stockholders). 
+25 
+Table of Contents 
+The Committee reviews and considers the deductibility of executive compensation under Section 162(m) of
+the Code. In certain situations, the Committee may approve compensation that does not meet the requirements of the Code in order to ensure competitive levels of total compensation for our executive officers. The annual incentive awards paid in 2012
+under our 2008 Cash Incentive Plan and the stock option grant to Mr. Lasher in 2011 are designed to meet the requirements for consideration as “qualified performance-based compensation” under Section 162(m). The Committee intends
+that future performance-vested restricted stock units will also meet such requirements. 
+COMPENSATION COMMITTEE REPORT 
+The Compensation Committee has reviewed the
+foregoing Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K and discussed the Compensation Discussion and Analysis with our management. Based on such review and discussions with management, the Compensation
+Committee recommended to the Board that the foregoing Compensation Discussion and Analysis be included in this proxy statement. 
+THE
+COMPENSATION COMMITTEE 
+Doreen A. Wright (Chairperson) 
+Raymond D. Croghan 
+Peter A. Jacobi 
+Summary Compensation Table 
+The following table sets forth information regarding
+compensation earned for services rendered during fiscal years 2011, and, where applicable, 2010 and 2009 for our Chief Executive Officer, our Chief Financial Officer, and the two other most highly compensated executive officers who were serving as
+executive officers at the end of 2011. 
+Name and Principal Position 
+Year 
+Salary 
+($) 
+Bonus 
+($) 
+Stock 
+Awards (1) 
+($) 
+Option 
+Awards (1) 
+($) 
+Non-Equity 
+Incentive Plan 
+Compensation (2) 
+($) 
+All
+Other 
+Compensation (3) 
+($) 
+Total 
+($) 
+John P. McCarvel (4) 
+2011 
+$828,333 
+$— 
+$2,349,981 
+$— 
+$1,285,200 
+$15,015 
+$4,478,529 
+President and Chief Executive Officer 
+2010 
+766,667 
+— 
+831,723 
+— 
+800,000 
+233,451 
+2,631,841 
+2009 
+595,833 
+240,000 
+— 
+— 
+— 
+48,044 
+883,877 
+Daniel P. Hart (5) 
+2011 
+491,823 
+— 
+475,019 
+— 
+450,000 
+14,606 
+1,431,449 
+Executive Vice President, Chief Legal 
+2010 
+475,000 
+— 
+296,298 
+— 
+339,150 
+41,403 
+1,151,851 
+and Administrative Officer 
+2009 
+259,119 
+208,220 
+598,500 
+403,680 
+— 
+130,565 
+1,600,084 
+Jeffrey J. Lasher (6) 
+2011 
+300,000 
+— 
+1,078,320 
+266,802 
+300,000 
+14,606 
+1,959,728 
+Senior Vice President-Finance and Chief Financial Officer 
+Scott E. Crutchfield 
+2011 
+$325,000 
+— 
+$350,009 
+— 
+$240,000 
+$15,106 
+$930,115 
+Senior Vice President of Worldwide Operations 
+(1) 
+Amounts reflect the aggregate grant date fair value of grants made in each respective fiscal year computed in accordance with stock-based accounting
+rules (Financial Standards Accounting Board (“FASB”) ASC Topic 718). Assumptions used in the calculations of these amounts are included in Note 9 to our Consolidated Financial Statements included in our Annual Report on Form 10-K
+for the year ended December 31, 2011. The grant date fair value of stock awards, which are comprised of time-vested and performance-vested restricted stock units, includes the grant date fair value for the performance-vested restricted stock
+units calculated based on the target amount for the award period commencing in the year indicated. For 2011, the total aggregate grant date fair value of stock awards, including the time-vested restricted stock units and the performance-vested
+restricted stock units assuming the highest level of payout for performance against assigned targets would be as follows: $2.0 million for Mr. McCarvel, $0.7 million for Messrs. Hart and Lasher and $0.5 million for Mr. Crutchfield.
+(2) 
+Amounts for 2011 reflect cash awards earned under our annual incentive plan based on actual performance in 2011 which were paid in 2012.
+26 
+Table of Contents 
+(3) 
+All other compensation for 2011 represents the following: (i) Company matches to employee 401(k) contributions in the amount of $9,800 for
+Mr. Hart, Mr. Lasher and Mr. Crutchfield, (ii) a $10,000 in car allowance for Mr. McCarvel and (iii) $4,518 in incremental healthcare premiums paid by us on behalf of each named executive officer that is not offered to
+other non-executive employees. 
+(4) 
+Mr. McCarvel was appointed as our President and Chief Executive Officer effective March 1, 2010. During 2009, he served as our Executive Vice
+President and Chief Operating Officer. 
+(5) 
+Mr. Hart was appointed as our Executive Vice President of Administration and Corporate Development on June 15, 2009. Effective
+January 1, 2010, Mr. Hart was appointed as our Executive Vice President, Chief Legal and Administrative Officer. 
+(6) 
+Mr. Lasher was appointed as our Senior Vice President-Finance and Chief Financial Officer effective April 28, 2011. During 2010 and 2009, he
+served as our Corporate Controller and Chief Accounting Officer. 
+Grants of Plan-Based Awards Table 
+The following table provides information for each of our named executive officers regarding annual and long-term incentive award opportunities, including
+the range of potential payouts under our non-equity annual incentive plan. 
+Estimated Future 
+Payouts Under 
+Non-Equity Incentive 
+Plan Awards 
+Estimated Future 
+Payouts
+Under 
+Equity Incentive 
+Plan Awards 
+All Other 
+Stock 
+Awards: 
+Number 
+of 
+Shares of 
+Stock or 
+Units 
+(#) 
+All Other 
+Option 
+Awards: 
+Number 
+of 
+Securities 
+Underlying 
+Options 
+(#) 
+Exercise 
+or
+Base 
+Price of 
+Option 
+Awards 
+($) 
+Grant 
+Date 
+Value
+of 
+Stock and 
+Option 
+Awards 
+Name 
+Type of Award 
+Grant 
+Date 
+Target 
+($) 
+Maximum 
+($) 
+Threshold 
+(#) 
+Target 
+(#) 
+Maximum 
+(#) 
+John P. McCarvel 
+Annual Incentive Award 
+3/16/11 
+$84,000 
+$147,000 
+— 
+— 
+— 
+— 
+— 
+$— 
+$— 
+Restricted Stock Unit 
+6/28/11 
+— 
+— 
+13,056 
+26,112 
+52,224 
+26,112 
+— 
+— 
+1,349,990 
+Restricted Stock Unit 
+6/29/11 
+— 
+— 
+— 
+— 
+— 
+38,986 
+— 
+— 
+999,991 
+Daniel P. Hart 
+Annual Incentive Award 
+3/16/11 
+299,250 
+523,688 
+— 
+— 
+— 
+— 
+— 
+— 
+Restricted Stock Unit 
+6/28/11 
+— 
+— 
+4,594 
+9,188 
+18,376 
+9,188 
+— 
+— 
+475,020 
+Jeffrey J. Lasher 
+Annual Incentive Award 
+3/16/11 
+195,000 
+341,250 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+Restricted Stock Unit 
+4/29/11 
+— 
+— 
+— 
+— 
+— 
+30,000 
+— 
+— 
+603,300 
+Stock Options 
+4/29/11 
+— 
+— 
+— 
+— 
+— 
+— 
+30,000 
+$20.11 
+266,802 
+Restricted Stock Unit 
+6/28/11 
+— 
+— 
+4,594 
+9,188 
+18,376 
+9,188 
+— 
+— 
+475,020 
+Scott E. 
+Annual Incentive Plan 
+3/16/11 
+195,000 
+341,250 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+Crutchfield 
+Restricted Stock Units 
+6/28/11 
+$— 
+$— 
+3,385 
+6,770 
+13,540 
+6,770 
+— 
+$— 
+$350,009 
+Annual Incentive Awards . The amounts shown for annual incentive awards represent the
+target and maximum amounts of annual cash incentive compensation that, depending on performance results, might have been paid to each executive for 2011 performance based on achievement of specified target levels of sales growth, earnings per share,
+inventory turnover and net unrestricted cash. The target payments were based on achieving the target level of performance with ranges from zero to 175% of the executive’s annual incentive target. Actual amounts paid in 2012 related to 2011
+performance are reflected in the “Non-Equity Incentive Plan Compensation” column of the “Summary Compensation Table” set forth above. These awards are described in further detail under “Compensation Discussion and
+Analysis” above. 
+Restricted Stock Units (“RSUs”) . The amounts shown for RSUs represent the
+number of RSUs awarded to the executives in 2011 and the grant date fair value of the RSUs determined in accordance with FASB ASC 718, as follows. The amounts shown for RSUs granted on June 28, 2011 represent awards of restricted stock units to
+certain of our NEOs as part of a performance incentive plan. One-half of these RSUs vest in three equal annual installments beginning one year after the date of grant based on continued employment. The other half may be earned from 50% to 200% of
+the target number of RSUs based on the level of achievement of a two-year cumulative earnings per share performance goal, and vest in two equal annual installments, 50% on achievement of the performance goal and 50% one year later subject to
+continued employment. The amount shown for RSUs granted to Mr. McCarvel on June 29, 2011 represents a special recognition and retention award that vests in three equal annual installments beginning one year after the date of grant based on
+continued 
+27 
+Table of Contents 
+employment. The amount shown for RSUs granted to Mr. Lasher on April 29, 2011 represents a promotion award of RSUs which vests in three equal annual installments beginning one year
+after the date of grant based on continued employment. These RSU awards are described in further detail under “Compensation Discussion and Analysis” above. 
+Stock Options. The amount shown for stock options represents the number of shares and the grant date fair value determined in accordance with FASB ASC 718 of a promotion award of
+options to purchase shares of our common stock with an exercise price equal to the closing price of the common stock on the NASDAQ Global Select Market on the date of grant. Twenty-five percent of the options will vest on the first anniversary of
+the grant date and the remaining options will vest in 36 equal monthly installments after the first anniversary of the grant date based on continued employment. This option award is described in further detail under “Compensation Discussion and
+Analysis” above. 
+Employment Agreement with Mr. Hart. In May 2009, we entered into an employment
+agreement with Mr. Hart. The agreement provides that Mr. Hart will receive an annual base salary of $475,000, subject to annual adjustments. His salary may be reduced only if such reduction is a uniformly applied reduction affecting all
+senior executives and is no greater than 10% of Mr. Hart’s base pay in any case, may not be reduced by greater than $47,500 in total during his employment with us. Mr. Hart is also eligible for a bonus pursuant to our 2008 Cash
+Incentive Plan. Mr. Hart’s bonus target under the Bonus Plan was 60% of his base pay in 2011. He is also entitled to participate in all employee benefit plans and programs generally available to our executives, including our Senior
+Executive Plan. The agreement also contains provisions relating to benefits Mr. Hart may receive in connection with a change in control or a termination of his employment, as described in further detail under “Potential Payments on
+Terminations or Change in Control.” Mr. Hart’s Agreement requires him to maintain confidential information regarding us and to assign certain inventions and intellectual property to us. During his employment with us and for twelve
+months after the termination of his employment with us, Mr. Hart will be restricted from participating in certain competitive businesses and from soliciting our employees and customers. 
+Salary and Bonus in Proportion to Total Compensation. As noted in “Compensation Discussion and Analysis” above, we believe that a substantial portion of each named
+executive officer’s compensation should be in the form of performance-based annual incentive awards and equity awards. Base salary of the named executive officers is set at levels that the Compensation Committee believes are competitive with
+our peer companies, with the expectation that shortfalls in base pay, if any, will be recouped through performance bonuses. The Compensation Committee believes that our current program substantially aligns the compensation of our named executive
+officers with the compensation of executive officers of our peer companies, while also permitting the Compensation Committee to provide incentives to the named executive officers to pursue performance that increases stockholder value. Please see
+“Compensation Discussion and Analysis” for a description of the objectives of our compensation program and overall compensation philosophy. 
+28 
+Table of Contents 
+Outstanding Equity Awards at Fiscal Year End 
+The following table sets forth information regarding outstanding options and unvested restricted stock and restricted stock unit awards held by our named
+executive officers as of December 31, 2011. Market values for outstanding stock awards are presented as of the end of 2011 based on the closing price of our common stock on the NASDAQ Global Select Market on December 30, 2011 of $14.77.
+Option Awards 
+Stock Awards 
+Name 
+Number
+of 
+Securities 
+Underlying 
+Unexercised 
+Options 
+(#) 
+Exercisable 
+Number
+of 
+Securities 
+Underlying 
+Unexercised 
+Options 
+(#) 
+Unexercisable 
+Option 
+Exercise 
+Price 
+($) 
+Option 
+Expiration Date 
+Number of 
+Shares
+or 
+Units of Stock 
+That Have Not 
+Vested 
+(#) 
+Market Value 
+of Shares
+or 
+Units of Stock 
+That Have Not 
+Vested 
+($) 
+John P. McCarvel 
+47,683 
+80,086 
+32,771 ( 1 ) 
+— 
+$ 1.14 
+10.50 
+11/17/2018 
+2/7/2016 
+152,885 ( 2 ) 
+— 
+$2,258,111 
+— 
+Daniel P. Hart 
+8,333 
+75,000 ( 3 ) 
+3.99 
+6/15/2019 
+90,348 ( 4 ) 
+1,334,440 
+Jeffrey J. Lasher 
+— 
+15,000 
+30,000 (5 ) 
+15,000 (7 
+) 
+20.11 
+3.99 
+4/29/2021 
+6/15/2019 
+68,710 ( 6 ) 
+— 
+1,014,847 
+— 
+Scott E. Crutchfield 
+25,438 
+43,548 
+7,562 (8 ) 
+— 
+1.14 
+10.50 
+11/17/2018 
+2/7/2016 
+29,290 ( 9 ) 
+— 
+432,613 
+— 
+( 1 ) 
+Represents the unvested portion of stock options to purchase 143,000 shares of common stock, which were granted on November 17, 2008. This stock
+option award has a four year vesting period with 25% vesting on the first anniversary of the grant date and the remaining options vesting in 36 equal monthly installments thereafter, based on continued employment. 
+( 2 ) 
+Represents the unvested portion of three restricted stock grants: (i) one for 70,485 shares awarded on June 15, 2010 of which 35,243 shares
+vest ratably on each of the first four anniversaries of the grant date based on continued employment and the remaining 35,242 shares vest on a cliff basis on the fourth anniversary of the grant date based on continued employment and provided certain
+corporate performance metrics are achieved; (ii) for 52,224 units awarded on June 28, 2011 of which one-half of the restricted stock units vest in three equal annual installments on June 15, 2012, June 15, 2013 and
+June 15, 2014 based on continued employment and up to one half of the restricted stock units vest in two equal annual installments on the date in 2013 that the achievement of certain performance metrics is established and one year from that
+date, respectively, based on continued employment; and (iii) one for 38,986 units awarded on June 29, 2011 which will vest in equal installments on the next three grant date anniversaries, based on continued employment.
+( 3 ) 
+Represents the unvested portion of a stock option to purchase 200,000 shares of common stock, which was granted on June 15, 2009. This stock
+option vests over four years with 25% vesting on the first anniversary of the grant date and the remaining options vesting in 36 equal monthly installments thereafter, based on continued employment. 
+( 4 ) 
+Represents the unvested portion of three restricted stock grants: (i) for 150,000 shares awarded on June 15, 2009 which vest annually in
+equal installments on the next three grant date anniversaries, based on continued employment; (ii) for 25,110 shares awarded on June 15, 2010 of which half vest ratably on each of the first four anniversaries of the grant date based on
+continued employment and the remaining half vest on a cliff basis on the fourth anniversary of the grant date based on continued employment and provided certain corporate performance metrics are achieved; (iii) for 18,376 units awarded on
+June 28, 2011 of which one-half of the restricted stock units vest in three equal installments on June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and up to one-half of the restricted stock units
+vest in two equal annual installments on the date in 2013 that the achievement of certain performance metrics is established and one year from that date, respectively, based on continued employment. 
+( 5 ) 
+Represents the unvested portion of stock options to purchase 30,000 shares of common stock, which were granted on April 29, 2011. This stock
+option award has a four year vesting period with 25% vesting on the 
+29 
+Table of Contents 
+first anniversary of the grant date and the remaining options vesting in 36 equal monthly installments thereafter, based on continued employment. 
+( 6 ) 
+Represents the unvested portion of four restricted stock grants: (i) for 40,000 shares granted on June 15, 2009 which vest annually in equal
+installments on the next three grant date anniversaries, based on continued employment; (ii) for 8,000 shares awarded on August 2, 2010 of which half vest ratably on June 15, 2011, June 15, 2012, June 15, 2013 and
+June 15, 2014 based on continued employment and the remaining half vest on a cliff basis on June 15, 2014, based on continued employment and provided certain corporate performance metrics are achieved; (iii) for 30,000 shares granted
+on April 29, 2011 which vest annually in equal installments on the next three grant date anniversaries, based on continued employment, and (iv) for 18,376 units awarded on June 28, 2011 of which one-half of the restricted stock units
+vest in three equal installments on June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and up to one-half of the restricted stock units vest in two equal annual installments on the date in 2013 that the
+achievement of certain performance metrics is established and one year from that date, respectively, based on continued employment. 
+( 7 ) 
+Represents the
+unvested portion of stock options to purchase 40,000 shares of common stock, which were granted on June 15, 2009. This stock option award has a four year vesting period with 25% vesting on the first anniversary of the grant date and the
+remaining options vesting in 36 equal monthly installments thereafter, based on continued employment. 
+( 8 ) 
+Represents the unvested portion of stock options to purchase 33,000 shares of common stock, which were granted on November 17, 2008. This stock
+option award has a four year vesting period with 25% vesting on the first anniversary of the grant date and the remaining options vesting in 36 equal monthly installments thereafter, based on continued employment. 
+( 9 ) 
+Represents the unvested portion of two restricted stock grants: (i) for 18,000 shares awarded on August 2, 2010 of which half vest ratably on
+June 15, 2011, June 15, 2012, June 15, 2013 and June 15, 2014 based on continued employment and the remaining half vest on a cliff basis on June 15, 2014, based on continued employment and provided certain
+corporate performance metrics are achieved; and (ii) for 13,540 units awarded on June 28, 2011 of which one-half of the restricted stock units vest in three equal installments on June 15, 2012, June 15, 2013 and
+June 15, 2014 based on continued employment and up to one-half of the restricted stock units vest in two equal annual installments on the date in 2013 that the achievement of certain performance metrics is established and one year from that
+date, respectively, based on continued employment. 
+Options Exercised and Stock Vested 
+The following table sets forth information for each of our named executive officers regarding stock options exercised and stock awards vested during
+2011. 
+Option Awards 
+Stock Awards 
+Name 
+Number of 
+Shares Acquired 
+on Exercise 
+(#) 
+Value 
+Realized on 
+Exercise 
+($) (1) 
+Number of 
+Shares Acquired 
+on Vesting 
+(#) 
+Value 
+Realized on 
+Vesting 
+($) (1) 
+John P. McCarvel 
+40,000 
+$501,182 
+48,810 
+$841,282 
+Daniel P. Hart 
+41,667 
+787,807 
+53,138 
+1,201,982 
+Jeffrey J. Lasher 
+10,000 
+123,100 
+14,333 
+324,212 
+Scott E. Crutchfield 
+50,200 
+$543,154 
+8,917 
+$157,900 
+(1) 
+For option awards, the value realized is the difference between the fair market value of our common stock at the time of exercise and the exercise
+price. For stock awards, the value realized is based on the closing price of our common stock on the vesting date. 
+30 
+Table of Contents 
+Nonqualified Deferred Compensation 
+Under our Senior Executive Plan, participants have the option to defer all or a part of their cash compensation in accordance with the terms and conditions established by the Compensation Committee. The
+deferred amount will vest ratably on a quarterly basis over a three-year period, with a pro rata amount vesting on each calendar quarter. Any unvested balance will vest immediately upon the death or disability of the participant or upon a Change in
+Control, as defined in the plan. None of the named executive officers have deferred any compensation since 2008. The table below summarizes the 2011 accrued earnings and balances at December 31, 2011 under our Senior Executive Plan for each of
+the named executive officers. 
+Name 
+Executive 
+Contributions 
+in Last Fiscal 
+Year 
+$ 
+Crocs, Inc. 
+Contributions 
+in Last Fiscal 
+Year 
+$ 
+Aggregate 
+Earnings in 
+Last Fiscal 
+Year (1) 
+$ 
+Aggregate 
+Withdrawals 
+/Distributions 
+$
+Aggregate 
+Balance at 
+Last Fiscal 
+Year End 
+$ 
+John P. McCarvel 
+$ 
+— 
+$ 
+— 
+$ 
+25,428 
+$ 
+— 
+$ 
+734,195 
+Daniel P. Hart 
+— 
+— 
+— 
+— 
+— 
+Jeffrey J. Lasher 
+— 
+— 
+— 
+— 
+— 
+Scott E. Crutchfield 
+— 
+— 
+— 
+— 
+— 
+(1) 
+Each participant in the Senior Executive Plan may choose, at his or her discretion, a portfolio of investments in which their contributions may be
+hypothetically invested. We are not obligated to invest the participant’s contributions into these accounts; however, upon the participant’s withdrawal, we are obligated to pay the amount, inclusive of earnings, interest, and capital
+gains, that the participant’s contributions would have earned had we actually invested the money as the participant directed. The aggregate earnings on each individual’s contribution varies widely depending on the portfolio of investments
+the participant chooses. We received investment direction from Mr. McCarvel and the aggregate earnings from those hypothetical investments are reflected in the table above. 
+Potential Payments on Terminations or Change in Control 
+Mr. Hart’s employment agreement provides certain benefits in the event of a change of control or certain terminations of employment. No other named executive officer currently has an employment
+agreement. Mr. Hart’s employment agreement provides that in the event of a change in control, all unvested stock options and time-based unvested stock awards then held by Mr. Hart that are scheduled to vest over the 24 months
+following the change in control will immediately vest upon the effective date of the change in control. The potential incremental value of such acceleration, assuming the change in control was effective as of December 30, 2011 and that the
+price of our common stock was the closing price of $14.77 on that date, would have been $1.7 million. The agreement also provides that if Mr. Hart is terminated by us involuntarily without cause, or if he resigns for good reason, he will
+receive: (i) a lump sum payment equal to one year of his base pay as of the termination date; (ii) a lump sum payment equal to 80% of his base pay in effect as of the termination date, pro-rated to equal the proportion of the year that he
+was employed by us; (iii) a lump sum payment equal to 80% of his base pay as of the termination date; and (iv) immediate vesting of any unvested stock options or time-based unvested stock awards then held by him that would have been vested
+had he remained employed for 24 months after the termination date. The potential aggregate amount of such payments, assuming such termination occurred on December 31, 2011 and including the potential incremental value of the equity acceleration
+as described above, would have been $3.0 million. These amounts are estimates of the incremental amounts that would be payable as of December 31, 2011 under Mr. Hart’s agreement in the foregoing circumstances. The actual amounts that
+would be payable in similar circumstances in the future can only be determined at the time of a change in control or his termination of employment under certain circumstances. The agreement also provides that any stock options granted to
+Mr. Hart during his employment will remain exercisable for ten years after the date of grant, including if Mr. Hart ceases to be employed by us for any reason other than termination for cause. 
+31 
+Table of Contents 
+Under Mr. Hart’s employment agreement, “cause,” “change of control” and
+“good reason” are defined as follows: 
+“Cause” is defined by the agreement to mean: (i) the
+executive’s conviction, or guilty or no contest plea, to any felony; (ii) any act of fraud by the executive related to or connected with the executive’s employment by the Company; (iii) the executive’s material breach of his
+fiduciary duty to the Company; (iv) the executive’s gross negligence or gross misconduct in the performance of duties reasonably assigned to the executive which causes material harm to the Company; (v) any willful and material
+violation by the executive of the Company’s codes of conduct or other rules or policies of the Company; (vi) any entry of any court order or other ruling that prevents the executive from performing his material duties and
+responsibilities hereunder; or (vii) any willful and material breach of the agreement by the executive. 
+“Change of
+control” is generally defined by the agreement to mean any one of the following: (i) incumbent directors (including those nominees subsequently nominated or elected by incumbent directors) cease to constitute a majority of the members of
+the Board; (ii) any person becomes the beneficial owner of 35% or more of our common stock or voting securities, with certain exceptions; (iii) consummation of a merger unless (a) after the merger the beneficial owners of our common
+stock and voting securities immediately prior to the trans action retain more than 50% of such common stock and voting securities of the entity resulting from the merger, (b) holders of any class or series of voting securities immediately prior
+to the merger have the right to receive substantially the same per share consideration in exchange for their voting securities, and (c) no person immediately after the merger beneficially owns 35% or more of the voting power of the entity
+resulting from the merger; (iii) a sale or other disposition of all or substantially all of the assets of the Company (in one transaction or a series of transactions); or (iv) stockholder approval of the liquidation or dissolution the
+Company, except that a change of control will not be deemed to occur unless it would be deemed to constitute a change in ownership or effective control, or a change in the ownership of a substantial portion of the assets, of a business under
+Section 409A of the Code. 
+“Good reason” is defined by the agreement to mean any of the following conditions
+arising during the executive’s term of employment without the consent of the executive: (i) a material diminution in the executive’s responsibilities, authority, position, or duties; (ii) a reduction in the executive’s base
+salary (except as provided for in the agreement); (iii) a reduction in the executive’s incentive or equity compensation opportunity such that it is materially less favorable than those provided generally to other senior executive officers;
+(iv) the Company’s material failure to honor its incentive compensation plans, as then in effect; (v) assignment of duties or responsibilities materially inconsistent with those described in the agreement; (vi) removal from the
+position of Executive Vice President of Administration and Corporate Development of the Company or its successor; (vii) any change in the executive’s reporting responsibility being solely to the Chief Executive Officer;
+(viii) relocation of the executive’s office or the Company 50 miles or more from the place of relocation agreed between the executive and Chief Executive Officer; or (x) any other action or inaction that constitutes a material breach
+by the Company of the agreement. 
+32 
+Table of Contents 
+REPORT OF THE AUDIT COMMITTEE 
+The Audit Committee has reviewed and discussed the audited financial statements for the fiscal year ended December 31, 2011 with our management and
+Deloitte & Touche LLP, our independent registered public accounting firm. Management is responsible for the preparation, presentation and integrity of the financial statements, accounting and financial reporting principles and internal
+control over financial reporting. Deloitte & Touche LLP is responsible for performing an independent audit of the financial statements in accordance with generally accepted auditing standards and for expressing opinions on the
+conformity of the financial statements with accounting principles generally accepted in the United States. 
+The Audit Committee has discussed
+with Deloitte & Touche LLP the matters required to be discussed by Statement on Auditing Standards No. 61, as amended, Communication With Audit Committees , and PCAOB AU Section 380, Communications with Audit
+Committees , and has received the written disclosures and the letter from Deloitte & Touche LLP required by applicable requirements of the Public Company Accounting Oversight Board regarding the independent auditor’s
+communications with the Audit Committee concerning independence. The Audit Committee has also discussed with Deloitte & Touche LLP their independence. 
+Based on its reviews and discussions referred to above, the Audit Committee recommended to the Board that the audited financial statements be included in our Annual Report on Form 10-K for the year
+ended December 31, 2011 for filing with the SEC. 
+The Audit Committee: 
+Thomas J. Smach (Chairperson) 
+Ronald L. Frasch 
+W. Stephen Cannon 
+33 
+Table of Contents 
+INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+The following table sets forth the aggregate fees for professional services provided during 2011 and 2010 by Deloitte & Touche LLP, our
+independent registered public accounting firm and its affiliates. The Audit Committee is required to pre-approve all non-audit services provided by Deloitte & Touche LLP. All of the fees paid to Deloitte & Touche LLP and
+disclosed in the following table were pre-approved by the Audit Committee. 
+2011 
+2010 
+Audit fees (1) 
+$ 
+1,882,800 
+$ 
+1,654,000 
+Audit-related fees 
+— 
+— 
+Tax fees (2) 
+644,463 
+280,502 
+All other fees 
+— 
+— 
+Total fees 
+$ 
+2,527,263 
+$ 
+1,934,502 
+(1) 
+Audit fees relate to professional services rendered in connection with the audit of our annual financial statements and internal controls over financial reporting, both
+of which are included in our Annual Report on Form 10-K and services attendant to, or required by, statute or regulation, such as: (i) comfort letters, consents and other audit services related to SEC and other regulatory filings;
+(ii) accounting consultation related to the audit; and (iii) statutory audit requirements in foreign countries. 
+(2) 
+Tax fees include professional services rendered in connection with tax compliance, tax advice, tax consulting and tax planning. 
+34 
+Table of Contents 
+PROPOSAL 2—RATIFICATION OF THE APPOINTMENT OF INDEPENDENT REGISTERED 
+PUBLIC ACCOUNTING FIRM 
+The Audit Committee has appointed Deloitte & Touche LLP as the independent registered public accounting firm for the fiscal year ending December 31, 2012. Deloitte &
+Touche LLP has served as our independent public accounting firm since 2005. We are not required to submit this appointment to the stockholders for approval, but the Board believes it is desirable as a matter of policy. We expect that a
+representative of Deloitte & Touche LLP will attend the Annual Meeting and will have the opportunity to make any statements if he or she so desires and to respond to appropriate stockholder questions. 
+If the stockholders do not ratify this appointment, the Audit Committee will investigate the reasons for the rejection and consider other independent
+registered public accounting firms. Even if the appointment is ratified, the Audit Committee may, in its discretion, appoint a different independent registered public accounting firm. 
+THE BOARD RECOMMENDS A VOTE “FOR” THE RATIFICATION OF DELOITTE & TOUCHE LLP AS THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR FISCAL YEAR 2012.
+35 
+Table of Contents 
+PROPOSAL 3—APPROVAL OF THE AMENDMENT AND RESTATEMENT OF THE 2008 CASH INCENTIVE PLAN 
+Introduction 
+On March 14, 2012, the Board, upon recommendation by the Compensation Committee, approved and adopted an amendment and restatement of the 2008 Cash
+Incentive Plan (the existing plan is referred to as the “Original Plan” and the plan as proposed to be amended is referred to as the “Amended Plan”), effective June 4, 2012 and, subject to stockholder approval, to govern the
+award and payment of cash incentive awards to certain executive officers of the Company. The Board directed that the Amended Plan be submitted to the stockholders for approval so that payments under the Amended Plan can qualify for deductibility for
+federal income tax purposes. 
+The purpose of the Amended Plan is to: 
+• 
+advance our interests by promoting our pay for performance philosophy; 
+• 
+attract and retain key employees; and 
+• 
+stimulate the efforts of such employees toward the continued success and growth of our business. 
+In addition, the Amended Plan is intended to permit the payment of cash incentive awards that may qualify as “performance-based compensation”
+within the meaning of Section 162(m) of the Internal Revenue Code of 1986, as amended (“Section 162(m)”); however, there can be no guarantee that amounts payable under the Amended Plan will be treated as qualified
+performance-based compensation under Section 162(m). 
+The Board believes that it is in the best interests of the Company and its
+stockholders for the Company to have a stockholder-approved plan under which cash incentive awards granted to its executives could be designed in a manner intended to qualify as “performance-based compensation” within the meaning of
+Section 162(m). Accordingly, the Amended Plan is being submitted for approval by stockholders. In general, under Section 162(m), in order for the Company to be able to deduct compensation in excess of $1,000,000 paid in any one year to our
+chief executive officer or any of our three other most highly compensated executive officers (other than our chief financial officer), such compensation must qualify as “performance-based.” One of the requirements of
+“performance-based” compensation for purposes of Section 162(m) is that the material terms of the performance goals under which compensation may be paid be disclosed to and approved by the Company’s stockholders at least once
+every five years. Stockholders last approved the material terms of the Original Plan at the 2007 annual meeting of stockholders. For purposes of Section 162(m), the material terms include (i) the individuals eligible to receive
+compensation; (ii) a description of the business criteria on which the performance goal is based; and (iii) the maximum amount of compensation that can be paid to an individual under the performance goal. Each of these aspects is discussed
+below, and stockholder approval of this Proposal 3 is intended to constitute reapproval of each of these aspects of the Amended Plan for purposes of the stockholder approval requirements of Section 162(m). 
+Key Changes from the Original Plan 
+If
+approved, the Amended Plan would make the following changes to the Original Plan, as described in more detail under “Description of the Amended Plan” below: (i) include adjustments that can be made to established performance goals in
+a manner that is intended to satisfy the requirements of Section 162(m); (ii) subject certain awards under the Amended Plan to the Company’s Executive Compensation Recovery Policy; and (iii) make certain other administrative
+changes. 
+36 
+Table of Contents 
+Description of the Amended Plan 
+The significant features of the Amended Plan are described below. A copy of the Amended Plan is attached to this proxy statement as Appendix A, and this discussion is qualified in its entirety by
+reference to the full text of the Amended Plan. 
+Administration 
+Our Compensation Committee, all of whose members are outside directors, will administer the Amended Plan. The compensation committee will have the authority to grant awards upon such terms, not
+inconsistent with the terms of the Amended Plan, as it considers appropriate. In addition, the compensation committee will have complete authority to interpret all provisions of the Amended Plan, to adopt, amend, and rescind rules and
+regulations pertaining to the administration of the Amended Plan, and to make all other determinations necessary or advisable for the administration of the Amended Plan, and to reduce or eliminate, in its discretion, the amount of any award
+otherwise payable under the Amended Plan. 
+Eligibility 
+All of our employees, who currently number approximately 4,100, will be eligible to participate under the Amended Plan. Our Compensation Committee determines which employees will be participants under the
+Amended Plan. However, the criteria for participation may change in subsequent years. Other annual or short-term bonus arrangements will be made available to employees who are not considered “covered employees” for purposes of
+Section 162(m). 
+Performance Measures 
+Participants will receive awards under the Amended Plan whose payout will be contingent upon the degree of attainment of specified performance measures over the applicable performance period. The
+performance measures are set by our compensation committee at the start of each performance period and are based on one or a combination of two or more of the following performance criteria: net sales; net earnings; earnings before income taxes;
+earnings before interest and taxes; earnings before interest, taxes, depreciation and amortization; earnings per share (basic or diluted); profitability as measured by return ratios (including return on assets, return on equity, return on investment
+and return on net sales) or by the degree to which any of the foregoing earnings measures exceed a percentage of net sales; cash flow; market share; margins (including one or more of gross, operating and net earnings margins); stock price; total
+stockholder return; asset quality; non-performing assets; revenue growth; operating income; pre- or after-tax income; cash flow per share; operating assets; improvement in or attainment of expense levels or cost savings; economic value added; and
+improvement in or attainment of working capital levels. 
+Any performance measure utilized may be expressed in absolute amounts, on a per share
+basis, as a change from preceding performance periods, as a percentage of another criterion, or as a comparison to the performance of specified companies or other external measures, and may relate to corporate, group, unit, division, affiliate or
+individual performance. 
+The Compensation Committee may provide in any award that any evaluation of performance may include or exclude any of
+the following events that occurs during a performance period: asset write-downs; litigation or claim judgments or settlements; the effect of changes in tax laws, accounting principles, or other laws or provisions affecting reported results; any
+reorganization and restructuring programs; certain extraordinary nonrecurring items; acquisitions or divestitures; foreign exchange gains and losses; and gains and losses on asset sales. To the extent such inclusions or exclusions affect awards to
+covered employees, they will be prescribed in a form that satisfies the requirements for “performance-based compensation” within the meaning of Section 162(m). 
+37 
+Table of Contents 
+Performance Periods 
+A performance period is the measure of time specified by our compensation committee over which the degree of attainment of the specified performance measures will be measured. 
+Payment of Awards; Maximum Amount of Awards 
+All awards under the Amended Plan for a performance period will be paid in cash following the end of such performance period and our Compensation Committee’s certification of the degree to which
+applicable performance measures were attained. The maximum individual award payment that can be made under the Amended Plan may not exceed $8 million for an annual performance period or, for performance periods longer or shorter in duration, an
+amount equal to $2.0 million multiplied by the number of quarters in the performance period. 
+Recovery of Executive Compensation
+Policy. 
+With respect to participants who are subject to the Company’s Executive Compensation Recovery Policy, all amounts earned
+under the Amended Plan are subject to such policy. 
+Termination of Employment 
+Except as otherwise provided below, no award for a performance period will be paid to a participant who is not actively employed by us at the end of the performance period. If a participant’s
+employment ends during a performance period, our compensation committee has the discretion to approve payment to the participant, or his or her beneficiaries, of a pro rata portion of the award payment the participant would have received but for the
+fact that the participant’s employment ended. 
+Amendment and Termination 
+Our Compensation Committee or our Board may amend, suspend or terminate the Amended Plan from time to time. An amendment will be subject to the approval of our stockholders only if such approval is
+necessary to maintain the Amended Plan in compliance with Section 162(m) or other applicable laws and regulations. 
+Federal
+Income Tax Consequences 
+The following is a brief summary of the U.S. federal income tax consequences of the Amended Plan generally
+applicable to us and to participants in the Amended Plan who are subject to U.S. federal taxes. The summary is based on the U.S. Internal Revenue Code of 1986, as amended, applicable Treasury Regulations and administrative and judicial
+interpretations thereof, each as in effect on the date of this proxy statement and is, therefore, subject to future changes in the law, possibly with retroactive effect. The summary is general in nature and does not purport to be legal or tax
+advice. Furthermore, the summary does not address issues relating to any U.S. gift or estate tax consequences or the consequences of any state, local or foreign tax laws. 
+A participant in the Amended Plan will be taxed at ordinary income rates on an award in the year in which a cash payment under the award, if any, is received, unless such cash is subject to deferral under
+a Company plan or a substantial risk of forfeiture. If a participant elects to defer a portion of the bonus, the participant may be entitled to defer the recognition of income. Generally, and subject to Section 162(m), the Company will receive
+a U.S. federal income tax deduction on the amount of income recognized by the participants at the same time such income is recognized by participants. Please note that the rules and regulations promulgated under Section 162(m) are complicated
+and subject to change from time to time, sometimes with retroactive effect. As such, and as noted above, there can be no guarantee that amounts payable under the Amended Plan will be treated as qualified performance-based compensation under
+Section 162(m) and/or deductible by the Company. 
+38 
+Table of Contents 
+We intend that awards granted under the Amended Plan comply with, or otherwise be exempt from,
+Section 409A of the Internal Revenue Code, but make no representation or warranty to that effect. 
+We are authorized to deduct or
+withhold from any payment due under the Amended Plan, or require a participant to remit to us, the amount of any withholding taxes due in respect of the payment and to take such other action as may be necessary to satisfy all obligations for the
+payment of applicable withholding taxes. We are not required to settle an award under the Amended Plan until all tax withholding obligations are satisfied. 
+New Plan Benefits 
+The specific individuals who will be granted awards under the Amended
+Plan and the type and amount of any such awards will be determined by the Compensation Committee, subject to limits on the maximum amounts that may be awarded to any individual, as described above. Accordingly, future awards to be received by or
+allocated to particular individuals under the Amended Plan are not presently determinable. 
+The approval of the Amended Plan requires the
+affirmative vote of the majority of shares present in person or represented by proxy at the meeting and entitled to vote on the proposal. 
+THE BOARD RECOMMENDS A VOTE “FOR” THE APPROVAL OF THE AMENDMENT AND RESTATEMENT OF THE 2008 CASH INCENTIVE PLAN 
+Equity Compensation Plan Information 
+As shown in the table below, we reserved 3.3 million shares of common stock for future issuance on exercise of outstanding options under equity
+compensation plans as of December 31, 2011. 
+Plan Category 
+Number
+of 
+Securities 
+to be Issued 
+on Exercise of 
+Outstanding Options 
+Weighted Average 
+Exercise Price of 
+Outstanding 
+Options 
+Number of Securities 
+Remaining Available 
+for Future 
+Issuance Under 
+Plans,
+Excluding 
+Securities Available 
+in First Column 
+Equity compensation plans approved by stockholders (1) 
+3,331,031 
+$ 
+11.91 
+6,959,120 
+Equity compensation plans not approved by stockholders 
+— 
+— 
+— 
+Total 
+3,331,031 
+$ 
+11.91 
+6,959,120 
+(1) 
+On July 9, 2007, at the annual stockholders’ meeting, our stockholders approved the 2007 Equity Incentive Plan (the “2007 Plan”),
+which previously had been approved by our board of directors and which became effective as of July 19, 2007. On June 28, 2011, our stockholders approved an amendment to the 2007 Plan to increase the number of shares of our common stock
+available for issuance from 9.0 million shares to 15.3 million shares, subject to adjustment for future stock splits, stock dividends and similar changes in our capitalization. On April 27, 2005, our Board of Directors adopted the
+2005 Equity Incentive Plan (the “2005 Plan”). On January 10, 2006, our Board of Directors amended the 2005 Plan to increase the number of shares of our common stock available for issuance under the 2005 Plan from 11.7 million
+shares to 14.0 million shares. Following the adoption of the 2007 Plan, no future grants were made under the 2005 Plan. 
+39 
+Table of Contents 
+PROPOSAL 4— ADVISORY VOTE TO APPROVE THE COMPENSATION OF OUR NAMED EXECUTIVE OFFICERS 
+The Dodd-Frank Wall Street Reform and Consumer
+Protection Act of 2010, or the Dodd-Frank Act, gives stockholders an opportunity to cast an advisory vote to approve compensation of our named executive officers as disclosed in this proxy statement. This proposal, commonly known as a “Say on
+Pay” proposal, gives stockholders the opportunity to approve or reject our executive pay program through the following resolution: 
+“RESOLVED, that the stockholders approve, on an advisory basis, the compensation of our named executive officers, as disclosed in the Compensation Discussion and Analysis, the compensation tables and
+any other related disclosure in this proxy statement.” 
+As discussed in the “Compensation Discussion and Analysis,” the primary
+objective of our executive compensation program is to create long-term value for our stockholders by attracting and retaining talented executives, holding our executives accountable to stockholders, motivating our executives to achieve superior
+financial and business objectives and aligning the interests of our executives with those of our stockholders. We believe our executive compensation strikes the appropriate balance between utilizing responsible, measured pay practices and
+effectively incentivizing our named executive officers to dedicate themselves fully to value creation for our stockholders. Please see “Compensation Discussion and Analysis” section above for an explanation of our executive compensation.
+This “Say on Pay” proposal allows our stockholders to express their view regarding the decisions of the Compensation Committee on
+the 2011 compensation of our named executive officers. Your advisory vote will serve as a tool to guide the Board and the Compensation Committee in continuing to improve the alignment of our executive compensation programs with the objective of
+creating long-term value for our stockholders. 
+THE BOARD RECOMMENDS A VOTE “FOR” THE COMPENSATION OF OUR NAMED EXECUTIVES.
+40 
+Table of Contents 
+OTHER MATTERS 
+We do not intend to bring before the Annual Meeting any matters other than the proposals specifically described above, and we know of no matters other
+than those to come before the Annual Meeting. If any other matters properly come before the Annual Meeting, it is the intention of the persons named in the accompanying proxy to vote such proxy in accordance with the recommendation of our management
+on such matters, including any matters dealing with the conduct of the Annual Meeting. 
+STOCKHOLDER PROPOSALS AND NOMINATIONS FOR 2013
+ANNUAL MEETING 
+Any proposal of a stockholder intended to be included in our proxy statement for the 2013 annual meeting of stockholders
+pursuant to SEC Rule 14a-8, must be received by us no later than December 11, 2012, unless the date of our 2013 Annual Meeting is more than 30 days before or after June 4, 2013, in which case the proposal must be received a
+reasonable time before we begin to print and mail our proxy materials. All proposals should be addressed to the Corporate Secretary, Crocs, Inc., 7477 East Dry Creek Parkway, Niwot, Colorado 80503. 
+In order for a stockholder to nominate a candidate for director for election or to bring other business before the 2013 annual meeting, we must receive
+timely notice of the nomination or business in writing by the close of business not later than March 6, 2013 and not earlier than February 4, 2013. However, in the event that the 2013 annual meeting is called for a date that is not within
+30 days before or 60 days after June 4, 2013, notice by the stockholder to be timely must be delivered not earlier than the close of business on the 120th day prior to such annual meeting and not later than the close of business
+on the later of the 90th day prior to such annual meeting or the 10th day following the date on which public announcement of the date of the 2013 annual meeting is made. 
+41 
+Table of Contents 
+APPENDIX A 
+CROCS, INC. 
+2008 CASH INCENTIVE PLAN 
+(As Amended and Restated Effective June 4, 2012) 
+1. Purpose. The purpose of the Crocs, Inc. 2008 Cash Incentive Plan (the “ Plan ”) is to advance the
+interests of Crocs, Inc. (“ Crocs ”) and its stockholders by promoting Crocs’s pay for performance philosophy, attracting and retaining key employees of Crocs and its subsidiaries, and stimulating the efforts of such
+employees toward the continued success and growth of Crocs’s business. Amounts paid pursuant to the Plan are intended to qualify as “performance-based compensation” within the meaning of Section 162(m) of the Internal
+Revenue Code of 1986, as amended. 
+2. Definitions. When the following terms are used with capital letters in the
+Plan, they will have the meanings indicated: 
+(a) “ Award ” means an incentive award which,
+subject to the terms and conditions prescribed by the Committee, entitles a Participant to receive a cash payment from the Company in accordance with Section 3. 
+(b) “ Board ” means the Board of Directors of Crocs. 
+(c) “ Code ” means the Internal Revenue Code of 1986, as amended. 
+(d) “ Committee ” means the Compensation Committee of the Board or such other committee as may be designated by the Board to administer the Plan. 
+(e) “ Company ” means Crocs and its subsidiaries. 
+(f) “ Covered Officer ” means any Participant whose compensation, in the Performance Period for which an
+the incentive under the Plan is calculated, is subject to the compensation expense deduction limitations set forth in Section 162(m) of the Code. 
+(g) “ Eligible Employee ” means any employee of the Company. 
+(h) “ Participant ” means an Eligible Employee designated by the Committee to participate in the Plan as provided in Section 3.1. Designation by the Committee as
+a Participant for a specific Performance Period or series of Performance Periods does not confer on the Participant the right to participate in the Plan for any other Performance Periods. 
+(i) “ Performance-Based Compensation ” means an Award that is intended to constitute
+“performance-based compensation” within the meaning of Section 162(m)(4)(C) of the Code and the regulations promulgated thereunder. 
+(j) “ Performance Measures ” means one or a combination of two or more of the following performance criteria: net sales; net earnings; earnings before income taxes;
+earnings before interest and taxes; earnings before interest, taxes, depreciation and amortization; earnings per share (basic or diluted); profitability as measured by return ratios (including return on assets, return on equity, return on investment
+and return on net sales) or by the degree to which any of the foregoing earnings measures exceed a percentage of net sales; cash flow; market share; margins (including one or more of gross, operating and net earnings margins); stock price; total
+stockholder return; asset quality; non-performing assets; revenue growth; operating income; pre- or after-tax income; cash flow per share; operating assets; 
+A-1
+Table of Contents 
+improvement in or attainment of expense levels or cost savings; economic value added; and improvement in or attainment of working capital levels. In addition, for any Award to a Participant who
+is not, and is not likely to be as of the end of the Company’s relevant tax year, a Covered Officer or that is not intended to constitute Performance-Based Compensation, Performance Measures may include, alone or in combination with any of the
+foregoing Performance Measures, any other measure of performance as determined by the Committee. Any Performance Measure utilized may be expressed in absolute amounts, on a per share basis, as a change from preceding Performance Periods, as a
+comparison to the performance of specified companies or other external measures, and may relate to one or any combination of corporate (including such direct and indirect subsidiaries of the Company as the Committee may determine or on such
+consolidated basis as the Committee may determine), group, unit, division, affiliate or individual performance. 
+(k) “ Performance Period ” means the period of time specified by the Committee over which the degree of
+attainment of specified Performance Measures will be measured. 
+3. Awards. 
+3.1 Allocation of Awards. Prior to the earlier of (i) 90 days following the commencement of a
+Performance Period or (ii) the passage of 25 percent of the duration of such Performance Period, the Committee will designate such Eligible Employees as it deems appropriate to participate in the Plan for such Performance Period. The
+Committee’s designation of an Eligible Employee as entitled to participate in the Plan may be for a single Performance Period, or for a fixed or indefinite series of future Performance Periods, in its discretion. A designation for more
+than one Performance Period shall be subject to the Participant’s continued employment by the Company, and may be rescinded at any time as to future Performance Periods by the Committee. Awards may be granted to a Participant in such
+amounts and on such terms as may be determined by the Committee. At the time an Award is made, the Committee will specify the terms and conditions that will govern the Award, which will include that the Award will be earned only upon, and to
+the extent that, the applicable Performance measures as described in Section 3.2 are satisfied over the course of the applicable Performance Period. Different terms and conditions may be established by the Committee for different Awards
+and for different Participants. 
+3.2 Performance Measures. The payment of an Award will be
+contingent upon the degree of attainment of such Performance Measures over the applicable Performance Period as are specified by the Committee. Performance Measures for any Performance Period will be established by the Committee prior to the
+earlier of (i) 90 days following the commencement of the Performance Period or (ii) the passage of 25 percent of the duration of the Performance Period. 
+3.3 Adjustments to Performance Measures. The Committee may provide in any Award that any evaluation of performance may include or exclude any of the following events that
+occurs during a Performance Period: (i) asset write-downs, (ii) litigation or claim judgments or settlements, (iii) the effect of changes in tax laws, accounting principles, or other laws or provisions affecting reported results,
+(iv) any reorganization and restructuring programs, (v) extraordinary nonrecurring items as described in Accounting Principles Board Opinion No. 30 and/or in Management’s Discussion and Analysis of Financial Condition and Results
+of Operations appearing in the Company’s annual report to stockholders for the applicable year, (vi) acquisitions or divestitures, (vii) foreign exchange gains and losses, and (viii) gains and losses on asset sales. To the extent
+such inclusions or exclusions affect Awards to Covered Employees, they shall be prescribed in a form that satisfies the requirements for “performance-based compensation” within the meaning of Section 162(m), or any successor provision
+thereto. 
+The Committee also may, at any time during or after a Performance Period, in its sole and absolute discretion,
+modify the Performance Measures applicable to a Performance Period in addition to any adjustments specified for the Performance Period in accordance with the immediately preceding paragraph if it determines that as a result of changed circumstances,
+such modification is required to reflect the original intent of such 
+A-2
+Table of Contents 
+Performance Measures. However, no such modification may be made to the extent it would increase the amount of compensation that would otherwise be payable to any Participant who is a Covered
+Officer or is likely to be a Covered Officer as of the end of the Company’s relevant tax year. 
+3.4 Maximum
+Amount of Awards. No Participant who is a Covered Officer shall be entitled to receive an Award payment for any Performance Period that exceeds $8,000,000 for an annual Performance Period or, if the Performance Period is longer or
+shorter in duration than one year, an amount equal to the product of (i) $2,000,000, multiplied by (ii) the number of quarters in the Performance Period. 
+3.5 Authority to Reduce or Eliminate Amount of Award. The Committee is authorized at any time during or after a Performance Period, in its sole and absolute discretion, to
+reduce or eliminate the amount of an Award otherwise payable to any Participant for any reason. No reduction in the amount of an Award payable to any Participant shall increase the amount of an Award payable to any other Participant.
+3.6 Payment of Awards. Following the completion of each Performance Period, the Committee shall
+certify in writing the degree to which the Performance Measures were attained and the Awards payable to Participants. Each Participant shall receive payment in cash of the Award as soon as practicable following the Committee’s
+determination and certification made pursuant to this Section 3.6, but in no event later than March 15 of the calendar year immediately following the last day of the Performance Period to which such payment relates. 
+4. Administration. 
+4.1 Authority of Committee. The Committee shall administer the Plan. The Committee shall have exclusive power, subject to the limitations contained in the Plan, to make
+Awards and to determine when and to whom Awards will be granted, and the form, amount and other terms and conditions of each Award, subject to the provisions of the Plan. The Committee shall have the authority to interpret the Plan and any
+Award made under the Plan, to establish, amend, waive and rescind any rules and regulations relating to the administration of the Plan, and to make all other determinations necessary or advisable for the administration of the Plan. The
+Committee may correct any defect, supply any omission or reconcile any inconsistency in the Plan or in any Award in the manner and to the extent it shall deem desirable. The determinations of the Committee in the administration of the Plan, as
+described herein, shall be final, binding and conclusive, subject to the provisions of the Plan. A majority of the members of the Committee shall constitute a quorum for any meeting of the Committee. 
+4.2 Indemnification. To the greatest extent permitted by law, (i) no member or former member of the
+Committee shall be liable for any action or determination taken or made in good faith with respect to the Plan or any Award made under the Plan, and (ii) the members or former members of the Committee shall be entitled to indemnification by the
+Company against and from any loss incurred by such members by reason of any such actions and determinations. 
+5. Effective Date
+of the Plan. The Plan as amended and restated effective June 4, 2012 shall become effective as of January 1, 2012; provided that the Plan as so amended and restated is approved by Crocs’s stockholders within 12 months
+of such date. The Plan shall remain in effect until it has been terminated pursuant to Section 8. 
+6. Right to
+Terminate Employment. Nothing in the Plan shall confer upon any Participant the right to continue in the employment of the Company or affect any right which the Company may have to terminate the employment of a Participant with or
+without cause. 
+7. Tax Withholding. The Company shall have the right to withhold from cash payments under the
+Plan to a Participant or other person an amount sufficient to cover any required withholding taxes. 
+A-3
+Table of Contents 
+8. Amendment, Modification and Termination of the Plan. The Board or Committee
+may at any time terminate, suspend or modify the Plan and the terms and provisions of any Award to any Participant which has not been paid. Amendments are subject to approval of Crocs’ stockholders only if such approval is necessary to maintain
+the Plan in compliance with the requirements of Section 162(m) of the Code, its successor provisions or any other applicable law or regulation. No Award may be granted during any suspension of the Plan or after its termination. 
+9. Unfunded Plan. The Plan shall be unfunded, and the Company shall not be required to segregate any assets that may at any
+time be represented by Awards under the Plan. No Participant shall, by virtue of the Plan, have any interest in any specific assets of the Company. 
+10. Other Benefit and Compensation Programs. Neither the adoption of the Plan by the Board nor its submission to the stockholders of the Company shall be construed as creating
+any limitation on the power of the Board or Committee to adopt such other incentive arrangements as it may deem appropriate. Payments received by a Participant under an Award made pursuant to the Plan shall not be deemed a part of a
+Participant’s regular recurring compensation for purposes of the termination, indemnity or severance pay law of any state and shall not be included in, nor have any effect on, the determination of benefits under any other employee benefit plan,
+contract or similar arrangement provided by the Company unless expressly so provided by such other plan, contract or arrangement, or unless the Committee expressly determines otherwise. 
+11. Executive Compensation Recovery Policy. For participants subject to the Company’s Recovery of Executive Compensation Policy (the “Policy”), all amounts
+earned under the Amended Plan are subject to the Policy, as in effect from time to time, a current copy of which may be requested from the Company at any time, and the terms and conditions of which are hereby incorporated by reference into the
+Amended Plan. 
+12. Governing Law. To the extent that Federal laws do not otherwise control, the Plan and all
+determinations made and actions taken pursuant to the Plan shall be governed by the laws of the State of Colorado and construed accordingly. 
+13. Other Provisions. 
+13.1 Non-transferability . Participants and beneficiaries shall not have the right to assign, pledge or otherwise dispose of any part of an Award under the Plan. 
+13.2 Termination of Employment . Except as otherwise provided in this section, no Award shall be paid to a
+Participant who is not actively employed by the Company as of the end of the applicable Performance Period. If a Participant’s employment with the Company ends during a Performance Period, the Committee may, in its discretion, determine
+that the Participant (or his or her beneficiaries) shall be paid a pro rata portion of the Award payment that the Participant would have received but for the fact that the Participant’s employment ended. Any such pro rated Award payment
+will be paid at the same time as other Award payments with respect to the applicable Performance Period. 
+A-4
+Table of Contents 
+Using a black ink pen, mark your votes with an X as shown in this example. Please do not write outside the designated areas. 
+x 
+Vote by mail 
+• 
+Mark, sign and vote your proxy card and return it in the postage-paid enevelope we provided or return it to Proxy Services c/o Computershare Investor
+Services, PO Box 43101, Providence, Rl 02440-5067 
+Electronic Voting Instructions 
+Available 24 hours a day, 7 days a week! 
+Instead of mailing your proxy, you may choose one of the voting methods outlined below to vote your proxy. 
+VALIDATION DETAILS ARE LOCATED BELOW IN THE TITLE BAR. 
+Proxies submitted by the
+Internet or telephone must be received by 1:00 a.m., Central Time, on June 4, 2012. 
+Vote by Internet 
+• Go to www.investorvote.com/crox 
+• Or scan the QR code with your smartphone 
+• Follow the steps outlined on the secure website 
+Vote by telephone 
+• Call toll free 1-800-652-VOTE (8683) within the USA US territories & Canada on a touch tone
+telephone 
+• Follow the instructions provided by the recorded message 
+q IF YOU HAVE NOT VOTED VIA THE INTERNET OR TELEPHONE, FOLD ALONG THE PERFORATION, DETACH AND RETURN THE BOTTOM PORTION IN THE ENCLOSED ENVELOPE. q 
+A 
+Proposals — The Board recommends a vote FOR all nominees, FOR Proposals 2, 3 and
+4. 
+1. 
+Election of Directors: 
+For 
+Withhold 
+For 
+Withhold 
+01 - Ronald L. Frasch 
+¨ 
+¨ 
+02 - W. Stephan Cannon 
+¨ 
+¨ 
+For 
+Against 
+Abstain 
+For 
+Against 
+Abstain 
+2. 
+Ratification of the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for fiscal year 2012. 
+¨ 
+¨ 
+¨ 
+3. 
+Approval of the amendment and restatement of our 2008 Cash Incentive Plan. 
+¨ 
+¨ 
+¨ 
+4. 
+An advisory vote to approve the compensation of our named executive officers. 
+¨ 
+¨ 
+¨ 
+Note : Such
+other business as may properly come before the meeting or any postponement or adjournment thereof. 
+B 
+Non-Voting Items 
+Change of Address — Please print your new address below. 
+Comments — Please print your comments below. 
+Meeting Attendance 
+Mark the box to the right if you plan to attend the Annual Meeting. 
+¨ 
+C 
+Authorized Signatures — This section must be completed for your vote to be counted. — Date and Sign Below 
+Please sign exactly as name(s) appears hereon. Joint owners should each sign. When signing as attorney, executor, administrator, corporate officer, trustee, guardian, or
+custodian, please give full title. 
+Date (mm/dd/yyyy) — Please print date below. 
+Signature 1 — Please keep signature within the box. 
+Signature 2 — Please keep signature within the box. 
+/ / 
+Table of Contents 
+Important notice regarding the internet availability of 
+proxy materials for the Annual Meeting of Stockholders. 
+The Notice and Proxy Statement and Annual Report, are available at: 
+www.edocumentview.com/crox 
+q 
+IF YOU HAVE NOT VOTED VIA THE INTERNET OR TELEPHONE, FOLD ALONG THE PERFORATION, DETACH AND RETURN THE BOTTOM PORTION IN THE ENCLOSED ENVELOPE.
+q 
+Proxy – Crocs, Inc. 
+Notice of 2012 Annual Meeting of Stockholders 
+St. Julien Hotel, 900 Walnut Street, Boulder, Colorado 
+Proxy Solicited by Board of Directors for Annual Meeting – June 4, 2012 
+John P. McCarvel and Daniel P. Hart, or any of them, each with the power of substitution, are hereby authorized to represent and vote the shares of
+the undersigned, with all the powers which the undersigned would possess if personally present, at the Annual Meeting of Stockholders of Crocs, Inc. to be held on June 4, 2012 or at any postponement or adjournment thereof. 
+Shares represented by this proxy will be voted by the
+stockholder. If no such directions are indicated, the Proxies will have authority to vote FOR all nominees, FOR Proposals 2, 3 and 4. 
+Please mark, sign, date and return this proxy card promptly using the enclosed reply envelope. 
+In their discretion, the Proxies are authorized to vote upon
+such other business as may properly come before the meeting. 
+(Items to be voted appear on reverse side.)
\ No newline at end of file
diff --git a/raw/proxies/0001334036/0001193125-12-157146/proxy_rpt.txt b/raw/proxies/0001334036/0001193125-12-157146/proxy_rpt.txt
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index 0000000000000000000000000000000000000000..9703a900fc4995e26ae349e7ed6f9582de181f65
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+++ b/raw/proxies/0001334036/0001193125-12-157146/proxy_rpt.txt
@@ -0,0 +1,18 @@
+CERTAIN RELATIONSHIPS AND RELATED PERSON TRANSACTIONS 
+Related Person Transactions 
+We had no
+transactions with related persons during 2011 which are required to be disclosed by the rules of the SEC. 
+Policy on Transactions with
+Related Persons 
+Our Code of Business Conduct and Ethics requires that any transaction involving us in which one of our directors,
+nominees for director, executive officers, or greater than five percent stockholders, or one of the aforementioned’s immediate family members (each, a “related person”), have a material interest be approved or ratified by the Audit
+Committee if the amount involved, when aggregated with the amount of all other transactions between the related person and us, exceeds $100,000 in a fiscal year. The full Board reviews ordinary course of business transactions in which directors have
+an interest as part of the Board’s annual director independence review, and our Code of Business Conduct and Ethics permits the full Board to waive any conflicts of interest between us and any director or officer. In determining whether to
+approve or ratify any such transaction, the Audit Committee must consider, in addition to other factors it deems appropriate, whether the transaction is on terms no less favorable to us than those involving unrelated parties. 
+Director and Officer Indemnification 
+We have entered into agreements to indemnify certain directors and executive officers in addition to the indemnification provided for in our certificate
+of incorporation and bylaws. These agreements, among other things, provide for indemnification of our directors and executive officers for certain expenses (including attorneys’ fees), judgments, fines and settlement amounts incurred by any
+such person in any action or proceeding, including any action by us or in our right, arising out of such person’s services as a director or executive officer of ours, any subsidiary of ours or any other company or enterprise to which the person
+provided services at our request. We believe that these provisions and agreements are necessary to attract and retain qualified persons as directors and executive officers. 
+15 
+Table of Contents
\ No newline at end of file